PART I
As of October 31, 2014, we own or have under contract 35.6 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capacity is used to supplement or replace regular pipeline supplies.
AsNatural Gas for Retail Distribution
Gas Utilities and Infrastructure is prevalent inresponsible for the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2014, the amountdistribution of natural gas to retail customers in storage varied from 10.4 million (one dekatherm equals 1,000,000 BTUs) to 24.2 million,its North Carolina, South Carolina, Tennessee, Ohio and the weighted average commodity cost of this gas in storage varied from $44.3 million to $97.5 million.
Natural gas developmentKentucky service territories. Gas Utilities and production in North America continues to provide abundant supply and price stability and moderation forInfrastructure’s natural gas as an energy commodity. With lower gas prices over the past seven years, we have been ableprocurement strategy is to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas component of customer rates in the three jurisdictions that we serve. Currently, natural gas has a price advantage over other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant sources of shale gas reserves.
We purchase our natural gas supplies by contractingcontract primarily with major and independent producers and marketers. Wemarketers for natural gas supply. It also purchasepurchases a diverse portfolio of transportation and storage servicesservice from interstate pipelines that are regulated by the FERC. Peak-use requirements are met through the use of company owned storage facilities, pipeline transportation capacity, purchased storage servicespipelines. This strategy allows Gas Utilities and other supply sources. We have been ableInfrastructure to obtain sufficient supplies ofassure reliable natural gas to meet customer requirements,supply and with the prospect of abundant domestic shale natural gas supplies and our contracted pipeline capacity, we believe that we will be able to meet our market demands in the future.
transportation for its firm customers during peak winter conditions. When firm pipeline services or contracted natural gas supplies are temporarily not needed due to market demand fluctuations, weGas Utilities and Infrastructure may release these services and supplies in the secondary market under FERC-approved capacity release provisions or make wholesale secondary market sales. The proceedsIn 2017, firm supply purchase commitment agreements provided 100 percent of the natural gas supply for Piedmont and 100 percent for Duke Energy Ohio.
Seasonality and the Impact of Weather
Gas Utilities and Infrastructure's costs and revenues are influenced by seasonal patterns due to peak natural gas sales occurring during the winter months. Residential customers are the most impacted by weather. There are certain regulatory mechanisms for the North Carolina, South Carolina and Tennessee service territories that normalize the margins collected from those transactionscertain customer classes during the winter, providing for an adjustment either up or down. In North Carolina, rate design provides protection from both weather and other usage variations such as conservation. In South Carolina and Tennessee, revenues are adjusted solely based on weather during the periods of November through March and October through April, respectively. Rate design for the Ohio service territory also mitigates the impacts of weather on customer bills. Estimated weather impacts are based on actual current period weather compared to normal weather conditions. Normal weather conditions are defined as the long-term average of actual historical weather conditions.
Degree-day data are used to reduceestimate energy required to maintain comfortable indoor temperatures based on each day’s average temperature. Heating-degree days measure the costvariation in weather based on the extent the average daily temperature falls below a base temperature. The methodology used to estimate the applicable impact of weather does not consider all variables that may impact customer response to weather conditions, such as wind chill. The precision of this estimate may also be impacted by applying long-term weather trends to shorter-term periods.
Competition
Gas Utilities and Infrastructure’s businesses operate as the sole supplier of natural gas we charge to customers through sharing mechanisms that are in place in all three jurisdictions whereby customers are allocated 75%within their retail service territories, with the exception of the savings through the incentive plans. For further information on these regulatory sharing mechanisms, see Note 2 to the consolidated financial statements in this Form 10-K.
We continue to diversify our supply portfolio by contracting to bring abundant and low costOhio, which has a competitive natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. In November 2012, we signed a long-term contract with Cabot Oil &market for distribution service. Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion projectUtilities and Infrastructure owns and operates facilities necessary to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus basedand distribute natural gas. These new supplyGas Utilities and capacity arrangements are scheduled to begin in late 2015,Infrastructure earns retail margin on the transmission and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas. Also, with the new ACP project that is targeted to be in service in late 2018, we will have additional pipeline capacity from the Marcellus and Utica supply basin under a long-term firm service agreement that we executed with ACP, subject to FERC approval of the project.
Competition
Our regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can lead to slower customer growth or customer conservation, or both, resulting in reduced gas purchases and customer billings. In turn, this can impact our capital expenditures and overall cash needs, including working capital needs. The direct use of natural gas in homes and businesses is the most efficient and cost effective usedistribution of natural gas and results in overall lower carbon emissions. However, the use of natural gas for power generation also adds significant value as a result of natural gas’ environmental attributes, competitive cost advantage and efficiency of delivery.
During the year ended October 31, 2014, approximately 4% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependentnot on relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of
the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of changes in oil and natural gas prices and the alternate fuel decisions made by industrial customers.
Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2014, no bypass occurred. The future level of bypass activity cannot be predicted.
Natural gas for power generation competes with other fuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as with industrial customers, we compete with other pipeline providers to serve the power generation plants.
Other
During the year ended October 31, 2014, our largest revenue generating customer contributed $89.2 million, or 6%, of total operating revenues. Our largest margin generating customer contributed $73.8 million, or 11% of total margin. Our largest revenue and margin generating customer is the same customer.
Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.
Compliance with federal, state and local environmental protection laws have had no material effect on our construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 in this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Costs incurred for natural gas, labor, employee benefits, consulting and construction are the business charges that we incur that are most significantly impacted by inflation. Changes to the cost of gasthe underlying commodity. Services are generally recovered through regulatory mechanisms and do not significantly impact net income. Labor and employee benefits are components ofpriced by state commission approved rates designed to include the cost of service, and construction costs less utility deferred income taxes are the primary components of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See discussion above for information on IMRs to track and recover certain capital costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a RSA mechanism that reduces regulatory lag to one year, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.
As of October 31, 2014, our fiscal year end, we had 1,879 employees compared with 1,795 as of October 31, 2013.
Our reports on Form 10-K, Form 10-Q and Form 8-K, and any amendments to these reports, are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.
Item 1A. Risk Factors
An overall economic downturn could negatively impact our earnings.
Any weakening of economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial assumptions, resulting in increased pension costs. The foregoing could negatively affect earnings and liquidity, reducing our ability to grow the business.
Increases in the wholesale price of natural gas could reduce our earnings and working capital.
A supply and demand imbalance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas; accordingly, restrictions or regulations on shale gas production could cause natural gas prices to increase. Additionally, the Commodity Futures Trading Commission (CFTC) under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has
regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. The prudently incurred cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are high, our working capital costs could increase due to higher carrying costs of gas storage inventories, adding further upward pressure on customer bills. Customers may have trouble paying those higher bills which may lead to bad debt expenses, ultimately reducing our earnings.
The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease.
We purchase almost all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to or reduction in that supply or interstate pipeline capacity due to events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.
Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.
Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. Our earnings could be negatively impacted if a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costsproviding these services and a reasonable return or significantly lowers our allowed return or negatively alters our cost allocation, rate design, cost trackers, including margin decouplingon invested capital. This regulatory policy is intended to provide safe and cost ofreliable natural gas or prohibits recovery of regulatory assets, including deferred gas costs.
service at fair prices.
In the normal course of business in the regulatory environment, assets are placed in service before rate cases can be filed that could result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we may suffer the negative financial effects of having placed in service assets that do not initially earn our authorized rate of return without the benefit of rate relief, which is commonly referred to as “regulatory lag.” Additionally, our capital investment in recent years has beenresidential, commercial and is projected to remain at higher levels, increasing the risk of cost recovery. All of this may negatively impact our results of operations and earnings.
Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various intervenors. State regulators have approved various mechanisms to stabilize our gas utility margin, including margin decoupling in North Carolina, rate stabilization in South Carolina, and uncollectible gas cost recovery in all states. State regulators have approved other margin stabilizing mechanisms that, for example, allow us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may otherwise directly accessindustrial customer markets, natural gas supply through their own connection to an interstate pipeline. If regulators decided to discontinue allowing us to use these tariff mechanisms, it would negatively impact our results ofdistribution operations financial condition and cash flows. In addition, regulatory authorities also review whether our gas costs are prudent and can disallow the recovery of a portion of our gas costs that we seek to recover from our customers, which would adversely impact earnings.
Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.
Our business is subject to competition that could negatively affect our results of operations.
The natural gas business is competitive, and we face competition fromcompete with other companies that supply energy, includingprimarily electric companies, oilpropane and propanefuel oil dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.
In residential, commercial Gas Utilities and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. OurInfrastructure's primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher natural gas costs, could cause these customers to suspend business operations or to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.
Higher natural gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business, and adversely affecting our earnings.
Pipeline and Storage Investments
Our business activitiesDuke Energy, through its Gas Utilities and Infrastructure segment, is a 47 percent equity member of Atlantic Coast Pipeline, LLC (ACP) that plans to build and own the proposed Atlantic Coast Pipeline (ACP Pipeline), an approximately 600-mile interstate natural gas pipeline, regulated by FERC. Prior to the Piedmont acquisition, Duke Energy owned a 40 percent equity ownership in ACP. The ACP pipeline is intended to transport diverse natural gas supplies into southeastern markets. Duke Energy Carolinas, Duke Energy Progress and Piedmont, among others, will be customers of the ACP pipeline. The targeted in-service date of the pipeline is late 2019.
Gas Utilities and Infrastructure also has a 7.5 percent equity ownership interest in Sabal Trail Transmission, LLC (Sabal Trail). Sabal Trail is a joint venture that owns a 515-mile natural gas pipeline (Sabal Trail pipeline) to transport natural gas to Florida, regulated by FERC. The Sabal Trail phase one mainline was placed into service in July 2017 and traverses Alabama, Georgia and Florida. A request to place in-service a lateral line to the Duke Energy Florida's Citrus County Combined Cycle facility is pending with FERC. Current legal challenges to the Sabal Trail pipeline are concentratedongoing, which may have an impact on continuing operations of the pipeline.
Gas Utilities and Infrastructure has a 24 percent equity ownership interest in three states.Constitution Pipeline Company, LLC (Constitution), an interstate pipeline development company formed to develop, construct, own and operate a 124-mile natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, regulated by FERC. As a result of permitting delays and project uncertainty, Constitution is unable to approximate an in-service date.
As a result of our assetsthe Piedmont acquisition, Duke Energy, through its Gas Utilities and 86% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers, including customers served by three North Carolina municipalities who are our wholesale customers, and most of our utility transmission and distribution pipelines areInfrastructure segment, has a 21.49 percent equity ownership interest in Cardinal Pipeline Company, LLC (Cardinal), an intrastate pipeline located in North Carolina regulated by the NCUC, a 45 percent equity ownership in Pine Needle LNG Company, LLC (Pine Needle), an interstate liquefied natural gas storage facility located in North Carolina and a 50 percent equity ownership interest in Hardy Storage Company, LLC (Hardy Storage), an underground interstate natural gas storage facility located in Hardy and Hampshire counties in West Virginia. Pine Needle and Hardy Storage are regulated by FERC.
KO Transmission Company (KO Transmission), a wholly owned subsidiary of Duke Energy Ohio, is an interstate pipeline company engaged in the business of transporting natural gas and is subject to the rules and regulations of FERC. KO Transmission's 90-mile pipeline supplies natural gas to Duke Energy Ohio and interconnects with the remainder locatedColumbia Gulf Transmission pipeline and Tennessee Gas Pipeline. An approximately 70-mile portion of KO Transmission's pipeline facilities is co-owned by Columbia Gas Transmission Corporation.
See Notes 4, 12 and 17 to the Consolidated Financial Statements, "Regulatory Matters," "Investments in Unconsolidated Affiliates" and "Variable Interest Entities," respectively, for further information on Duke Energy's pipeline investments.
Inventory
Gas Utilities and Infrastructure must maintain adequate natural gas inventory in order to provide reliable delivery to customers. As of December 31, 2017, the inventory balance for Gas Utilities and Infrastructure was $106 million. For more information on inventory, see Note 1 to the Consolidated Financial Statements, "Summary of Significant Accounting Policies."
Regulation
State
The NCUC, PSCSC, PUCO, TPUC and KPSC (collectively, the state gas utility commissions) approve rates for Duke Energy's retail natural gas service within their respective states. The state gas utility commissions, to varying degrees, have authority over the construction and operation of Gas Utilities and Infrastructure’s natural gas distribution facilities. Certificates of Public Convenience and Necessity or Certificates of Environmental Compatibility and Public Necessity issued by the state gas utility commissions or other government agencies, as applicable, authorize Gas Utilities and Infrastructure to construct and operate its natural gas distribution facilities and to sell natural gas to retail and wholesale customers. Prior approval from the relevant state gas utility commission is required for Gas Utilities and Infrastructure 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 a reasonable rate of return on its invested capital, including equity.
In addition to amounts collected from customers though approved base rates, each of the state gas utility commissions allow 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.
Natural gas costs are eligible for recovery by Gas Utilities and Infrastructure. Due to the associated regulatory treatment and the method allowed for recovery, changes in natural gas costs from year to year have no material impact on operating results of Gas Utilities and Infrastructure, unless a commission finds a portion of such costs to have not been prudent. However, delays between the expenditure for natural gas and recovery from customers can adversely impact the timing of cash flows of Gas Utilities and Infrastructure.
The following table summarizes certain components underlying recently approved and effective base rates or rate stabilization filings in the last three years. |
| | | | | | | | | | |
| | Annual |
| | Return |
| | Equity |
| | |
| | Increase |
| | on |
| | Component of |
| | |
| | (in millions) |
| | Equity |
| | Capital Structure |
| | Effective Date |
Piedmont 2016 South Carolina Rate Stabilization Adjustment Filing(a) | 8 |
| | 10.2 | % | | 53.0 | % | | November 2016 |
Piedmont 2017 South Carolina Rate Stabilization Adjustment Filing(a) | 6 |
| | 10.2 | % | | 53.0 | % | | November 2017 |
| |
| (a) | Under the rate stabilization adjustment mechanism, Piedmont resets rates in South Carolina based on updated costs and revenues on an annual basis. |
Gas Utilities and Infrastructure has integrity management rider (IMR) mechanisms in North Carolina and Tennessee designed to separately track and recover certain costs associated with capital investments incurred to comply with federal pipeline safety and integrity programs, as well as additional state safety and integrity requirements in Tennessee. ChangesThe following table summarizes information related to recently approved or pending IMR filings. |
| | | | | | | | | |
| | Cumulative |
| | Annual Margin |
| | Effective |
| (in millions) | Investment |
| | Revenues |
| | Date |
Piedmont 2017 IMR Filing – North Carolina(a) | $ | 738 |
| | $ | 77 |
| | December 2017 |
Piedmont 2016 IMR Filing – Tennessee(b) | 193 |
| | 23 |
| | January 2017 |
| | | | | | |
| Pending Filing: | | | | | Proposed Effective Date |
Piedmont 2017 IMR Filing – Tennessee(c) | $ | 231 |
| | $ | 23.4 |
| | January 2018 |
(a) Cumulative investment amounts through September 30, 2017.
(b) Cumulative investment amounts through October 31, 2016.
| |
| (c) | Cumulative investment amounts through October 31, 2017. A ruling from the TPUC is pending. |
For more information on rate matters and other regulatory proceedings, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”
Federal
Gas Utilities and Infrastructure is subject to various federal regulations, including regulations that are particular to the natural gas industry. These federal regulations include but are not limited to the following:
Regulations of the FERC affect the certification and siting of new interstate natural gas pipeline projects, the purchase and sale of, the prices paid for, and the terms and conditions of service for the interstate transportation and storage of natural gas.
Regulations of the PHMSA affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems.
Regulations of the EPA relate to the environment including proposed air emissions regulations that would expand to include emissions of methane. For a discussion of environmental regulation, see “Environmental Matters” in this section. Refer to “Other Matters” 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.
Regulations of FERC and the state gas utility commissions govern access to regulated natural gas and other data by nonregulated entities and services provided between regulated and nonregulated energy affiliates. These regulations affect the activities of nonregulated affiliates with Gas Utilities and Infrastructure.
COMMERCIAL RENEWABLES
Commercial Renewables primarily acquires, builds, develops and operates wind and solar renewable generation throughout the continental U.S. The portfolio includes nonregulated renewable energy and energy storage businesses.
Commercial Renewables' renewable energy includes utility-scale wind and solar generation assets, which total 2,907 MW across 14 states from 21 wind facilities and 63 solar facilities. Revenues are primarily generated by selling the power produced from renewable generation through long-term contracts to utilities, electric cooperatives, municipalities and commercial and industrial customers. In most instances, these customers have obligations under state-mandated renewable energy portfolio standards or similar state or local renewable energy goals. Energy and renewable energy credits generated by wind and solar projects are generally sold at contractual prices. In addition, as eligible wind and solar projects are placed in service, Commercial Renewables recognizes either investment tax credits (ITCs) when the renewable solar or wind project achieves commercial availability or production tax credits (PTC) as power is generated by wind projects over 10 years. Renewable ITCs are recognized over the useful life of the asset as a reduction to depreciation expense with the benefit of the tax basis adjustment due to the ITC recognized in income in the year of commercial availability.
As part of its growth strategy, Commercial Renewables has expanded its investment portfolio through the addition of distributed solar companies and projects, energy storage systems and energy management solutions specifically tailored to commercial businesses. These investments include the 2015 acquisition of a controlling interest in REC Solar Corp., a California-based provider of solar installations for retail, manufacturing, agriculture, technology, government and nonprofit customers across the U.S. and Phoenix Energy Technologies Inc., a California-based provider of enterprise energy management and information software to commercial businesses. In 2017, Duke Energy acquired the remaining interest in REC Solar.
For additional information on Commercial Renewables' generation facilities, see Item 2, “Properties.”
Regulation
Commercial Renewables is subject to regulation at the federal level, primarily from the FERC. Regulations of the FERC govern access to regulated market information by nonregulated entities and services provided between regulated and nonregulated utilities.
Market Environment and Competition
The market price of commodities and services, along with the quality and reliability of services provided, drive competition in the wholesale energy business. Commercial Renewables' main competitors include other nonregulated generators and wholesale power providers.
Sources of Electricity
Commercial Renewables relies on wind and solar resources for its generation of electric energy.
OTHER
The remainder of Duke Energy’s operations is presented as Other. While it is not an operating segment, Other primarily includes interest expense on holding company debt, unallocated corporate costs including costs to achieve strategic acquisitions, amounts related to certain companywide initiatives and contributions made to the Duke Energy Foundation. Other also includes Bison Insurance Company Limited (Bison) and an investment in NMC.
The Duke Energy Foundation is a nonprofit organization funded by Duke Energy shareholders that makes charitable contributions to selected nonprofits and government subdivisions.
Bison, a wholly owned subsidiary of Duke Energy, is a captive insurance company with the principal activity of providing Duke Energy subsidiaries with indemnification for financial losses primarily related to property, workers’ compensation and general liability.
NMC is a joint venture that operates in Jubail, Saudi Arabia, as a large regional economies, politics,producer of methanol and methyl tertiary butyl ether (MTBE), an additive to gasoline. In 2017, NMC produced approximately 934,000 metric tons of methanol and approximately 1,087,000 metric tons of MTBE. Approximately 40 percent of methanol is normally used in MTBE production. Upon the successful startup of NMC's polyacetal production facility during the fourth quarter of 2017, Duke Energy's ownership interest in NMC decreased from 25 percent to 17.5 percent. Duke Energy records the investment activity of NMC using the equity method of accounting and retains 25 percent of NMC's board of directors representation and voting rights.
Regulation
Certain entities within Other are subject to the jurisdiction of federal, state and local agencies.
Employees
On December 31, 2017, Duke Energy had a total of 29,060 employees on its payroll. The total includes 5,483 employees who are represented by labor unions under various collective bargaining agreements that generally cover wages, benefits, working practices, and other terms and conditions of employment.
Executive Officers of the Registrants
The following table sets forth the individuals who currently serve as executive officers. Executive officers serve until their successors are duly elected or appointed. |
| | | | | |
| Name | | Age(a) | | Current and Recent Positions Held |
| Lynn J. Good | | 58 |
| | Chairman, President and Chief Executive Officer. Ms. Good was elected as Chairman of the Board, effective January 1, 2016, and assumed her position as President and Chief Executive Officer in July 2013. Prior to that, she served as Executive Vice President and Chief Financial Officer since 2009. |
| Steven K. Young | | 59 |
| | Executive Vice President and Chief Financial Officer. Mr. Young assumed his current position in August 2013. Prior to that, he had served as Senior Vice President, Chief Accounting Officer and Controller since April 2006. |
| Douglas F Esamann | | 60 |
| | Executive Vice President, Energy Solutions and President, Midwest and Florida Regions. Mr. Esamann assumed his current position in September 2016 and was Executive Vice President and President, Midwest and Florida Regions since June 2015. Prior to that, he was President, Duke Energy Indiana since November 2010. |
| Lloyd M. Yates | | 57 |
| | Executive Vice President, Customer and Delivery Operations and President, Carolinas Region. Mr. Yates assumed his current position in September 2016 and was Executive Vice President, Market Solutions and President, Carolinas Region since August 2014. He held the position of Executive Vice President, Regulated Utilities from December 2012 to August 2014, and prior to that, had served as Executive Vice President, Customer Operations since July 2012, upon the merger of Duke Energy and Progress Energy. Prior to the merger, Mr. Yates was President and Chief Executive Officer of Progress Energy Carolinas, Inc., which is now known as Duke Energy Progress, LLC since July 2007. |
| Dhiaa M. Jamil | | 61 |
| | Executive Vice President and Chief Operating Officer. Mr. Jamil assumed the role of Chief Operating Officer in May 2016. Prior to his current position, he had held the title Executive Vice President and President, Regulated Generation and Transmission since June 2015. Prior to that, he had served as Executive Vice President and President, Regulated Generation since August 2014. He served as Executive Vice President and President of Duke Energy Nuclear from March 2013 to August 2014, and Chief Nuclear Officer from February 2008 to February 2013. He also served as Chief Generation Officer for Duke Energy from July 2009 to June 2012. |
| Franklin H. Yoho | | 58 |
| | Executive Vice President and President, Natural Gas. Mr. Yoho assumed his current position in October 2016 upon the acquisition of Piedmont by Duke Energy. Prior to this appointment, he served as Senior Vice President and Chief Commercial Officer of Piedmont since August 2011. Prior to that, he served as Senior Vice President, Commercial Operations since March 2002. |
| Julia S. Janson | | 53 |
| | Executive Vice President, External Affairs, Chief Legal Officer and Corporate Secretary. Ms. Janson assumed her current position in December 2012 and, in May 2017, assumed the responsibilities for the External Affairs and Strategic Policy organization. Prior to that, she had held the position of President of Duke Energy Ohio and Duke Energy Kentucky since 2008. |
| Melissa H. Anderson | | 53 |
| | Executive Vice President, Administration and Chief Human Resources Officer. Ms. Anderson assumed her position in May 2016 and had been Executive Vice President and Chief Human Resources Officer since January 2015. Prior to joining Duke Energy, she served as Senior Vice President of Human Resources at Domtar Inc. since 2010. |
| William E. Currens Jr. | | 48 |
| | Senior Vice President, Chief Accounting Officer and Controller. Mr. Currens assumed his current position in May 2016. Prior to that, he had held the position of Vice President, Investor Relations since 2009. |
(a) The ages of the officers provided are as of December 31, 2017.
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.
Environmental Matters
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. 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 (CWA), which requires permits for facilities that discharge wastewaters into navigable waters.
The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past 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 National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their permitting and licensing decisions, including siting approvals.
Coal Ash Act, as amended, which establishes requirements regarding the use and closure of existing ash basins, the disposal of ash at active coal plants and the handling of surface water and groundwater impacts from ash basins in North Carolina.
The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (RCRA), which creates a framework for the proper management of hazardous and nonhazardous solid waste; classifies CCR as nonhazardous waste; and establishes standards for landfill and surface impoundment placement, design, operation and closure, groundwater monitoring, corrective action, and post-closure care.
The Toxic Substances Control Act (TSCA), which gives EPA the authority to require reporting, recordkeeping and testing requirements, and to place restrictions relating to chemical substances and/or mixtures, including polychlorinated biphenyls.
For more information on environmental matters, see Notes 5 and 9 to the Consolidated Financial Statements, “Commitments and Contingencies – Environmental” and "Asset Retirement Obligations," respectively, and the “Other Matters” section of MD&A. Except as otherwise described in these sections, costs to comply with current federal, state and local provisions regulating the discharge of materials into the environment or other potential costs related to protecting the environment are incorporated into the routine cost structure of our various business segments and are 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.
The "Other Matters" section of MD&A includes an estimate of future capital expenditures required to comply with environmental regulations and weather patternsa discussion of Global Climate Change including the potential impact of current and future legislation related to greenhouse gas (GHG) emissions on the Duke Energy Registrants' operations. Recently passed and potential future environmental statutes 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 statutes and regulations become effective, the Duke Energy Registrants will seek appropriate regulatory recovery of costs to comply within its regulated operations.
Duke Energy Carolinas is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Carolinas’ service area covers approximately 24,000 square miles and supplies electric service to 2.5 million residential, commercial and industrial customers. For information about Duke Energy Carolinas’ generating facilities, see Item 2, “Properties.” Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.
Substantially all of Duke Energy Carolinas' operations are regulated and qualify for regulatory accounting. Duke Energy Carolinas operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Progress Energy is a public utility holding company primarily engaged in the regulated electric utility business and is subject to regulation by the FERC. Progress Energy conducts operations through its wholly owned subsidiaries, Duke Energy Progress and Duke Energy Florida. When discussing Progress Energy’s financial information, it necessarily includes the results of Duke Energy Progress and Duke Energy Florida.
Substantially all of Progress Energy’s operations are regulated and qualify for regulatory accounting. Progress Energy operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Duke Energy Progress is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Progress’ service area covers approximately 32,000 square miles and supplies electric service to approximately 1.5 million residential, commercial and industrial customers. For information about Duke Energy Progress’ generating facilities, see Item 2, “Properties.” Duke Energy Progress is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.
Substantially all of Duke Energy Progress’ operations are regulated and qualify for regulatory accounting. Duke Energy Progress operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Duke Energy Florida is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. Duke Energy Florida’s service area covers approximately 13,000 square miles and supplies electric service to approximately 1.8 million residential, commercial and industrial customers. For information about Duke Energy Florida’s generating facilities, see Item 2, “Properties.” Duke Energy Florida is subject to the regulatory provisions of the FPSC, NRC and FERC.
Substantially all of Duke Energy Florida’s operations are regulated and qualify for regulatory accounting. Duke Energy Florida operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Duke Energy Ohio is a regulated public utility primarily engaged in the transmission and distribution of electricity in portions of Ohio and Kentucky, in the generation and sale of electricity in portions of Kentucky and the transportation and sale of natural gas in portions of Ohio and Kentucky. Duke Energy Ohio also conducts competitive auctions for retail electricity supply in Ohio whereby recovery of the energy price is from retail customers. Operations in Kentucky are conducted through its wholly owned subsidiary, Duke Energy Kentucky, Inc. (Duke Energy Kentucky). References herein to Duke Energy Ohio include Duke Energy Ohio and its subsidiaries, unless otherwise noted. Duke Energy Ohio is subject to the regulatory provisions of the PUCO, KPSC and FERC.
Duke Energy Ohio’s service area covers approximately 3,000 square miles and supplies electric service to approximately 850,000 residential, commercial and industrial customers and provides transmission and distribution services for natural gas to approximately 529,000 customers. For information about Duke Energy Ohio's generating facilities, see Item 2, “Properties.”
KO Transmission, a wholly owned subsidiary of Duke Energy Ohio, is an interstate pipeline company engaged in the business of transporting natural gas and is subject to the rules and regulations of FERC. KO Transmission's 90-mile pipeline supplies natural gas to Duke Energy Ohio and interconnects with the Columbia Gulf Transmission pipeline and Tennessee Gas Pipeline. An approximately 70-mile portion of KO Transmission's pipeline facilities is co-owned by Columbia Gas Transmission Corporation.
On April 2, 2015, Duke Energy completed the sale of its nonregulated Midwest generation business, which sold power into wholesale energy markets, to a subsidiary of Dynegy. For further information about the sale of the Midwest Generation business, refer to Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions."
Substantially all of Duke Energy Ohio's operations that remain after the sale qualify for regulatory accounting.
Business Segments
Duke Energy Ohio has two reportable operating segments, Electric Utilities and Infrastructure and Gas Utilities and Infrastructure. For additional information on these business segments, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Duke Energy Indiana is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Indiana. Duke Energy Indiana’s service area covers 23,000 square miles and supplies electric service to 820,000 residential, commercial and industrial customers. See Item 2, “Properties” for further discussion of Duke Energy Indiana’s generating facilities, transmission and distribution. Duke Energy Indiana is subject to the regulatory provisions of the IURC and FERC.
Substantially all of Duke Energy Indiana’s operations are regulated and qualify for regulatory accounting. Duke Energy Indiana operates one reportable business segment, Electric Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
Piedmont is a regulated public utility primarily engaged in the distribution of natural gas to over 1 million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are wholesale customers. Piedmont is subject to the regulatory provisions of the NCUC, PSCSC, TPUC and FERC.
Substantially all of Piedmont’s operations are regulated and qualify for regulatory accounting. Piedmont operates one reportable business segment, Gas Utilities and Infrastructure. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”
In addition to other disclosures within this Form 10-K, including "Management's Discussion and Analysis of Financial Condition and Results of Operations – Matters Impacting Future Results" for each registrant in Item 7, and other documents filed with the SEC from time to time, the following factors should be considered in evaluating Duke Energy and its subsidiaries. Such factors could affect actual results of operations and cause results to differ substantially from those currently expected or sought. Unless otherwise indicated, risk factors discussed below generally relate to risks associated with all of the Duke Energy Registrants. Risks identified at the Subsidiary Registrant level are generally applicable to Duke Energy.
Business Strategy Risks
Duke Energy’s future results could be adversely affected if it is unable to implement its business strategy.
Duke Energy’s future results of operations depend, in significant part, on the extent to which it can implement its business strategy successfully. Duke Energy's strategy, including transforming the customer experience, modernizing the energy grid, generating cleaner energy, expansion of natural gas infrastructure, modernizing the regulatory construct and engaging employees and stakeholders to accomplish these priorities, is subject to business, economic and competitive uncertainties and contingencies, many of which are beyond its control. As a consequence, Duke Energy may not be able to fully implement or realize the anticipated results of its strategy.
Regulatory, Legislative and Legal Risks
The Duke Energy Registrants’ regulated utility revenues, earnings and results are dependent on state legislation and regulation that affect electric generation, electric and natural gas transmission, distribution and related activities, which may limit their ability to recover costs.
The Duke Energy Registrants’ regulated electric and natural gas utility businesses are regulated on a cost-of-service/rate-of-return basis subject to statutes and regulatory commission rules and procedures of North Carolina, South Carolina, Florida, Ohio, Tennessee, Indiana and Kentucky. If the Duke Energy Registrants’ regulated utility earnings exceed the returns established by the state utility commissions, retail electric and natural gas rates may be subject to review and possible reduction by the commissions, which may decrease the Duke Energy Registrants’ future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, the Duke Energy Registrants’ future earnings could be negatively impacted.
If legislative and regulatory structures were to evolve in such a way that the Duke Energy Registrants’ exclusive rights to serve their regulated customers were eroded, their future earnings could be negatively impacted. Federal and state regulations, laws and other efforts designed to promote and expand the use of energy efficiency measures and distributed generation technologies, such as private solar and battery storage, in Duke Energy service territories could result in customers leaving the electric distribution system and an increase in customer net energy metering, which allows customers with private solar to receive bill credits for surplus power at the full retail amount. Over time, customer adoption of these technologies and increased energy efficiency could result in excess generation resources as well as stranded costs if Duke Energy is not able to fully recover the costs and investment in generation.
State regulators have approved various mechanisms to stabilize natural gas utility margins, including margin decoupling in North Carolina, rate stabilization in South Carolina and uncollectible natural gas cost recovery in all states. State regulators have approved other margin stabilizing mechanisms that, for example, allow for recovery of margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may otherwise directly access natural gas supply through their own connection to an interstate pipeline. If regulators decided to discontinue the Duke Energy Registrants' use of tariff mechanisms, it would negatively impact the growth opportunities available to us and the usage patterns andresults of operations, financial condition and cash flows. In addition, regulatory authorities also review whether natural gas costs are prudent and can disallow the recovery of a portion of natural gas costs that the Duke Energy Registrants seek to recover from customers, which would adversely impact earnings.
The rates that the Duke Energy Registrants’ regulated utility businesses are allowed to charge are established by state utility commissions in rate case proceedings, which may limit their ability to recover costs and earn an appropriate return on investment.
The rates that the Duke Energy Registrants’ regulated utility business are allowed to charge significantly influences the results of operations, financial position and liquidity of the Duke Energy Registrants. The regulation of the rates that the regulated utility businesses charge customers is determined, in large part, by state utility commissions in rate case proceedings. Negative decisions made by these regulators could have a material adverse effect on the Duke Energy Registrants’ results of operations, financial position or liquidity and affect the ability of the Duke Energy Registrants to recover costs and an appropriate return on the significant infrastructure investments being made. Duke Energy cannot predict the outcome of these rate case proceedings.
Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect our earnings.the Duke Energy Registrants’ financial position, results of operations or cash flows and their utility businesses.
Increased competition resulting from deregulation or restructuring legislation could have a significant adverse impact on the Duke Energy Registrants’ results of operations, financial position or cash flows. Retail competition and the unbundling of regulated electric service could have a significant adverse financial impact on the Duke Energy Registrants due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. The Duke Energy Registrants cannot predict the extent and timing of entry by additional competitors into the electric markets. The Duke Energy Registrants cannot predict if or when they will be subject to changes in legislation or regulation, nor can they predict the impact of these changes on their financial position, results of operations or cash flows.
The Duke Energy Registrants’ businesses are subject to newextensive federal regulation and existinga wide variety of laws and regulationsgovernmental policies, including taxes, that may require significant expenditures, significantly increase operatingchange over time in ways that affect operations and costs.
Duke Energy is subject to regulations under a wide variety of U.S. federal and state regulations and policies. There can be no assurance that laws, regulations and policies will not be changed in ways that result in material modifications of business models and objectives or affect returns on investment by restricting activities and products, subjecting them to escalating costs or significant finesprohibiting them outright.
On December 22, 2017, President Trump signed the Tax Cuts and Jobs Acts (the Tax Act) into law which, among other provisions, reduces the maximum federal corporate income tax rate from 35 percent to 21 percent and limits interest deductions outside of regulated utility operations effective January 1, 2018. The resulting revaluation of existing deferred tax assets and liabilities to the lower federal corporate tax rate were recognized in Duke Energy’s December 31, 2017, financial statements. Guidance issued by the SEC indicates that additional adjustments for items that were estimated may be recorded during 2018 if new information becomes available. The Tax Act also could be amended or penalties for noncompliance.subject to technical correction, which could change the financial impacts that were recorded at December 31, 2017, or are expected to be recorded in future periods. The FERC and state utility commissions will determine the regulatory treatment of the impacts of the Tax Act. Duke Energy’s future results of operations, financial condition and cash flows could be adversely impacted by the Tax Act, subsequent amendments or corrections, or the actions of the FERC, state utility commissions or credit rating agencies related to the Tax Act.
Our business and operationsThe Duke Energy Registrants are subject to regulation by FERC, NRC, EPA and various other federal agencies as well as the FERC,North American Electric Reliability Corporation. Regulation affects almost every aspect of the NCUC,Duke Energy Registrants’ businesses, including, among other things, their ability to: take fundamental business management actions; determine the PSCSC,terms and rates of transmission and distribution services; make acquisitions; issue equity or debt securities; engage in transactions with other subsidiaries and affiliates; and pay dividends upstream to the TRA,Duke Energy Registrants. Changes to federal regulations are continuous and ongoing. The Duke Energy Registrants cannot predict the DOT,future course of regulatory changes or the EPA,ultimate effect those changes will have on their businesses. However, changes in regulation can cause delays in or affect business planning and transactions and can substantially increase the CFTC and other agencies, and weDuke Energy Registrants’ costs.
The Duke Energy Registrants are subject to numerous federal and state laws and regulations. Compliance with existing or newenvironmental laws and regulations requiring significant capital expenditures that can increase the cost of operations, and which may impact or limit business plans, or cause exposure to environmental liabilities.
The Duke Energy Registrants are subject to numerous environmental laws and regulations affecting many aspects of their present and future operations, including CCRs, air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs which may not be recoverable in rates from our customers. For example, while we have implemented an IMR mechanism in North Carolina and Tennessee to recover certain capital expenditures made in compliance with federal and state safety and integrity management laws or regulations, there is a risk that the relevant regulators will disallow some of the expenditures under the IMR mechanism, and that the costs expended in compliance with such laws would not be recoverable through such rate mechanisms (but rather through general rate cases with extended lag). Because the language in somecosts. These laws and regulations is not prescriptive, there isgenerally require the Duke Energy Registrants to obtain and comply with a risk that our interpretationwide variety of theseenvironmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may not be consistentcan require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with expectations of regulators. Any compliance failure related to these laws andenvironmental regulations may result in the imposition of fines, penalties orand injunctive measures affecting operating assets. For example, underThe steps the Duke Energy Policy ActRegistrants could be required to take to ensure their facilities are in compliance could be prohibitively expensive. As a result, the Duke Energy Registrants may be required to shut down or alter the operation of 2005,their facilities, which may cause the FERC has civil penalty authority underDuke Energy Registrants to incur losses. Further, the Natural Gas ActDuke Energy Registrants may not be successful in recovering capital and operating costs incurred to impose penaltiescomply with new environmental regulations through existing regulatory rate structures and their contracts with customers. Also, the Duke Energy Registrants may not be able to obtain or maintain from time to time all required environmental regulatory approvals for current violations of uptheir operating assets or development projects. Delays in obtaining any required environmental regulatory approvals, failure to $1 million per day for each violation. As the regulatory environment for our industry increasesobtain and comply with them or changes in complexity, the risk of inadvertent noncompliance could also increase. All of these eventsenvironmental 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 to comply with current environmental regulations will have a material adverse effect on our business,the Duke Energy Registrants’ financial position, results of operations or cash flows due to regulatory cost recovery, the Duke Energy Registrants are at risk that the costs of complying with environmental regulations in the future will have such an effect.
The EPA has recently enacted or proposed new federal regulations governing the management of cooling water intake structures, wastewater and CO2 emissions. These regulations may require the Duke Energy Registrants to make additional capital expenditures and increase operating and maintenance costs.
The Duke Energy Registrants' operations, capital expenditures and financial condition.results may be affected by regulatory changes related to the impacts of global climate change.
There is continued concern, both nationally and internationally, about climate change. The EPA may adopt and implement regulations to restrict emissions of GHGs. Increased regulation of GHG emissions could impose significant additional costs on the Duke Energy Registrants' operations, their suppliers and customers. Regulatory changes could also result in generation facilities to be retired early and result in stranded costs if Duke Energy is not able to fully recover the costs and investment in generation. At this time, the effect that climate change regulation may have in the future on Duke Energy's business, financial condition or results of operations is not able to be predicted.
Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.
The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide and air emissions regulations that could be expanded to address emissions of methane. Such laws or regulations could impose costs tied to carbon emissions, operational
requirementsOperational Risks
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 restrictions,sluggishness in the economy generally affect the markets in which the Duke Energy Registrants operate and negatively influence operations. Declines in demand for electricity or additional charges to fund energy efficiency activities. They could also providenatural gas as a cost advantage to alternative energy sources, impose costs or restrictions on end usersresult of economic downturns in the Duke Energy Registrants’ regulated service territories will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and the use of natural gas. Although the Duke Energy Registrants’ regulated electric and natural gas or result in otherbusinesses are subject to regulated allowable rates of return and recovery of certain costs, or requirements, such as fuel and purchased natural gas costs, associated with the adoptionunder periodic adjustment clauses, overall declines in electricity or natural gas sold as a result of new infrastructureeconomic downturn or recession could reduce revenues and technology to respond to new mandates. The focus on climate change couldcash flows, thereby diminishing results of operations. Additionally, prolonged economic downturns that negatively impact the reputation of fossil fuel products or services. The occurrence of these events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.
Weather conditions may cause our earnings to vary from year to year.
Our earnings can vary from year to year, depending in part on weather conditions. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms and rate design that normalize the margin we collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. If our rates and tariffs are modified to eliminate weather protection provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather. Additionally, our weather normalization mechanisms do not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of these events, ourDuke Energy Registrants’ results of operations and earningscash flows could vary and be negatively impacted.
result in future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values.
The operationDuke 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 ourreturn 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, thereby diminishing results of operations.
Factors that could impact sales volumes, generation of electricity and market prices at which the Duke Energy Registrants are able to sell electricity and natural gas distribution and transmission activities may be interrupted by accidents, work stoppage, severe are as follows:
weather conditions, including destructiveabnormally mild winter or summer weather patterns,that cause lower energy or natural gas usage for heating or cooling purposes, as applicable, and periods of low rainfall that decrease the ability to operate facilities in an economical manner;
supply of and demand for energy commodities;
transmission or transportation constraints or inefficiencies that impact nonregulated energy operations;
availability of competitively priced alternative energy sources, which are preferred by some customers over electricity produced from coal, nuclear or natural gas plants, and customer usage of energy-efficient equipment that reduces energy demand;
natural gas, crude oil and refined products production levels and prices;
ability to procure satisfactory levels of inventory, such as hurricanes, tornadoes and floods, pandemic or acts of terrorism and sabotage.
Inherent in our gas distribution and transmission activities, includingcoal, natural gas and LNG storage, are a varietyuranium; and
capacity and transmission service into, or out of, hazardsthe Duke Energy Registrants’ markets.
Natural disasters or operational accidents may adversely affect the Duke Energy Registrants’ operating results.
Natural disasters (such as electromagnetic events or the 2011 earthquake and tsunami in Japan) or other operational risks, suchaccidents within the company or industry (such as third-party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions,the San Bruno, California natural gas transmission pipeline failure) could have direct significant impacts on the Duke Energy Registrants as well as acts of terrorismon key contractors and sabotage,suppliers. Such events could also damage our pipelinesindirectly impact the Duke Energy Registrants through changes to policies, laws and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result inregulations whose compliance costs have a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If these events are severe enough or if they lead to operational interruptions, they could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental damage, impairment of our operations and substantial loss to us. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering places, could increaseimpact on the level of damages resulting from these risks. Our regulators may not allow us to recover part or all of the increased cost related to the foregoing events from our customers, which would negatively affect our earnings. The occurrence of any of these events could adversely affect ourDuke Energy Registrants’ financial position, results of operations and cash flows.
The reputation and financial condition of the Duke Energy Registrants could be negatively impacted due to their obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, remediation, disposal and monitoring relating to CCR, the high costs and new rate impacts associated with implementing these new CCR-related requirements and the strategies and methods necessary to implement these requirements in compliance with these legal obligations.
As a result of electricity produced for decades at coal-fired power plants, the Duke Energy Registrants manage large amounts of CCR that are primarily stored in dry storage within landfills or combined with water in other surface impoundments, all in compliance with applicable regulatory requirements. However, the potential exists for another CCR-related incident, such as the one that occurred during the 2014 Dan River Steam Station ash basin release, that could raise environmental or general public health concerns. Such a CCR-related incident could have a material adverse impact on the reputation and financial condition of the Duke Energy Registrants.
During 2015, EPA regulations were enacted related to the management of CCR from power plants. These regulations classify CCR as nonhazardous waste under the RCRA and apply to electric generating sites with new and existing landfills, new and existing surface impoundments, structural fills and CCR piles, and establishes requirements regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring, protection and remedial procedures and other operational and reporting procedures for the disposal and management of CCR. In addition to the federal regulations, CCR landfills and surface impoundments will continue to be independently regulated by existing state laws, regulations and permits, as well as additional legal requirements that may be imposed in the future. These federal and state laws, regulations and other legal requirements may require or result in additional expenditures, increased operating and maintenance costs and/or result in closure of certain power generating facilities, which could affect the financial position, results of operations and cash flows of the Duke Energy Registrants. The Duke Energy Registrants intend to seek full cost recovery for expenditures through the normal ratemaking process with state and federal utility commissions, who permit recovery in rates of necessary and prudently incurred costs associated with the Duke Energy Registrants’ regulated operations, and through other wholesale contracts with terms that contemplate recovery of such costs, although there is no guarantee of full cost recovery. In addition, the timing for recovery of such costs could have a material adverse impact on Duke Energy's cash flows.
The Duke Energy Registrants have recognized significant asset retirement obligations related to these CCR-related requirements. Closure activities began in 2015 at the four sites specified as high priority by the Coal Ash Act and at the W.S. Lee Steam Station site in South Carolina in connection with other legal requirements. Excavation at these sites involves movement of large amounts of CCR materials to off-site locations for use as structural fill, to appropriate engineered off-site or on-site lined landfills or conversion of the ash for beneficial use. At other sites, preliminary planning and closure methods have been studied and factored into the estimated retirement and management costs. The Coal Ash Act requires CCR surface impoundments in North Carolina to be closed, with the closure method and timing based on a risk ranking classification determined by legislation or state regulators. Additionally, the RCRA required closure timing depends upon meeting or continuing to meet certain criteria. As the closure and CCR management work progresses and final closure plans and corrective action measures are developed and approved at each site, the scope and complexity of work and the amount of CCR material could be greater than estimates and could, therefore, materially increase compliance expenditures and rate impacts.
The Duke Energy Registrants’ financial position, results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, or decline in customer demand or number of customers.
Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas and the need for additional power generation and delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of the Duke Energy Registrants, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.
Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.
Advances in distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production utilized by the Duke Energy Registrants.
Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or number of customers and may cause the failure of the Duke Energy Registrants to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on their financial position, results of operations and cash flows.
Furthermore, the Duke Energy Registrants currently have energy efficiency riders in place to recover the cost of energy efficiency programs in North Carolina, South Carolina, Florida, Indiana, Ohio and Kentucky. Should the Duke Energy Registrants be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact.
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, including extreme weather conditions associated with climate change.
Electric power generation and natural gas distribution are generally seasonal businesses. In most parts of the U.S., the demand for power peaks during the warmer summer months, with market prices also typically peaking at that time. In other areas, demand for power peaks during the winter. Demand for natural gas peaks during the winter months. Further, extreme weather conditions such as heat waves, winter storms and severe weather associated with climate change could cause these seasonal fluctuations to be more pronounced. As a result, 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 hydroelectric plants, as well as 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 cost of storm restoration efforts may not be ablefully recoverable through the regulatory process.
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. The FERC’s power transmission regulations 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 growth and performance in these regions. In addition, the ISOs 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.
Duke Energy may be unable to complete necessary or desirable pipeline expansion or infrastructure development or maintenance projects, which may delay or prevent usthe Duke Energy Registrants from serving ournatural gas customers or expanding ourthe natural gas business.
In order to serve current or new natural gas customers or expand ourthe service to existing customers, wethe Duke Energy Registrants need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Duke Energy Registrants have made significant investments in a number of pipeline development projects, which are being operated and constructed by third party joint venture partners. Various factors, may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project,projects, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns and the inability to negotiate acceptable agreements relating to rights-of-way,rights of way, construction or other material development components.components, may prevent or delay the completion of projects or increase costs. As a result, wethe Duke Energy Registrants may not be ableunable to adequately serve existing natural gas customers or support customer growth or could result inincur higher than anticipated cost, bothcosts, which could have a negative financial impact.
The availability of which wouldadequate interstate pipeline transportation capacity and natural gas supply may decrease.
The Duke Energy Registrants purchase almost all of their natural gas supply from interstate sources that must be transported to the applicable service territories. Interstate pipeline companies transport the natural gas to the Duke Energy Registrants' systems under firm service agreements that are designed to meet the requirements of their core markets. A significant disruption to interstate pipelines capacity or reduction in natural gas supply due to events including, but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyberattacks or other acts of war or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce the normal interstate supply of natural gas and thereby reduce earnings. Moreover, if additional natural gas infrastructure, including, but not limited to, exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then growth opportunities could be limited and earnings 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 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 are exposed to risk that counterparties will not be able to fulfill their obligations. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events or environmental regulations affecting any of these fuel suppliers, could limit the Duke Energy Registrants' ability to operate their facilities. 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 earnings.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.
Potential terrorist activities, or military or other actions, 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 effects in ways the Duke Energy Registrants cannot predict at this time. In addition, future acts of terrorism and possible reprisals as a consequence of action by the U.S. and its allies could be directed against companies operating in the U.S. Information technology systems, transmission and distribution and generation facilities such as 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 information technology systems, transmission and distribution and generation facilities, including nuclear power plants under the NRC’s design basis threat requirements. These increased costs could include additional physical plant security and security personnel or additional capability following a terrorist incident.
Cyberattacks and data security breaches could adversely affect the Duke Energy Registrants' businesses.
Information security risks have generally increased in recent years as a result of the proliferation of new technologies and the increased sophistication and frequency of cyberattacks and data security breaches. The utility industry requires the continued operation of sophisticated information technology systems and network infrastructure, which are part of an interconnected regional grid. Additionally, connectivity to the internet continues to increase through smart grid and other initiatives. Because of the critical nature of the infrastructure, increased connectivity to the internet and technology systems’ inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism or other types of data security breaches, the Duke Energy Registrants face a heightened risk of cyberattack. In the event of such an attack, the Duke Energy Registrants could (i) have business operations disrupted, property damaged, customer information stolen and other private information accessed, (ii) experience substantial loss of revenues, repair and restoration costs, implementation costs for additional security measures to avert future cyberattacks and other financial loss and (iii) be subject to increased regulation, litigation and reputational damage.
Elevated levels of capital expenditures may weaken our financial position and inhibit customer growth.27
We makeFailure 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 increase. Failure to hire and adequately train replacement employees, including the transfer of significant annual capital expenditures for system integrity, infrastructureinternal historical knowledge and maintenance that do not immediately produce revenue. We haveexpertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If the Duke Energy Registrants are unable to successfully attract and retain an appropriately qualified workforce, their financial position, results of operations or cash flows could be negatively affected.
The costs of retiring Duke Energy Florida’s Crystal River Unit 3 could prove to be more extensive than is currently identified.
Costs 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 Duke Energy Florida’s financial condition, results of operations and cash flows.
Duke Energy Ohio’s and Duke Energy Indiana’s membership in an RTO presents risks that could have a material adverse effect on their results of operations, financial condition and cash flows.
The rules governing the various regional power markets may 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 have 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.
As 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.
The Duke Energy Registrants may not recover costs incurred to begin construction on projects that are canceled.
Duke Energy’s long-term strategy requires the construction of new projects, either wholly owned or partially owned, which involve a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs. To limit the risks of these construction projects, the Duke Energy Registrants enter into equipment purchase orders and construction contracts and incur engineering and design service costs either through general rate cases in advance of receiving necessary regulatory approvals and/or alternative rate mechanisms approvedsiting or environmental permits. If any of these projects are canceled for any reason, including failure to receive necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.
Nuclear Generation Risks
Duke Energy Carolinas, Duke Energy Progress and Duke 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 stateDuke Energy Carolinas, Duke Energy Progress and Duke 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 current or past 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 commissions,oversight, impose fines 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 the control of Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, such as RSAsa serious nuclear incident at a facility owned by a third party, could necessitate substantial capital and IMRs, that periodically adjust ratesother expenditures, as well as assessments to reflect incurred capital expenditures. However, before rates are adjusted, we fund construction through operatingcover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on the results of operations, financial condition, cash flows and by accessing short- and long-term capital markets and as a result, we may experience reduced liquidity and deteriorating credit metrics, which may weaken our financial position and could trigger a possible downgrade fromreputation of the rating agencies. In addition, after these capital costs are reflected in rates, to the extent that rates rise considerably, customers may choose alternative forms of energy to meet their needs. This would reduce our customer growth, which would weaken our financial position by reducing earnings and cash flows.Duke Energy Registrants.
A downgrade in our credit ratingsLiquidity, Capital Requirements and Common Stock Risks
The Duke Energy Registrants rely on access to short-term borrowings and longer-term debt and equity 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 significantly financed through issuances of debt and equity. 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 flows from their operations and to fund investments originally financed through debt instruments with disparate maturities, the Duke Energy Registrants rely on access to short-term money markets as well as longer-term capital markets. The Subsidiary Registrants also rely on access to short-term intercompany borrowings. If the Duke Energy Registrants are not able to access debt or equity at competitive rates or at all, the ability to finance their operations and implement their strategy and business plan as scheduled could negatively affect ourbe adversely affected. An inability to access debt and equity 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 cost of andborrowing or adversely affect the ability to access capital.one or more financial markets. Such disruptions could include: economic downturns, the bankruptcy of an unrelated energy company, unfavorable capital market conditions, market prices for electricity and natural gas, actual or threatened terrorist attacks, or the overall health of the energy industry. The availability of credit under Duke Energy’s Master Credit Facility depends upon the ability of the banks providing commitments under the facility 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 a revolving credit facility to provide backup for its commercial paper program and letters of credit to support variable rate demand tax-exempt bonds that may be put to the Duke Energy Registrant issuer at the option of the holder. The facility includes borrowing sublimits for the Duke Energy Registrants, each of whom is a party to the credit facility, 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 Master Credit Facility.
Our ability to obtain adequateThe Duke Energy Registrants must meet credit quality standards and cost effective financing depends in part on ourthere is no assurance they will maintain investment grade credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-gradeIf the Duke Energy Registrants 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’ senior long-term debt issuances is currently rated investment grade by ourvarious rating agencies. The Duke Energy Registrants cannot ensure their senior long-term debt will be rated investment grade in the future.
If the rating agencies particularlywere to rate the Duke Energy Registrants below investment grade, borrowing costs would increase, perhaps significantly. In addition, the potential pool of investors and funding sources would likely decrease. Further, if the short-term debt rating were to fall, access to the commercial paper market could be significantly limited.
A downgrade below investment grade could adversely affect our costsalso require the posting of borrowing and/additional collateral in the form of letters of credit or access to sources of liquiditycash under various credit, commodity and capital. Such a downgrade could further limit our access to private credit marketscapacity agreements and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, thetrigger termination clauses in some interest rate on our borrowings under our revolving credit agreement and commercial paper (CP) program, as well as on any future public or private debt issuances, would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.
We may be unable to access capital or the cost of capital may significantly increase.
Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets or waning investor sentiment could adversely affect our ability to access short-term and long-term capital. Our access to funds under our CP program is dependent on investor demand for our commercial paper. Disruptions and volatility in the global credit markets could limit the demand for our commercial paper or result in the need to offer higher interest rates to investors,derivative agreements, which would result in higher expense and could adversely impact liquidity. Tax rates on dividends may increase, which could increase the cost of equity. The inability to access adequate capital or the increase in cost of capital may require us to conserve cash prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.
Changes in federal and/or state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash flows.
Changes in federal and/or state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers. These events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flows. Anypayments. All of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to growwould likely reduce the business or require us to reduce or eliminate the dividend or other discretionary uses of cash,Duke Energy Registrants’ liquidity and profitability and could negatively affect earnings.
We do not generate sufficient cash flows to meet all our cash needs.
We have made, and expect to continue to make, large capital expenditures in order to finance the expansion, upgrading and maintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our dependencymaterial effect on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.
The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in
default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.
We are exposed to credit risk of counterparties with whom we do business.
Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.
Non-compliance with debt covenants or conditions could adversely affect the Duke Energy Registrants’ ability to execute future borrowings.
The costDuke Energy Registrants’ debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of providing pension benefitsthe agreements.
Market performance and relatedother changes may decrease the value of the NDTF investments of Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, which then could require significant additional funding.
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. The performance of the capital markets affects the values of the assets held in trust to satisfy these future obligations. Duke Energy Carolinas, Duke Energy Progress and Duke 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 may increase.for decommissioning nuclear plants. If Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are unable to successfully manage their NDTF assets, their financial condition, results of operations and cash flows could be negatively affected.
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 a non-contributory defined benefit pension planplans are dependent onupon 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 plan, changes in these actuarial assumptions,plans, future government regulation changes in life expectancy and our required or voluntary contributions made to the plan. Changesplans. The Subsidiary Registrants are allocated their proportionate share of the cost and obligations related to these plans. Without sustained growth in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline inpension investments over time to increase the value of investments that fund our pension plan if not offset or mitigated by a decline in our liabilities, could increaseassets and, depending upon the expense of our pension plan, and weother factors impacting costs as listed above, Duke Energy could be required to fund our planits 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 our liquidity by reducing cash flows and could negatively affect results of operations.
We may invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.
We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by our regulated utility segment and our regulated non-utilities segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance. We may not be able to fully direct the management and policies of these businesses, and other participants in those relationships may take action contrary to our interests, including making operational decisions that could affect our costs and liabilities related to our investment. In addition, other participants may withdraw from the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours. The results of operations from those investments may be significantly less or realized significantly later than anticipated. All the above could adversely affect our earnings from or return of our investment in these businesses. We could make future equity method investments, acquisitions, or other business arrangements involving regulated or unregulated businesses as a minority or majority owner, with the similar potential to adversely affect our earnings from or return of our investment in those businesses.
We may be unable to attract and retain professional and technical employees, which could adversely impact our earnings.
Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract, train, develop and retain a skilled workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. Without a properly skilled and experienced workforce, our costs, including productivity and safety costs, costs to replace employees, and costs as a result of errors may increase, and this could negatively impact our earnings.
Cybersecurity attack, acts of cyber-terrorism or failure of technology systems could disrupt our business operations, shut down our facilities or result in the loss or exposure of confidential or sensitive customer, employee or Company information.
We are placing greater reliance on technological tools that support our operations and corporate functions and processes. We may own these tools or have a license to use them, or we may rely on the technological tools of third parties to whom we outsource processes. We use such tools to manage our natural gas distribution and transmission pipeline operations, maintain customer, employee, Company and vendor data, prepare our financial statements and manage supply chain and other business processes. One or more of these technologies may fail due to physical disruption such as flooding, design defects or human error, or we may be unable to have these technologies supported, updated, expanded or integrated into other
technologies. As technology and as our business operations change, we may replace or add systems and tools, and failure to successfully execute on these projects may result in business disruption or loss of data. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.
Disruption or failure of business operations and information technology systems could shut down our facilities or otherwise adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems, serve our customers effectively or manage our assets. An attack on or failure of information technology systems could result in the unauthorized release of customer, employee or other confidential or sensitive data. These events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our operations and financial results could be adversely affected.
Our insurance coverage may not be sufficient.
We currently have general liability and property insurance in place in amounts that we consider appropriate based on our business risk and best practices in our industry and in general business. Such policies are subject to certain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage for risks against which we and others in our industry typically insure may not be available in the future, or may be available but at materially increased costs, reduced coverage or on terms that are not commercially reasonable. Premiums and deductibles may increase substantially. The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on ourDuke Energy Registrants’ financial position, results of operations andor cash flows.
Duke Energy is a holding company and depends on the cash flows from its subsidiaries to meet its financial obligations.
Because Duke Energy is a holding company with no operations or cash flows of its own, its ability to meet its financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on its common stock, is primarily dependent on the net income and cash flows of its subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Duke Energy, its subsidiaries have regulatory restrictions and financial obligations that must be satisfied. These subsidiaries are separate legal entities and have no obligation to provide Duke Energy with funds. In addition, Duke Energy may provide capital contributions or debt financing to its subsidiaries under certain circumstances, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness and to pay dividends on Duke Energy’s common stock.
ItemITEM 1B. Unresolved Staff CommentsUNRESOLVED STAFF COMMENTSNone.
All property includedITEM 2. PROPERTIESELECTRIC UTILITIES AND INFRASTRUCTURE
The following table provides information related to the Electric Utilities and Infrastructure's generation stations as of December 31, 2017. The MW displayed in the Consolidated Balance Sheetstable below are based on summer capacity. Ownership interest in “Utility Plant”all facilities is 100 percent unless otherwise indicated. |
| | | | | |
| | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Duke Energy Carolinas | | | | |
| Oconee | Nuclear | Uranium | SC | 2,554 |
|
| McGuire | Nuclear | Uranium | NC | 2,316 |
|
Catawba(a) | Nuclear | Uranium | SC | 445 |
|
| Belews Creek | Fossil | Coal | NC | 2,220 |
|
| Marshall | Fossil | Coal | NC | 2,058 |
|
| J.E. Rogers | Fossil | Coal | NC | 1,388 |
|
| Lincoln Combustion Turbine (CT) | Fossil | Gas/Oil | NC | 1,193 |
|
| Allen | Fossil | Coal | NC | 1,098 |
|
| Rockingham CT | Fossil | Gas/Oil | NC | 825 |
|
| Buck Combined Cycle (CC) | Fossil | Gas | NC | 668 |
|
| Dan River CC | Fossil | Gas | NC | 662 |
|
| Mill Creek CT | Fossil | Gas/Oil | SC | 563 |
|
| W.S. Lee | Fossil | Gas | SC | 170 |
|
| W.S. Lee CT | Fossil | Gas/Oil | SC | 84 |
|
| Bad Creek | Hydro | Water | SC | 1,360 |
|
| Jocassee | Hydro | Water | SC | 780 |
|
| Cowans Ford | Hydro | Water | NC | 324 |
|
| Keowee | Hydro | Water | SC | 152 |
|
| Other small facilities (25 plants) | Hydro | Water | NC/SC | 669 |
|
| Distributed generation | Renewable | Solar | NC | 39 |
|
| Total Duke Energy Carolinas | | | | 19,568 |
|
|
| | | | | |
| | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Duke Energy Progress | | | | |
| Brunswick | Nuclear | Uranium | NC | 1,870 |
|
| Harris | Nuclear | Uranium | NC | 928 |
|
| Robinson | Nuclear | Uranium | SC | 741 |
|
| Roxboro | Fossil | Coal | NC | 2,439 |
|
| Smith CC | Fossil | Gas/Oil | NC | 1,073 |
|
| H.F. Lee CC | Fossil | Gas/Oil | NC | 888 |
|
| Wayne County CT | Fossil | Gas/Oil | NC | 857 |
|
| Smith CT | Fossil | Gas/Oil | NC | 772 |
|
| Darlington CT | Fossil | Gas/Oil | SC | 664 |
|
| Mayo | Fossil | Coal | NC | 727 |
|
| L.V. Sutton CC | Fossil | Gas/Oil | NC | 607 |
|
| Asheville | Fossil | Coal | NC | 378 |
|
| Asheville CT | Fossil | Gas/Oil | NC | 320 |
|
| Weatherspoon CT | Fossil | Gas/Oil | NC | 124 |
|
| L.V. Sutton CT (Black Start) | Fossil | Gas/Oil | NC | 80 |
|
| Blewett CT | Fossil | Oil | NC | 52 |
|
| Walters | Hydro | Water | NC | 112 |
|
| Other small facilities (three plants) | Hydro | Water | NC | 115 |
|
| Distributed generation | Renewable | Solar | NC | 62 |
|
| Total Duke Energy Progress | | | | 12,809 |
|
|
| | | | | |
| | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Duke Energy Florida | | | | |
| Crystal River | Fossil | Coal | FL | 2,188 |
|
| Hines CC | Fossil | Gas/Oil | FL | 2,032 |
|
| Bartow CC | Fossil | Gas/Oil | FL | 1,080 |
|
| Anclote | Fossil | Gas | FL | 1,013 |
|
| Intercession City CT | Fossil | Gas/Oil | FL | 951 |
|
| Osprey CC | Fossil | Gas/Oil | FL | 582 |
|
| DeBary CT | Fossil | Gas/Oil | FL | 561 |
|
| Tiger Bay CC | Fossil | Gas/Oil | FL | 200 |
|
| Bartow CT | Fossil | Gas/Oil | FL | 168 |
|
| Bayboro CT | Fossil | Oil | FL | 171 |
|
| Suwannee River CT | Fossil | Gas | FL | 149 |
|
| Higgins CT | Fossil | Gas/Oil | FL | 107 |
|
| Avon Park CT | Fossil | Gas/Oil | FL | 48 |
|
| University of Florida CoGen CT | Fossil | Gas | FL | 47 |
|
| Distributed generation | Renewable | Solar | FL | 8 |
|
| Total Duke Energy Florida | | | | 9,305 |
|
|
| | | | | |
| | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Duke Energy Ohio | | | | |
| East Bend | Fossil | Coal | KY | 600 |
|
| Woodsdale CT | Fossil | Gas/Propane | OH | 476 |
|
| Beckjord Battery Storage | Renewable | Storage | OH | 4 |
|
| Total Duke Energy Ohio | | | | 1,080 |
|
|
| | | | | |
| | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Duke Energy Indiana | | | | |
Gibson(b) | Fossil | Coal | IN | 2,822 |
|
Cayuga(c) | Fossil | Coal/Oil | IN | 1,005 |
|
| Edwardsport | Fossil | Coal | IN | 595 |
|
| Madison CT | Fossil | Gas | OH | 566 |
|
Vermillion CT(d) | Fossil | Gas | IN | 360 |
|
| Wheatland CT | Fossil | Gas | IN | 450 |
|
| Noblesville CC | Fossil | Gas/Oil | IN | 264 |
|
| Gallagher | Fossil | Coal | IN | 280 |
|
| Henry County CT | Fossil | Gas/Oil | IN | 129 |
|
| Cayuga CT | Fossil | Gas/Oil | IN | 80 |
|
| Connersville CT | Fossil | Oil | IN | 74 |
|
| Miami Wabash CT | Fossil | Oil | IN | 64 |
|
| Markland | Hydro | Water | IN | 45 |
|
| Distributed generation | Renewable | Solar | IN | 10 |
|
| Total Duke Energy Indiana | | | | 6,744 |
|
|
| | | | | |
| | | | Owned MW |
|
| Totals by Type | | | | Capacity |
|
| Total Electric Utilities | | | | 49,506 |
|
| Totals By Plant Type | | | | |
| Nuclear | | | | 8,854 |
|
| Fossil | | | | 36,972 |
|
| Hydro | | | | 3,557 |
|
| Renewable | | | | 123 |
|
| Total Electric Utilities | | | | 49,506 |
|
| |
| (a) | Jointly owned with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation and Piedmont Municipal Power Agency. Duke Energy Carolinas' ownership is 19.25 percent of the facility. |
| |
| (b) | Duke Energy Indiana owns and operates Gibson Station Units 1 through 4 and is a joint owner of unit 5 with Wabash Valley Power Association, Inc. (WVPA) and Indiana Municipal Power Agency. Duke Energy Indiana operates unit 5 and owns 50.05 percent. |
(c) Includes Cayuga Internal Combustion.
(d) Jointly owned by us and used in our regulated utility segment. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majorityWVPA. Duke Energy Indiana's ownership is 62.5 percent of the total investedfacility.
The following table provides information related to Electric Utilities and Infrastructure's electric transmission and distribution properties as of December 31, 2017. |
| | | | | | | | | | | | |
| | | Duke |
| Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Energy |
| Energy |
| Energy |
| Energy |
|
| | Energy |
| Carolinas |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Electric Transmission Lines | | | | | | |
| Miles of 500 to 525 kilovolt (kV) | 1,100 |
| 600 |
| 300 |
| 200 |
| — |
| — |
|
| Miles of 345 kV | 1,700 |
| — |
| — |
| — |
| 1,000 |
| 700 |
|
| Miles of 230 kV | 8,400 |
| 2,700 |
| 3,400 |
| 1,600 |
| — |
| 700 |
|
| Miles of 100 to 161 kV | 12,300 |
| 6,800 |
| 2,500 |
| 900 |
| 700 |
| 1,400 |
|
| Miles of 13 to 69 kV | 8,400 |
| 3,000 |
| — |
| 2,200 |
| 700 |
| 2,500 |
|
| Total conductor miles of electric transmission lines | 31,900 |
| 13,100 |
| 6,200 |
| 4,900 |
| 2,400 |
| 5,300 |
|
| Electric Distribution Lines | | | | | | |
| Miles of overhead lines | 174,300 |
| 66,600 |
| 46,400 |
| 25,200 |
| 13,700 |
| 22,400 |
|
| Miles of underground line | 102,800 |
| 37,800 |
| 29,400 |
| 20,800 |
| 5,900 |
| 8,900 |
|
| Total conductor miles of electric distribution lines | 277,100 |
| 104,400 |
| 75,800 |
| 46,000 |
| 19,600 |
| 31,300 |
|
| Number of electric transmission and distribution substations | 3,300 |
| 1,500 |
| 500 |
| 500 |
| 300 |
| 500 |
|
Substantially all of Electric Utilities and Infrastructure's electric plant in utility distributionservice is mortgaged under indentures relating to Duke Energy Carolinas’, Duke Energy Progress', Duke Energy Florida's, Duke Energy Ohio’s and transmission plant to serve our customers. We have approximately 2,910 linear milesDuke Energy Indiana’s various series of transmission pipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,300 linear miles of distribution mains up to 16 inches in diameter. TheFirst Mortgage Bonds.
GAS UTILITIES AND INFRASTRUCTURE
Gas Utilities and Infrastructure owns transmission pipelines and distribution mains that are generally underground, located near public streets and highways, or on property owned by others for which weDuke Energy Ohio and Piedmont have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties areproperty located in North Carolina, South Carolinawithin the Gas Utilities and Tennessee. Utility Plant includes “Construction work in progress," which primarily represents distribution, transmission and general plant projects that have not been placed intoInfrastructure service pending completion.
None of our property is encumbered, and all property is in use except for “Plant held for future use” as classified in the Consolidated Balance Sheets. The amount classified as plant held for future use is comprised of land located in Robeson County, North Carolina. For further information on this Robeson County property, see Note 1 and Note 2 to the consolidated financial statements in this Form 10-K.
We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our operating locations and resource centers located in North Carolina, South Carolina and Tennessee. Lease payments for these various offices totaled $4.5 million for the year ended October 31, 2014.
Property included in the Consolidated Balance Sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of natural gas water heaters leased to commercial customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.
Item 3. Legal Proceedings
We have only immaterial litigation or routine litigation in the normal course of business.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE).territories. The following table provides information with respectrelated to the highGas Utilities and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 2014 and 2013.
Infrastructure's natural gas distribution. |
| | | | | | | | | | | | | | | | | | |
| 2014 | | High |
| | Low |
| | 2013 | | High |
| | Low |
|
| Quarter ended: | | | | | | Quarter ended: | | | | |
| January 31 | | $ | 34.18 |
|
| $ | 31.94 |
| | January 31 | | $ | 33.10 |
| | $ | 28.51 |
|
| April 30 | | 36.55 |
|
| 32.12 |
| | April 30 | | 34.92 |
| | 31.73 |
|
| July 31 | | 37.86 |
|
| 34.30 |
| | July 31 | | 35.53 |
| | 32.39 |
|
| October 31 | | 38.36 |
|
| 33.38 |
| | October 31 | | 35.05 |
| | 31.56 |
|
|
| | | | | | |
| | | Duke |
| |
| | Duke |
| Energy |
| |
| | Energy |
| Ohio |
| Piedmont |
|
| Miles of natural gas distribution and transmission pipelines | 33,100 |
| 7,200 |
| 25,900 |
|
| Miles of natural gas service lines | 27,400 |
| 6,900 |
| 20,500 |
|
As of December 12, 2014, our common stock was owned by 13,379 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in street name or in the name of an investment company.COMMERCIAL RENEWABLES
Dividends
The following table provides information with respectrelated to quarterly dividends paid on common stock for the years ended OctoberCommercial Renewables' electric generation facilities as of December 31, 2014 and 2013. We expect that comparable cash dividends will continue to be paid2017. The MW displayed in the future.
|
| | | | | | | | | | |
| | | Dividends Paid | | | | Dividends Paid |
| 2014 | | Per Share | | 2013 | | Per Share |
| Quarter ended: | | | | | Quarter ended: | | | |
| January 31 | | 31 |
| ¢ | | January 31 | | 30 |
| ¢ |
| April 30 | | 32 |
| ¢ | | April 30 | | 31 |
| ¢ |
| July 31 | | 32 |
| ¢ | | July 31 | | 31 |
| ¢ |
| October 31 | | 32 |
| ¢ | | October 31 | | 31 |
| ¢ |
The amount of cash dividends that may be paidtable below are based on common stocknameplate capacity. Ownership interest in all facilities is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2014, our ability to pay dividends was not restricted.
Share Repurchases
The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2014.
100 percent unless otherwise indicated. |
| | | | | | | | |
Period | | Total Number
of Shares
Purchased
| | Average Price
Paid Per Share
| | Total Number of
Shares Purchased
as Part of Publicly
Announced Program
| | Maximum Number
of Shares that May
Yet be Purchased
Under the Program (1)
|
Beginning of the period | | | | | | | | 2,910,074 |
8/1/14 – 8/31/14 | | — | | — | | — | | 2,910,074 |
9/1/14 – 9/30/14 | | — | | — | | — | | 2,910,074 |
10/1/14 – 10/31/14 | | — | | — | | — | | 2,910,074 |
| | | | | Owned MW |
|
| Facility | Plant Type | Primary Fuel | Location | Capacity |
|
| Commercial Renewables – Wind | | | | |
| Los Vientos Windpower (five sites) | Renewable | Wind | TX | 912 |
|
| Top of the World | Renewable | Wind | WY | 200 |
|
| Frontier | Renewable | Wind | OK | 200 |
|
| Notrees | Renewable | Wind | TX | 153 |
|
| Campbell Hill | Renewable | Wind | WY | 99 |
|
| North Allegheny | Renewable | Wind | PA | 70 |
|
| Laurel Hill Wind Energy | Renewable | Wind | PA | 69 |
|
| Ocotillo | Renewable | Wind | TX | 59 |
|
| Kit Carson | Renewable | Wind | CO | 51 |
|
| Silver Sage | Renewable | Wind | WY | 42 |
|
| Happy Jack | Renewable | Wind | WY | 29 |
|
| Shirley | Renewable | Wind | WI | 20 |
|
Sweetwater IV(a) | Renewable | Wind | TX | 113 |
|
Sweetwater V(a) | Renewable | Wind | TX | 38 |
|
Ironwood(a) | Renewable | Wind | KS | 84 |
|
Cimarron II(a) | Renewable | Wind | KS | 66 |
|
Mesquite Creek(a) | Renewable | Wind | TX | 106 |
|
| Total Renewables – Wind | | — | | —2,311 |
|
| Commercial Renewables – Solar | | — | | |
| Conetoe II | Renewable | Solar | NC | 80 |
|
| Seville I & II | Renewable | Solar | CA | 50 |
|
| Rio Bravo I & II | Renewable | Solar | CA | 40 |
|
| Wildwood I & II | Renewable | Solar | CA | 35 |
|
| Caprock | Renewable | Solar | NM | 25 |
|
| Kelford | Renewable | Solar | NC | 22 |
|
| Highlander | Renewable | Solar | CA | 21 |
|
| Dogwood | Renewable | Solar | NC | 20 |
|
| Halifax Airport | Renewable | Solar | NC | 20 |
|
| Pasquotank | Renewable | Solar | NC | 20 |
|
| Pumpjack | Renewable | Solar | CA | 20 |
|
| Shawboro | Renewable | Solar | NC | 20 |
|
| Longboat | Renewable | Solar | CA | 20 |
|
| Bagdad | Renewable | Solar | AZ | 15 |
|
| TX Solar | Renewable | Solar | TX | 14 |
|
| Creswell Alligood | Renewable | Solar | NC | 14 |
|
| Victory | Renewable | Solar | CO | 13 |
|
| Washington White Post | Renewable | Solar | NC | 12 |
|
| Whitakers | Renewable | Solar | NC | 12 |
|
| Other small solar | Renewable | Solar | Various | 123 |
|
| Total Renewables – Solar | | | | 596 |
|
| Total Commercial Renewables | | | | 2,907 |
|
(a) Commercial Renewables owns 47 percent of Sweetwater IV and V and 50 percent of Ironwood, Cimarron II and Mesquite Creek.
OTHER
Duke Energy owns approximately 8 million square feet and leases approximately 2 million square feet of corporate, regional and district office space spread throughout its service territories.
ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, including regulatory and environmental matters, see Note 4, “Regulatory Matters,” and Note 5, “Commitments and Contingencies,” to the Consolidated Financial Statements.
MTBE Litigation
On June 19, 2014, the Commonwealth of Pennsylvania filed suit against, among others, Duke Energy Merchants, alleging contamination of “waters of the state” by MTBE from leaking gasoline storage tanks. MTBE is a gasoline additive intended to increase the oxygen level in gasoline and make it burn cleaner. The lawsuit was moved to federal court and consolidated into an existing multidistrict litigation docket of pending MTBE cases. This suit was settled for an immaterial amount in December 2017.
In December 2017, the state of Maryland filed a lawsuit in Baltimore City Circuit Court against Duke Energy Merchants and other defendants alleging contamination of its water supplies from MTBE. Discovery is underway. Duke Energy cannot predict the outcome of this matter.
ITEM 4. MINE SAFETY DISCLOSURES This is not applicable for any of the Duke Energy Registrants.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES The common stock of Duke Energy is listed and traded on the New York Stock Exchange (NYSE) (ticker symbol DUK). As of January 31, 2018, there were 166,271 Duke Energy common stockholders of record.
There is no market for common stock of the Subsidiary Registrants, all of which is owned by Duke Energy.
Common Stock Data by Quarter
The following chart provides Duke Energy common stock trading prices as reported on the NYSE and information on common stock dividends declared. Stock prices represent the intraday high and low stock price.
Duke Energy expects to continue its policy of paying regular cash dividends; however, there is no assurance as to the amount of future dividends as they depend on future earnings, capital requirements and financial condition, and are subject to declaration by the Duke Energy Board of Directors.
Duke Energy’s operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to Duke Energy. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters” for further information regarding these restrictions.
Securities Authorized for Issuance Under Equity Compensation Plans |
| | | | |
(1)
| The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. On that date, the Board also approved an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated. |
DiscussionSee Item 12 of our compensation plans, under which sharesPart III within this Annual Report for information regarding Securities Authorized for Issuance Under Equity Compensation Plans.
Issuer Purchases of our common stock are authorizedEquity Securities for issuance, is included inFourth Quarter 2017 There were no repurchases of equity securities during the portionfourth quarter of our proxy statement captioned “Executive Compensation” to be filed no later than January 31, 2015, in connection with our Annual Meeting to be held on March 5, 2015, and is incorporated herein by reference.2017.
Comparisons of Cumulative Total Shareholder Returns36
The following performance graph compares ourthe cumulative total shareholder return from October 31, 2009 through October 31, 2014 (a five-year period)Duke Energy Corporation common stock, as compared with the average performance of our industry peer group and the Standard & Poor’sPoor's 500 Stock Index a broad market index (the(S&P 500) and the Philadelphia Utility Sector Index (Philadelphia Utility Index) for the past five years. The graph assumes an initial investment of $100 on December 31, 2012, in Duke Energy common stock, in the S&P 500 Index). Our local distribution company (LDC) Peer Group index is comprised of peer group companies that are domiciledand in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our relative total shareholder returns, which we use for market benchmarking for our executive compensation plans.
Over the past several years, we have made significant additional investments in transmission pipeline infrastructure. In light of this transmission business and now owning and operating over 2,900 miles of transmission pipeline, our LDC Peer Group was updated to include CenterPoint Energy and Questar Corporation, effective with our performance award under an approved incentive compensation plan covering a three-year performance period that ended October 31, 2014. Our total return of $100 invested as of October 31, 2014 was $198. With the addition of CenterPoint Energy and Questar Corporation, our LDC Peer Group return was $236. Without them, the peer group return would have been $241.
The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2009Philadelphia Utility Index and that all dividends were reinvested. Stock price performancesThe stockholder return shown onbelow for the graph arefive-year historical period may not be indicative of future price performance.
LDC Peer Group—The following companies are included: AGL Resources, Inc., AtmosDuke Energy Corporation, CenterPoint Energy, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, Questar Corporation, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporationhas filed the certification of its Chief Executive Officer and WGL Holdings, Inc. Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to this Annual Report on Form 10-K for the year ended December 31, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
| Piedmont | | $ | 100 |
| | $ | 132 |
| | $ | 152 |
| | $ | 154 |
| | $ | 171 |
| | $ | 198 |
|
| LDC Peer Group | | 100 |
| | 129 |
| | 156 |
| | 167 |
| | 201 |
| | 236 |
|
| S&P 500 Index | | 100 |
| | 117 |
| | 126 |
| | 145 |
| | 185 |
| | 216 |
|
ItemITEM 6. Selected Financial DataSELECTED FINANCIAL DATAThe following table provides selected financial data for the years ended October 31, 2010of 2013 through 2014.2017. See also Item 7.
|
| | | | | | | | | | | | | | | | | | | | |
| In thousands, except per share amounts |
| 2014 |
| 2013 |
| 2012 |
| 2011 |
| 2010 |
| Operating Revenues |
| $ | 1,469,988 |
|
| $ | 1,278,229 |
|
| $ | 1,122,780 |
|
| $ | 1,433,905 |
| | $ | 1,552,295 |
|
| Margin (operating revenues less cost of gas) |
| $ | 690,208 |
|
| $ | 621,490 |
|
| $ | 575,446 |
|
| $ | 573,639 |
| | $ | 552,592 |
|
| Net Income |
| $ | 143,801 |
|
| $ | 134,417 |
|
| $ | 119,847 |
|
| $ | 113,568 |
| | $ | 141,954 |
|
| Earnings per Share of Common Stock: |
|
|
|
|
|
|
| | | |
| Basic |
| $ | 1.85 |
|
| $ | 1.80 |
|
| $ | 1.67 |
|
| $ | 1.58 |
| | $ | 1.96 |
|
| Diluted |
| $ | 1.84 |
|
| $ | 1.78 |
|
| $ | 1.66 |
|
| $ | 1.57 |
| | $ | 1.96 |
|
| Cash Dividends per Share of Common Stock |
| $ | 1.27 |
| | $ | 1.23 |
| | $ | 1.19 |
| | $ | 1.15 |
| | $ | 1.11 |
|
| Total Assets |
| $ | 4,784,253 |
|
| $ | 4,368,609 |
|
| $ | 3,769,939 |
| | $ | 3,242,541 |
| | $ | 3,053,275 |
|
| Long-Term Debt (less current maturities) |
| $ | 1,424,430 |
|
| $ | 1,174,857 |
|
| $ | 975,000 |
| | $ | 675,000 |
| | $ | 671,922 |
|
|
| | | | | | | | | | | | | | | | | | | |
| (in millions, except per share amounts) | 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Statement of Operations(a) | | | | | | | | | |
| Total operating revenues | $ | 23,565 |
| | $ | 22,743 |
| | $ | 22,371 |
| | $ | 22,509 |
| | $ | 21,211 |
|
| Operating income | 5,781 |
| | 5,341 |
| | 5,078 |
| | 4,842 |
| | 4,305 |
|
| Income from continuing operations | 3,070 |
| | 2,578 |
| | 2,654 |
| | 2,538 |
| | 2,278 |
|
| (Loss) Income from discontinued operations, net of tax | (6 | ) | | (408 | ) | | 177 |
| | (649 | ) | | 398 |
|
| Net income | 3,064 |
| | 2,170 |
| | 2,831 |
| | 1,889 |
| | 2,676 |
|
| Net income attributable to Duke Energy Corporation | 3,059 |
| | 2,152 |
| | 2,816 |
| | 1,883 |
| | 2,665 |
|
| Common Stock Data | | | | | | | | | |
| Income from continuing operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 4.37 |
| | $ | 3.71 |
| | $ | 3.80 |
| | $ | 3.58 |
| | $ | 3.21 |
|
| Diluted | 4.37 |
| | 3.71 |
| | 3.80 |
| | 3.58 |
| | 3.21 |
|
| (Loss) Income from discontinued operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | (0.01 | ) | | $ | (0.60 | ) | | $ | 0.25 |
| | $ | (0.92 | ) | | $ | 0.56 |
|
| Diluted | (0.01 | ) | | (0.60 | ) | | 0.25 |
| | (0.92 | ) | | 0.55 |
|
| Net income attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 4.36 |
| | $ | 3.11 |
| | $ | 4.05 |
| | $ | 2.66 |
| | $ | 3.77 |
|
| Diluted | 4.36 |
| | 3.11 |
| | 4.05 |
| | 2.66 |
| | 3.76 |
|
| Dividends declared per share of common stock | 3.49 |
| | 3.36 |
| | 3.24 |
| | 3.15 |
| | 3.09 |
|
| Balance Sheet | | | | | | | | | |
| Total assets | $ | 137,914 |
| | $ | 132,761 |
| | $ | 121,156 |
| | $ | 120,557 |
| | $ | 114,779 |
|
| Long-term debt including capital leases, less current maturities | 49,035 |
| | 45,576 |
| | 36,842 |
| | 36,075 |
| | 37,065 |
|
| |
| (a) | Significant transactions reflected in the results above include: (i) the sale of the International Disposal Group in 2016, including a loss on sale recorded within discontinued operations (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”) (ii) the acquisition of Piedmont in 2016, including losses on interest rate swaps related to the acquisition financing (see Note 2); (iii) 2014 impairment related to the disposal of the Midwest Generation Disposal Group; (iv) 2014 incremental tax expense resulting from the decision to repatriate all cumulative historical undistributed foreign earnings; (v) 2014 increase in the litigation reserve related to a criminal investigation of the Dan River release; (vi) 2013 charges related to Crystal River Unit 3 and nuclear development costs; and (vii) costs to achieve mergers in all periods. |
ItemITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSManagement’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP) in the United States (U.S.), as well as certain non-GAAP financial measures such as adjusted earnings and adjusted earnings per share discussed below. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.
The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
This report, as well as other documents we file is separately filed by Duke Energy Corporation (collectively with the Securitiesits subsidiaries, Duke Energy) and Exchange Commission (SEC)its subsidiaries Duke Energy Carolinas, LLC (Duke Energy Carolinas), may contain forward-looking statements. In addition, our senior managementProgress Energy, Inc. (Progress Energy), Duke Energy Progress, LLC (Duke Energy Progress), Duke Energy Florida, LLC (Duke Energy Florida), Duke Energy Ohio, Inc. (Duke Energy Ohio), Duke Energy Indiana, LLC (Duke Energy Indiana) and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Item 1A. Risk Factors:
Economic conditions in our markets
Wholesale price of natural gas
Availability of adequate interstate pipeline transportation capacity and natural gas supply
Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis
Competition from other companies that supply energy
Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated
Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us
Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities
Changes in local building codes or appliance standards
Weather conditions
Operational interruptions to our gas distribution and transmission activities
Inability to complete necessary or desirable pipeline expansion or infrastructure development projects
Elevated levels of capital expenditures
Changes to our credit ratings
Availability and cost of capital
Federal and state fiscal, tax and monetary policies
Ability to generate sufficient cash flows to meet all our cash needs
Ability to satisfy all of our outstanding debt obligations
Ability of counterparties to meet their obligations to us
Costs of providing pension benefits
Earnings from the joint venture businesses in which we invest
Ability to attract and retain professional and technical employees
Cybersecurity breaches or failure of technology systems
Ability to obtain and maintain sufficient insurance
Change in number of outstanding shares
Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not place undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “may,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.
Forward-looking statements are based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.
Overview
Piedmont Natural Gas Company, Inc., which began operations in 1951, (Piedmont). However, none of the registrants make any representation as to information related solely to Duke Energy or the subsidiary registrants of Duke Energy other than itself. Subsequent to Duke Energy's acquisition of Piedmont on October 3, 2016, Piedmont is a wholly owned subsidiary of Duke Energy. The financial information for Duke Energy includes results of Piedmont subsequent to October 3, 2016. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information regarding the acquisition.
DUKE ENERGY
Duke Energy is an energy services company whose principal business isheadquartered in Charlotte, North Carolina. Duke Energy operates in the distributionU.S. primarily through its wholly owned subsidiaries, Duke Energy Carolinas, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana and Piedmont. When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of the Subsidiary Registrants, which, along with Duke Energy, are collectively referred to as the Duke Energy Registrants.
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Executive Overview
With our multiyear portfolio transition complete, we operated in 2017 as a domestic, regulated energy infrastructure business. Our long-term view provides a compelling vision to advance our strategy, leveraging scale and a focused portfolio to deliver a reliable dividend with 4 to 6 percent earnings per share (EPS) growth during our five year planning horizon. We have made progress advancing our long-term strategy to invest in our growth drivers of cleaner energy, grid modernization and natural gas infrastructure, while also improving customer satisfaction.
Financial Results
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| (a) | See Results of Operations below for Duke Energy’s definition of adjusted earnings and adjusted earnings per share as well as a reconciliation of this non-GAAP financial measure to net income attributable to Duke Energy and net income attributable to Duke Energy per diluted share. |
Duke Energy's 2017 GAAP reported earnings were impacted by unfavorable weather and the absence of International Energy partially offset by growth in the electric and gas businesses, including the addition of a full year's earnings contribution from Piedmont and ongoing cost management efforts. See “Results of Operations” below for a detailed discussion of the consolidated results of operations, as well as a detailed discussion of financial results for each of Duke Energy’s reportable business segments, as well as Other.
2017 Areas of Focus and Accomplishments
Duke Energy advanced a number of important strategic initiatives to over one milliontransform its energy future with a focus on customers, employees, operations and growth. The company has responded to an environment of changing customer demands by investing in electric and natural gas infrastructure that customers value and that provide an opportunity for sustainable growth.
Portfolio Transition. On October 3, 2016, Duke Energy completed the acquisition of Piedmont, a North Carolina corporation primarily engaged in regulated natural gas distribution to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee,Tennessee. In December 2016, Duke Energy completed the sale of its Latin American generation businesses in two separate transactions. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information regarding these transactions.
With the acquisition of Piedmont and the sale of International Energy, Duke Energy completed a multiyear portfolio transition. The Piedmont acquisition reflects the growing importance of natural gas to the future of the energy infrastructure within the company's service territory and throughout the U.S. and establishes a strategic platform for future growth in natural gas infrastructure. The growth opportunities reflected in our 10-year strategy are expected to increase the earnings contributions from the natural gas business from 8 percent to 15 percent.
Operational Excellence. Duke Energy continues to focus on the safe and efficient operation of its generation fleet. During 2017, we delivered strong overall safety and environmental performance, with our key employee safety metric, total incident case rate, and our reportable environmental events both improving from last year. Our nuclear and fossil/hydro generation fleets demonstrated strong performance, exceeding their respective reliability targets.
Storm Response and System Restoration. Hurricane Irma, in October 2017, was one of the most powerful storms ever to hit the southern U.S. During Hurricane Irma, over 1.3 million customers in Florida were without power. Our restoration efforts involved coordination and communication with more than 12,000 line and fieldworkers and our team restored power to 99 percent of customers within eight days.
Customer Satisfaction. Higher J.D. Power residential customer satisfaction scores in 2017 reflect progress in the company's efforts to meet customers’ expectations. The work to improve customer satisfaction will continue, but all jurisdictions remain on track to make steady gains in the years ahead as Duke Energy continues to transform the customer experience through its Customer Connect Program.
Constructive Regulatory Outcomes. One of our long-term strategic goals is to achieve modernized regulatory constructs in all of our jurisdictions within 10 years. Modernized constructs provide a number of benefits, including customers served by municipalities who are our wholesaleimproved earnings and cash flows through more timely recovery of investments, as well as stable pricing for customers. We are investedfiled several base rate cases during 2017 to recover a range of strategic investments, such as customer service technologies, coal ash costs in joint venture, energy-related businesses, including unregulated retailthe Carolinas, smart meters, natural gas marketing, regulated interstateand solar generation. We continue to pursue additional legislative and regulatory outcomes, both in Washington and across our service territories, that make sense for our customers and investors.
Cost Management and Efficiencies. Duke Energy has a demonstrated track record of driving efficiencies and productivity, including merger integration and continuous improvement efforts. These efficiencies will help in Duke Energy's objective to keep overall customer rates below the national average, while moderating customer bill increases over time. We are on track to exceed targeted Piedmont merger cost synergies without significant disruptions to the business or culture, integrating the Piedmont and Midwest natural gas transportationoperations, and storagemoving to a shared services model. We continue to leverage new technology and regulated intrastatedata analytics to drive additional efficiencies across the business.
Dividend Growth. In 2017, Duke Energy continued to grow the dividend payment to shareholders by approximately 4 percent. 2017 represented the 91st consecutive year Duke Energy paid a cash dividend on its common stock.
Duke Energy Objectives – 2018 and Beyond
Duke Energy will continue to deliver exceptional value to customers, be an integral part of the communities in which it does business, and provide attractive returns to investors. Duke Energy is committed to lead the way to cleaner, smarter energy solutions that customers value through a strategy focused on:
Transformation of the customer experience to meet changing customer expectations through enhanced convenience, control and choice in energy supply and usage.
Modernization of the electric grid, including smart meters, storm hardening, self-healing and targeted undergrounding to ensure the system is better prepared for severe weather and to improve the system's reliability and flexibility, as well as to provide better information and services for customers.
Generation of cleaner energy through an increased amount of natural gas, transportation businesses.renewables generation and the continued safe and reliable operation of nuclear plants.
Expansion of natural gas infrastructure, from midstream gas pipelines to local distribution systems.
Operational excellence through engagement with employees and being an industry leader in safety performance and efficient operations.
Stakeholder engagement to ensure the regulatory rules in the states in which Duke Energy operates benefit customers and allow Duke Energy to recover its significant investments in a timely manner while maintaining affordable rates.
Engagement with regulatory commissions to determine the regulatory treatment of the impact of the Tax Act.
We operate with three reportable40
Primary objectives toward the implementation of this strategy include:
Growth Initiatives. Growth in the Electric Utilities and Infrastructure business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulatedis expected to be supported by the North Carolinainvestment of significant capital in the electric transmission and distribution grid, and in cleaner, more efficient generation. Duke Energy expects to invest approximately $30 billion in Electric Utilities Commission (NCUC)and Infrastructure growth projects over the next five years (2018-2022), continuing its efforts to generate cleaner energy. Duke Energy intends to work constructively with regulators to evaluate the Public Service Commission ofcurrent regulatory construct and seek modernized recovery solutions, such as riders, rate decoupling and multiyear rate plans, that benefit both customers and shareholders.
Investment projects at Electric Utilities and Infrastructure currently underway that will support growth initiatives include:
Duke Energy Indiana's $1.4 billion grid modernization plan, which is aimed at improving reliability, including fewer outages and quicker restoration.
Significant investments in combined-cycle natural gas plants, including completing the $1.5 billion Citrus County plant in Florida, the $600 million W.S. Lee facility in South Carolina and the Tennessee Regulatory Authority (TRA) as$900 million investment in the Western Carolinas Modernization Project. These investments will allow Duke Energy to rates, service area, adequacy of service, safety standards, extensionsreplace older, less efficient coal units.
Duke Energy expects to continue to advance other cleaner energy sources within its regulated electric jurisdictions, including hydro, wind, solar and abandonment of facilities, accountingcombined heat and depreciation. The NCUC also regulates us as topower projects, increasing the issuance of long-term debt and equity securities. Factors critical to the successflexibility of the regulated utility segment include operating a safesystem and reliableallowing Duke Energy to continue lowering carbon emissions.
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| ◦ | In North Carolina, HB 589 provides a timely cost recovery mechanism for any solar investments we are able to make through a competitive market process. |
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| ◦ | In Florida, as part of the comprehensive multi-year rate settlement, we committed to invest in approximately 700 MW of solar capacity over the next five years and will be authorized to recover the cost of that investment through a single issue base rate increase. We also advanced our strategic priority of energy grid investment, establishing a multiyear recovery method for $1 billion of grid investments. |
Duke Energy expects to invest around $7 billion growing its Gas Utilities and Infrastructure business over the next five years. Growth in Gas Utilities and Infrastructure will be focused on the following:
With the acquisition of Piedmont, Duke Energy now operates natural gas distribution system and the ability to recover the costs and expensesbusinesses across five states. The continued integration of the businessPiedmont, as well as additional investments in the rates chargednatural gas Local Distribution Company (LDC) system, will help maintain system integrity and expand natural gas distribution to new customers. The regulated non-utility activities segment consists of our equity method investments in joint venture regulated energy-related businesses that are held by our wholly-owned subsidiaries. The unregulated non-utility activities segment consists primarily of our equity method investment in SouthStar
Duke Energy Services LLC (SouthStar) that is held by a wholly-owned subsidiary. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.
Executive Summary
A summary of our annual results is as follows:
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| | | | | | | | | | | | | | | | | | |
| Comprehensive Income Statements Components |
| | | | | | | | | |
| | | | | | | | | Percent Change |
| | | | | | | | | 2014 vs. | | 2013 vs. |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 | | 2013 | | 2012 |
| Operating Revenues | | $ | 1,469,988 |
| | $ | 1,278,229 |
| | $ | 1,122,780 |
| | 15.0 | % | | 13.8 | % |
| Cost of Gas | | 779,780 |
| | 656,739 |
| | 547,334 |
| | 18.7 | % | | 20.0 | % |
| Margin | | 690,208 |
| | 621,490 |
| | 575,446 |
| | 11.1 | % | | 8.0 | % |
| Operations and Maintenance | | 270,877 |
| | 253,120 |
| | 242,599 |
| | 7.0 | % | | 4.3 | % |
| Depreciation | | 118,996 |
| | 112,207 |
| | 103,192 |
| | 6.1 | % | | 8.7 | % |
| General Taxes | | 37,294 |
| | 34,635 |
| | 34,831 |
| | 7.7 | % | | (0.6 | )% |
| Utility Income Taxes | | 83,176 |
| | 77,334 |
| | 69,101 |
| | 7.6 | % | | 11.9 | % |
| Total Operating Expenses | | 510,343 |
| | 477,296 |
| | 449,723 |
| | 6.9 | % | | 6.1 | % |
| Operating Income | | 179,865 |
| | 144,194 |
| | 125,723 |
| | 24.7 | % | | 14.7 | % |
| Other Income (Expense), net of tax | | 18,622 |
| | 15,161 |
| | 14,221 |
| | 22.8 | % | | 6.6 | % |
| Utility Interest Charges | | 54,686 |
| | 24,938 |
| | 20,097 |
| | 119.3 | % | | 24.1 | % |
| Net Income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
| | 7.0 | % | | 12.2 | % |
| | | | | | | | | | | |
| Average Shares of Common Stock: | | | | | | | | | | |
| Basic | | 77,883 |
|
| 74,884 |
| | 71,977 |
| | 4.0 | % | | 4.0 | % |
| Diluted | | 78,193 |
|
| 75,333 |
| | 72,278 |
| | 3.8 | % | | 4.2 | % |
| | | | | | | | | | | |
| Earnings per Share of Common Stock: | | | | | | | | | | |
| Basic | | $ | 1.85 |
|
| $ | 1.80 |
| | $ | 1.67 |
| | 2.8 | % | | 7.8 | % |
| Diluted | | $ | 1.84 |
|
| $ | 1.78 |
| | $ | 1.66 |
| | 3.4 | % | | 7.2 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| Margin by Customer Class |
| | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Sales and Transportation: | | | | | | | | | | | | |
| Residential | | $ | 348,782 |
| | 51 | % | | $ | 331,920 |
| | 54 | % | | $ | 321,056 |
| | 56 | % |
| Commercial | | 169,442 |
| | 25 | % | | 155,065 |
| | 25 | % | | 150,306 |
| | 26 | % |
| Industrial | | 50,889 |
| | 7 | % | | 52,268 |
| | 8 | % | | 46,993 |
| | 8 | % |
| Power Generation | | 77,573 |
| | 11 | % | | 56,312 |
| | 9 | % | | 32,289 |
| | 6 | % |
| For Resale | | 8,819 |
| | 1 | % | | 7,477 |
| | 1 | % | | 7,465 |
| | 1 | % |
| Total | | 655,505 |
| | 95 | % | | 603,042 |
| | 97 | % | | 558,109 |
| | 97 | % |
| Secondary Market Sales | | 25,414 |
| | 4 | % | | 8,979 |
| | 1 | % | | 9,681 |
| | 2 | % |
| Miscellaneous | | 9,289 |
| | 1 | % | | 9,469 |
| | 2 | % | | 7,656 |
| | 1 | % |
| Total | | $ | 690,208 |
| | 100 | % | | $ | 621,490 |
| | 100 | % | | $ | 575,446 |
| | 100 | % |
|
| | | | | | | | | | | | | | | |
| Gas Deliveries, Customers, Weather Statistics and Number of Employees |
| | | | | | | | | | | |
| | | | | | | | | Percent Change |
| | | | | | | | | 2014 vs. | | 2013 vs. |
| | | 2014 | | 2013 | | 2012 | | 2013 | | 2012 |
| Deliveries in Dekatherms (in thousands): | | | | | | | | | | |
| Residential | | 61,782 |
| | 55,283 |
| | 43,788 |
| | 11.8 | % | | 26.3 | % |
| Commercial | | 44,259 |
| | 39,602 |
| | 33,774 |
| | 11.8 | % | | 17.3 | % |
| Industrial | | 95,780 |
| | 95,019 |
| | 89,234 |
| | 0.8 | % | | 6.5 | % |
| Power Generation | | 201,707 |
| | 190,862 |
| | 151,675 |
| | 5.7 | % | | 25.8 | % |
| For Resale | | 7,174 |
| | 6,834 |
| | 5,829 |
| | 5.0 | % | | 17.2 | % |
| Throughput | | 410,702 |
|
| 387,600 |
| | 324,300 |
| | 6.0 | % | | 19.5 | % |
| Secondary Market Volumes | | 20,516 |
| | 41,605 |
| | 48,373 |
| | (50.7 | )% | | (14.0 | )% |
| | | | | | | | | | | |
| Customers Billed (at period end) | | 992,551 |
|
| 979,909 |
| | 969,239 |
| | 1.3 | % | | 1.1 | % |
| Gross Residential, Commercial and Industrial Customer Additions | | 16,251 |
| | 14,293 |
| | 13,274 |
| | 13.7 | % | | 7.7 | % |
| Degree Days | | | | | | | | | | |
| Actual | | 3,543 |
|
| 3,336 |
| | 2,668 |
| | 6.2 | % | | 25.0 | % |
| Normal | | 3,265 |
|
| 3,276 |
| | 3,310 |
| | (0.3 | )% | | (1.0 | )% |
| Percent colder (warmer) than normal | | 8.5 | % |
| 1.8 | % | | (19.4 | )% | | n/a |
| | n/a |
|
| Number of Employees (at period end) | | 1,879 |
| | 1,795 |
| | 1,752 |
| | 4.7 | % | | 2.5 | % |
Financial Performance – Fiscal 2014 Compared with Fiscal 2013
Our 2014 fiscal year was a solid one with a 7% increase in net income. Margin increased 11% due to customer growth, higher volumes delivered to residential and commercial customers in South Carolina and Tennessee due to colder weather, new rates effective January 1, 2014 in North Carolina under a rate case settlement, the Tennessee and North Carolina integrity management rider (IMR) rate adjustments, increased transportation delivery services for power generation customers and higher margin sales from secondary market activity. Operations and maintenance (O&M) expenses and depreciation expense increased 7% and 6%, respectively. The increase in O&M expenses was related to increases in payroll, regulatory, bad debt and contract labor expenses. Depreciation was higher due to increases in plant in service from our capital investment program. General taxes increased 8% primarily due to increased property taxes, franchise taxes and payroll taxes. Other Income (Expense) increased 23% primarily due to an increase in income from equity method investments, primarily from SouthStar and Constitution Pipeline Company, LLC (Constitution), partially offset by a write-off of an investment that had been accounted for under the cost method. Utility interest charges increased 119% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and the recording of interest expense on amounts due to customers.
Business Summary – Fiscal 2014 Compared with Fiscal 2013
Our fiscal 2014 performance reflects execution of our long-term business strategy that focuses on safety and growth in our markets, favorable changes in state regulation with new rates and IMRs, and secondary market activity. As discussed above, financial performance was solid for the year with increased earnings and an increase in our dividend rate per share to our investors.
Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. As reflected in this annual report, we revised this target to include both short- and long-term debt as we believe it provides a more accurate representation of our overall leverage and our financing targets. Wewill continue to rely on our commercial paper (CP) program to meet our short-term liquidity needs. We accomplished the followinggrow its midstream pipeline business, underpinned by investments in fiscal year 2014:
In November 2013, we entered into an agreement with our revolving credit facility lenders that increased our borrowing capacity to $850 million.
In December 2013, we repaid the balance of $100 million of our 5% medium-term notes as they became due.
In December 2013, we issued 1.6 million shares under forward sale agreements (FSAs) entered into in February 2013, receiving proceeds of $47.3 million.
In September 2014, we issued $250 million of twenty-year, unsecured senior notes, receiving net proceeds of $247.7 million, net of debt issuance costs.
For further information on these transactions, see Note 4, Note 5 and Note 6 to the consolidated financial statements in this Form 10-K and the following discussion of "Cash Flows from Financing Activities."
Managing Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have adequate and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. In November 2012, in order to provide additional diversification, reliability and gas cost benefits to our customers, we signed long-term capacity and supply contracts to transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. This source of supply is scheduled to be available in late 2015 once construction of the Williams – Transco Leidy Southeast expansion project has been completed. In October 2014, we signed a long-term pipeline capacity precedent agreement under the Atlantic Coast Pipeline, LLC (ACP) project to sourceSabal Trail and Constitution pipeline projects. These highly contracted pipelines will bring much needed, low-cost natural gas supplies fromto the Marcellus and Utica shale basins in central West Virginia that are anticipated to be available for the winter 2018 – 2019 season.
Customer Growth – We have added increasing numbers of customers in our service areas each year over our last three fiscal years. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. With continued improvement ineastern U.S., spurring economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of natural gas, total new customers increased 13.7% in 2014 compared to 2013.
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| | | | | | | | | |
| | | | | | | Percent |
| | | 2014 | | 2013 | | Change |
| Residential new home construction | | 11,659 |
| | 10,299 |
| | 13.2 | % |
| Residential conversion | | 2,814 |
| | 2,463 |
| | 14.3 | % |
| Commercial | | 1,763 |
| | 1,512 |
| | 16.6 | % |
| Industrial | | 15 |
| | 19 |
| | (21.1 | )% |
| Total new customers | | 16,251 |
| | 14,293 |
| | 13.7 | % |
Overall, total net customers billed increased 1.3% as compared to 2013.
Capital Expenditures – We continued to execute our capital expansion and improvement programs that will provide benefits to our customers through safe and reliable natural gas service while providing our shareholders a fair and reasonable return on invested capital. Our capital expenditures are driven by pipeline integrity, safety and compliance programs, investments for customer growth and technologyhelping Duke Energy to grow its customer base in the Southeast.
For Commercial Renewables, Duke Energy will continue to pursue long-term contracted wind and system infrastructure, includingsolar projects that meet its return criteria.
Cost Management. Duke Energy has a new comprehensive workdemonstrated track record of driving efficiencies and assetproductivity into the business, leveraging its scale through competitive procurement initiatives, deploying digital transformation and continuing to identify sustainable cost savings as an essential element in response to a transforming industry.
Execute on Coal Ash Management Strategy. Duke Energy will continue the company's compliance strategy with the North Carolina Coal Ash Management Act of 2014 (Coal Ash Act) and Resource Conservation and Recovery Act. Duke Energy will update ash management system.
With significant capital costs incurred under our ongoing system integrity programs, we implemented new regulatory mechanisms that will allow us to recover and earn on those investments in a more timely manner. In December 2013, the NCUC approved the settlement of our 2013 general rate case, including the implementation of an IMR to separately track and recover the costs associated with capital expenditures in orderplans to comply with federal pipeline safety and integrity requirements. With the IMR mechanism, we will avoid having to file costly and more frequent future general rate proceedings, consuming both our resources and the resources of the NCUC and its staff. Under the IMR tariff, we will make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. For the annual period beginning February 1, 2014, the North Carolina IMR will increase our margin revenues by $.8 million with $.6 million recorded through the 2014 fiscal year end. With its approval of the rate case settlement, the NCUC continued to allow regulatory asset treatment of our external pipeline integrity management O&M costs and recovery of these costs through future amortization in rates. Also in December 2013, the TRA approved the settlement of our August 2013 IMR filing in Tennessee to recover the costs of our capital investments associated with federal and state mandated safety and integrity programs. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures incurred through the previous October. For the twelve-month period beginning January 1, 2014, the Tennessee IMR will increase our margin revenues by $13.1 million with $10.1 million recorded through the fourth quarter of 2014.
We completed pipeline expansion projects over our last three fiscal years that provide natural gas delivery service to new power generation facilities in our market area. We currently provide service to 25 power generation customer accounts. See the discussion of our forecasted capital investments in “Cash Flows from Investing Activities” in this Form 10-K .
Business Process and Technology Improvements – We are executing a multi-year, multi-project program designed to bring additional technology and automation to our field operations to enable our employees to more effectively and efficiently manage our pipeline assets. This program is expected to facilitate compliance with pipeline safety and integrityappropriate regulations and create operating efficiencies. Implementation began in April 2014. Several phases of the programexpand excavation and other compliance work at additional sites once plans and permits are expected to be implemented through our fiscal year 2016.approved.
Regulatory and Legislative Activity – We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. As discussed above, with the NCUC approval of the settlement of our 2013 general rate case, we implemented adjustments in our rates and charges, effective January 1, 2014, to provide incremental annual total revenues of $30.7 million, yielding an annual pre-tax income increase of $24.2 million. This revenue increase was a .7% annual rate increase for our customers since our last general rate proceeding in 2008. The new rates are based on a rate base in North Carolina of $1.8 billion as of September 30, 2013, an equity capital structure component of 50.7% and a return on common equity of 10%.
Equity Method Investments – Our investments in complementary energy-related businesses continue to be an attractive way to generate earnings growth and long-term shareholder returns. Our 2014 earnings before taxes from SouthStar increased $5 million with our additional investment of $22.5 million made in September 2013, maintaining our 15% equity ownership. Our partner contributed retail natural gas marketing assets and related customers located in Illinois.
We are a 24% equity member of Constitution, a Federal Energy Regulatory Commission (FERC) regulated interstate natural gas pipeline that is proposed to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. The forecasted in-service date of the project is late 2015 or 2016. We expect our total 24% equity contributions will be an estimated $175 million. We contributed $37.6 million and $15.9 million in 2014 and 2013, respectively, for a total of $53.5 million to date.
In September 2014, we became a 10% equity member of ACP, a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. We expect our total 10% equity contributions will be an estimated $450 million to $500 million before any project financing. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements and "Cash Flows from Investing Activities" in this Form 10-K.
Strategy and Focus Areas
Our long-term strategic directives shape our annual business objectives and focus on our customers, our communities, our employees and our shareholders. They also reflect what we believe are the inherent advantages of natural gas compared to other types of energy. Our seven foundational strategic priorities are as follows:
Promote the benefits of natural gas,
Expand our core natural gas and complementary energy-related businesses to enhance shareholder value,
Be the energy service provider of choice,
Achieve excellence in customer service every time,
Preserve financial strength and flexibility,
Execute sustainable business practices, and
Enhance our healthy, high performance culture.
With a focus on these priorities, we believe we will enhance long-term shareholder value. For a full discussion of our strategy and focus areas, see Item 1. Business in this Form 10-K.
Additional information on operating results for the years ended October 31, 2014, 2013 and 2012 follows.
Results of Operations
Non-GAAP Measures
Operating RevenuesManagement evaluates financial performance in part based on non-GAAP financial measures, including adjusted earnings and adjusted diluted EPS. These items represent income from continuing operations attributable to Duke Energy, adjusted for the dollar and per share impact of special items. As discussed below, special items include certain charges and credits, which management believes are not indicative of Duke Energy's ongoing performance. Management believes the presentation of adjusted earnings and adjusted diluted EPS provides useful information to investors, as it provides them with an additional relevant comparison of Duke Energy’s performance across periods.
Management uses these non-GAAP financial measures for planning and forecasting, and for reporting financial results to the Duke Energy Board of Directors (Board of Directors), employees, stockholders, analysts and investors. Adjusted diluted EPS is also used as a basis for employee incentive bonuses. The most directly comparable GAAP measures for adjusted earnings and adjusted diluted EPS are Net Income Attributable to Duke Energy Corporation (GAAP Reported Earnings) and Diluted EPS Attributable to Duke Energy Corporation common stockholders (GAAP Reported EPS), respectively.
Special items included in the periods presented include the following, which management believes do not reflect ongoing costs:
Costs to Achieve Mergers represents charges that result from strategic acquisitions.
Cost Savings Initiatives represent severance charges related to company-wide initiatives, excluding merger integration, to standardize processes and systems, leverage technology and workforce optimization.
Regulatory Settlements in 2017 represent charges related to the Levy nuclear project in Florida and the Mayo Zero Liquid Discharge and Sutton combustion turbine projects in North Carolina. The 2015 amount represents charges related to the IGCC Settlement.
Commercial Renewables Impairments represent other-than-temporary, asset and goodwill impairments.
Impacts of the Tax Act represent estimated amounts recognized related to the Tax Cuts and Jobs Act.
Ash Basin Settlement and Penalties represent charges related to Plea Agreements and settlement agreements with regulators and other governmental entities.
Adjusted earnings also include the operating revenuesresults of the nonregulated Midwest generation business and Duke Energy Retail Sales (collectively, the Midwest Generation Disposal Group) and the International Disposal Group, which have been classified as discontinued operations. Management believes inclusion of the operating results of the Disposal Groups within adjusted earnings and adjusted diluted EPS results in a better reflection of Duke Energy's financial performance during the period.
Duke Energy’s adjusted earnings and adjusted diluted EPS may not be comparable to similarly titled measures of another company because other companies may not calculate the measures in the same manner.
Reconciliation of GAAP Reported Amounts to Adjusted Amounts
The following table presents a reconciliation of adjusted earnings and adjusted diluted EPS to the most directly comparable GAAP measures. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| (in millions, except per share amounts) | Earnings | | EPS | | Earnings | | EPS | | Earnings | | EPS |
| GAAP Reported Earnings/EPS | $ | 3,059 |
| | $ | 4.36 |
| | $ | 2,152 |
| | $ | 3.11 |
| | $ | 2,816 |
| | $ | 4.05 |
|
| Adjustments to Reported: | | | | | | | | | | | |
| Costs to Achieve Mergers | 64 |
| | 0.09 |
| | 329 |
| | 0.48 |
| | 60 |
| | 0.09 |
|
| Regulatory Settlements | 98 |
| | 0.14 |
| | — |
| | — |
| | 58 |
| | 0.08 |
|
| Commercial Renewables Impairments | 74 |
| | 0.11 |
| | 45 |
| | 0.07 |
| | — |
| | — |
|
Impacts of the Tax Act(c) | (102 | ) | | (0.14 | ) | | — |
| | — |
| | — |
| | — |
|
| Cost Savings Initiatives | — |
| | — |
| | 57 |
| | 0.08 |
| | 88 |
| | 0.13 |
|
| Ash Basin Settlement and Penalties | — |
| | — |
| | — |
| | — |
| | 11 |
| | 0.02 |
|
Discontinued Operations(a)(b) | 6 |
| | 0.01 |
| | 661 |
| | 0.95 |
| | 119 |
| | 0.17 |
|
| Adjusted Earnings/Adjusted Diluted EPS | $ | 3,199 |
| | $ | 4.57 |
| | $ | 3,244 |
| | $ | 4.69 |
| | $ | 3,152 |
| | $ | 4.54 |
|
| |
| (a) | For 2016, includes a loss on sale of the International Disposal Group. Represents the GAAP reported Loss from Discontinued Operations, less the International Disposal Group operating results, which are included in adjusted earnings. |
| |
| (b) | For 2015, includes the impact of a litigation reserve related to the Midwest Generation Disposal Group. Represents (i) GAAP reported Income from Discontinued Operations, less the International Disposal Group operating results and Midwest Generation Disposal Group operating results, which are included in adjusted earnings, and (ii) a state tax charge resulting from the completion of the sale of the Midwest Generation Disposal Group but not reported as discontinued operations. |
| |
| (c) | The Tax Act reduced the corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018. As the tax change was enacted in 2017, Duke Energy is required to remeasure its existing deferred tax assets and liabilities at the lower rate. For Duke Energy's regulated operations, where the reduction in the net accumulated deferred income tax liability is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability. |
Year Ended December 31, 2017, as compared to 2016
Duke Energy’s full-year 2017 GAAP Reported EPS was $4.36 compared to $3.11 for 2014full-year 2016. In addition to the adjusted diluted EPS drivers discussed below, GAAP Reported EPS in 2017 was higher primarily due to a $0.14 benefit per share related to the Tax Act in 2017, lower costs to achieve the Piedmont merger and 2013 compareda loss on sale and impairments associated with the samesale of the International Disposal Group in 2016, partially offset by charges of $0.14 related to regulatory settlements in Electric Utilities and Infrastructure.
As discussed, management also evaluates financial performance based on adjusted earnings. Duke Energy’s full-year 2017 adjusted diluted EPS was $4.57 compared to $4.69 for full-year 2016. The decrease in adjusted diluted EPS was primarily due to:
Lower regulated electric revenues of $0.26 per share due to less favorable weather in the current year, including lost revenues related to Hurricane Irma;
The prior periods are presented below.year operating results from the International Disposal Group, which was sold in December 2016. The 2016 operating results included a benefit from the valuation of deferred income taxes. See Note 22 to the Consolidated Financial Statements, Income Taxes," for additional information;
|
| | | | | | | | |
| Changes in Operating Revenue - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Residential and commercial customers | | $ | 201.5 |
| | $ | 136.2 |
|
| Industrial customers | | 1.4 |
| | 18.0 |
|
| Power generation customers | | 21.8 |
| | 28.1 |
|
| Secondary market | | 5.4 |
| | 23.8 |
|
| Margin decoupling mechanism | | (39.4 | ) | | (40.8 | ) |
| WNA mechanisms | | (11.4 | ) | | (10.4 | ) |
| IMR mechanisms | | 10.7 |
| | — |
|
| Other | | 1.8 |
| | 0.5 |
|
| Total | | $ | 191.8 |
| | $ | 155.4 |
|
Residential
Higher depreciation and commercial customers – the increase isamortization expense at Electric Utilities and Infrastructure primarily due to higher consumptiondepreciable base.
Partially offset by:
Higher regulated electric revenues from increased pricing and riders driven by new rates in Duke Energy Progress South Carolina, base rate adjustments in Florida and energy efficiency rider revenues in North Carolina, as well as growth in weather-normal retail volumes;
Lower operations, maintenance and other expenses, net of amounts recoverable in rates, at Electric Utilities and Infrastructure resulting from ongoing cost efficiency efforts and lower year-to-date storm costs than the prior year; and
Additional earnings from incremental investments in Atlantic Coast Pipeline, LLC (ACP) and Sabal Trail natural gas pipelines.
Year Ended December 31, 2016, as compared to 2015
Duke Energy’s full-year 2016 GAAP Reported EPS was $3.11 compared to $4.05 for full-year 2015. GAAP Reported EPS was lower primarily due to a $0.93 loss on sale of the International business, which has been presented as discontinued operations. Duke Energy also recorded $0.40 of after-tax costs to achieve the Piedmont merger in 2016, including losses on interest rate swaps related to the acquisition financing. See Note 2, "Acquisitions and Dispositions," for additional information on the Piedmont and International transactions.
As discussed, management also evaluates financial performance based on adjusted earnings. Duke Energy’s full-year 2016 adjusted diluted EPS was $4.69 compared to $4.54 for full-year 2015. The variance in adjusted diluted EPS was primarily due to:
More favorable weather in 2016 compared to 2015;
Increased retail revenues from pricing and riders, including energy efficiency programs;
Strong operations and maintenance cost control at Electric Utilities and Infrastructure; and
Piedmont’s earnings contribution subsequent to the acquisition in October 2016.
Partially offset by:
Higher storm costs at Electric Utilities and Infrastructure due to significant 2016 storms;
Higher interest expense related to additional debt outstanding; and
Higher depreciation and amortization expense at Electric Utilities and Infrastructure primarily due to higher depreciable base.
Segment Results
The remaining information presented in this discussion of results of operations is on a GAAP basis. Management evaluates segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests. Segment income includes intercompany revenues and expenses that are eliminated in the Consolidated Financial Statements.
Duke Energy's segment structure includes the following segments: Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables. The remainder of Duke Energy’s operations is presented as Other. See Note 3 to the Consolidated Financial Statements, “Business Segments,” for additional information on Duke Energy’s segment structure.
Tax Cuts and Jobs Act (the Tax Act)
On December 22, 2017, President Trump signed the Tax Act into law. Among other provisions, the Tax Act lowers the corporate federal income tax rate from 35 percent to 21 percent, limits interest deductions outside of regulated utility operations, and eliminates bonus depreciation for regulated utilities, effective January 1, 2018. The Tax Act also could be amended or subject to technical correction, which could change the financial impacts that were recorded at December 31, 2017, or are expected to be recorded in future periods. See Note 22 to the Consolidated Financial Statements, "Income Taxes," for additional information on the Tax Act. The FERC and state utility commissions will determine the regulatory treatment of the impacts of the Tax Act for the Subsidiary Registrants. Duke Energy's segments’ future results of operations, financial condition and cash flows could be adversely impacted by the Tax Act, subsequent amendments or corrections, or the actions of the FERC, state utility commissions or credit rating agencies related to the Tax Act. Duke Energy is reviewing orders to address the rate treatment of the Tax Act by each state utility commission in which the Subsidiary Registrants operate. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information. Beginning in January 2018, the Subsidiary Registrants will defer the estimated ongoing impacts of the Tax Act that are expected to be returned to customers. See the Credit Ratings section below for additional information on the impact of the Tax Act on the Duke Energy Registrants' credit ratings.
As a result of the Tax Act, Duke Energy revalued its existing deferred tax assets and deferred tax liabilities as of December 31, 2017, to account for the estimated future impact of lower corporate tax rates on these deferred tax amounts. For Duke Energy's regulated operations, where the net reduction in the net accumulated deferred income tax liability is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information on the Tax Act's impact to the regulatory asset and liability accounts. The following table shows the expense (benefit) recorded on Duke Energy's Consolidated Statement of Operations for the year ended December 31, 2017. |
| | | |
| | Impacts of |
| (in millions) | the Tax Act(a)(b) |
Electric Utilities and Infrastructure(c) | $ | (231 | ) |
Gas Utilities and Infrastructure(d)(e) | (26 | ) |
| Commercial Renewables | (442 | ) |
Other(f) | 597 |
|
Total impact of the Tax Act(d) | $ | (102 | ) |
| |
| (a) | Except where noted below, amounts are included within Income Tax Expense From Continuing Operations on the Consolidated Statement of Operations. |
| |
| (b) | See Note 4 and Note 22 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets. |
| |
| (c) | Amount primarily relates to the remeasurement of net deferred tax liabilities that are excluded for ratemaking purposes related to abandoned or impaired assets and certain wholesale fixed rate contracts. |
| |
| (d) | Includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations. |
| |
| (e) | Amount primarily relates to the remeasurement of net deferred tax liabilities that relates to equity method investments and certain wholesale fixed rate contracts. |
| |
| (f) | Amount primarily relates to the remeasurement of Foreign Tax Credits, federal net operating losses and non-regulated deferred tax assets. |
Electric Utilities and Infrastructure |
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | | | Variance |
| | | | Variance |
|
| | | | | | 2017 vs. |
| | | | 2016 vs. |
|
| (in millions) | 2017 |
| | 2016 |
| | 2016 |
| | 2015 |
| | 2015 |
|
| Operating Revenues | $ | 21,331 |
| | $ | 21,366 |
| | $ | (35 | ) | | $ | 21,521 |
| | $ | (155 | ) |
| Operating Expenses | | | | |
|
| | | |
|
|
| Fuel used in electric generation and purchased power | 6,379 |
| | 6,595 |
| | (216 | ) | | 7,308 |
| | (713 | ) |
| Operations, maintenance and other | 5,196 |
| | 5,292 |
| | (96 | ) | | 5,138 |
| | 154 |
|
| Depreciation and amortization | 3,010 |
| | 2,897 |
| | 113 |
| | 2,735 |
| | 162 |
|
| Property and other taxes | 1,079 |
| | 1,021 |
| | 58 |
| | 1,013 |
| | 8 |
|
| Impairment charges | 176 |
| | 16 |
| | 160 |
| | 101 |
| | (85 | ) |
| Total operating expenses | 15,840 |
| | 15,821 |
| | 19 |
| | 16,295 |
| | (474 | ) |
| Gains on Sales of Other Assets and Other, net | 6 |
| | — |
| | 6 |
| | 5 |
| | (5 | ) |
| Operating Income | 5,497 |
| | 5,545 |
| | (48 | ) | | 5,231 |
| | 314 |
|
| Other Income and Expenses | 308 |
| | 303 |
| | 5 |
| | 264 |
| | 39 |
|
| Interest Expense | 1,240 |
| | 1,136 |
| | 104 |
| | 1,074 |
| | 62 |
|
| Income Before Income Taxes | 4,565 |
| | 4,712 |
| | (147 | ) | | 4,421 |
| | 291 |
|
| Income Tax Expense | 1,355 |
| | 1,672 |
| | (317 | ) | | 1,602 |
| | 70 |
|
| Segment Income | $ | 3,210 |
| | $ | 3,040 |
| | $ | 170 |
| | $ | 2,819 |
| | $ | 221 |
|
| | | | | | | | | | |
| Duke Energy Carolinas Gigawatt-Hours (GWh) sales | 87,305 |
| | 88,545 |
| | (1,240 | ) | | 86,950 |
| | 1,595 |
|
| Duke Energy Progress GWh sales | 66,822 |
| | 69,049 |
| | (2,227 | ) | | 64,881 |
| | 4,168 |
|
| Duke Energy Florida GWh sales | 40,591 |
| | 40,404 |
| | 187 |
| | 40,053 |
| | 351 |
|
| Duke Energy Ohio GWh sales | 24,639 |
| | 25,163 |
| | (524 | ) | | 25,439 |
| | (276 | ) |
| Duke Energy Indiana GWh sales | 33,145 |
| | 34,368 |
| | (1,223 | ) | | 33,518 |
| | 850 |
|
| Total Electric Utilities and Infrastructure GWh sales | 252,502 |
| | 257,529 |
| | (5,027 | ) | | 250,841 |
| | 6,688 |
|
| Net proportional MW capacity in operation | 48,828 |
| | 49,295 |
| | (467 | ) | | 50,170 |
| | (875 | ) |
Year Ended December 31, 2017, as Compared to 2016
Electric Utilities and Infrastructure's results were impacted by the Tax Act, growth from investments, lower operations and maintenance expense and higher weather-normal retail sales volumes, partially offset by less favorable weather, impairment charges due to regulatory settlements, increased depreciation and amortization, higher interest expense and higher property and other taxes. The following is a detailed discussion of the variance drivers by line item.
Operating Revenues. The variance was driven primarily by:
a $292 million decrease in retail sales, net of fuel revenue, due to less favorable weather in the current year; and
a $235 million decrease in fuel revenues driven by lower retail sales volumes, lower fuel prices included in rates and changes in the generation mix.
Partially offset by:
a $364 million increase in rider revenues including increased revenues related to energy efficiency programs, Duke Energy Florida’s nuclear asset securitization, Midwest transmission and distribution capital investments and Duke Energy Indiana’s Edwardsport Integrated Gasification Combined Cycle (IGCC) plant, as well as an increase in retail pricing due to base rate adjustments for Duke Energy Florida’s Osprey acquisition and Hines Chillers and the Duke Energy Progress South Carolina rate case;
an $86 million increase in weather-normal sales volumes to customers; and
a $26 million increase in other revenues primarily due to favorable transmission revenues.
Operating Expenses. The variance was driven primarily by:
a $160 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year at Duke Energy Florida and the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year at Duke Energy Progress related to the partial settlement in the North Carolina rate case;
•a $113 million increase in depreciation and amortization expense primarily due to additional plant in service; and
•a $58 million increase in property and other taxes primarily due to higher property taxes.
Partially offset by:
a $216 million decrease in fuel expense (including purchased power) primarily due to lower retail sales and changes in the generation mix; and
a $96 million decrease in operation, maintenance and other expense primarily due to lower plant outage, storm restoration and labor and benefits costs partially offset by higher operational costs that are recoverable in rates.
Interest Expense. The variance was due to higher debt outstanding in the current year and Duke Energy Florida's Crystal River 3 (CR3) regulatory asset debt return ending in June 2016 upon securitization.
Income Tax Expense. The variance was primarily due to a decrease in pretax income and the impact of the Tax Act. The effective tax rates for the years ended December 31, 2017, and 2016 were 29.7 percent and 35.5 percent, respectively. The decrease in the effective tax rate was primarily due to the impact of the Tax Act. See the Tax Cuts and Jobs Act section above for additional information on the Tax Act.
Year Ended December 31, 2016, as Compared to 2015
Electric Utilities and Infrastructure's higher earnings were primarily due to increased pricing and rider revenues, favorable weather, a prior year impairment charge associated with the 2015 Edwardsport IGCC settlement and an increase in wholesale power margins. These impacts were partially offset by increased depreciation and amortization expense, higher interest expense and higher operations and maintenance expense. The following is a detailed discussion of the variance drivers by line item.
Operating Revenues. The variance was driven primarily by:
a $768 million decrease in fuel revenues driven by lower fuel prices included in rates.
Partially offset by:
a $414 million increase in rider revenues including increased revenues related to energy efficiency programs, the additional ownership interest in generating assets acquired from NCEMPA in the third quarter of 2015 and increased revenues related to Duke Energy Indiana’s clean coal equipment, and increased retail electric pricing primarily due to the expiration of the North Carolina cost of removal decrement rider;
a $101 million increase in retail sales, net of fuel revenue, due to favorable weather compared to the prior year; and
a $76 million increase in wholesale power revenues primarily due to additional volumes and capacity charges for customers served under long-term contracts, including the NCEMPA wholesale contract.
Operating Expenses. The variance was driven primarily by:
a $713 million decrease in fuel expense (including purchased power and natural gas purchases for resale) primarily due to lower natural gas and coal prices, and lower volumes of coal and oil, partially offset by higher volumes of natural gas; and
an $85 million decrease in pretax impairment charges in the prior year primarily due to the 2015 Edwardsport IGCC settlement.
Partially offset by:
a $162 million increase in depreciation and amortization expense primarily due to additional plant in service, including the additional ownership interest in generating assets acquired from NCEMPA, as well as the expiration of the North Carolina cost of removal decrement rider; and
a $154 million increase in operations and maintenance expense primarily due to higher environmental and operational costs that are recoverable in rates, increased employee benefit costs, and higher storm restoration costs, partially offset by lower costs due to effective cost control efforts.
Other Income and Expenses. The variance was primarily driven by higher AFUDC equity.
Interest Expense. The variance was due to higher debt outstanding in the current year.
Income Tax Expense. The variance was primarily due to an increase in pretax income. The effective tax rates for the years ended December 31, 2016, and 2015 were 35.5 percent and 36.2 percent, respectively.
Matters Impacting Future Electric Utilities and Infrastructure Results
An order from regulatory authorities disallowing recovery of costs related to closure of ash impoundments could have an adverse impact on Electric Utilities and Infrastructure's financial position, results of operations and cash flows. See Note 4 and Note 9 to the Consolidated Financial Statements, “Regulatory Matters” and "Asset Retirement Obligations," respectively, for additional information.
On May 18, 2016, the North Carolina Department of Environmental Quality (NCDEQ) issued proposed risk classifications for all coal ash surface impoundments in North Carolina. All ash impoundments not previously designated as high priority by the North Carolina Coal Ash Management Act of 2014 (Coal Ash Act) were designated as intermediate risk. Certain impoundments classified as intermediate risk, however, may be reassessed in the future as low risk pursuant to legislation enacted on July 14, 2016. Electric Utilities and Infrastructure's estimated asset retirement obligations (AROs) related to the closure of North Carolina ash impoundments are based upon the mandated closure method or a probability weighting of potential closure methods for the impoundments that may be reassessed to low risk. As the final risk ranking classifications in North Carolina are delineated, final closure plans and corrective action measures are developed and approved for each site, the closure work progresses and the closure method scope and remedial methods are determined, the complexity of work and the amount of coal combustion material could be different than originally estimated and, therefore, could materially impact Electric Utilities and Infrastructure's financial position. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations," for additional information.
Duke Energy is a party to multiple lawsuits and could be subject to fines and other penalties related to operations at certain North Carolina facilities with ash basins. The outcome of these lawsuits and potential fines and penalties could have an adverse impact on Electric Utilities and Infrastructure's financial position, results of operations and cash flows. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.
In the fourth quarter of 2016, Hurricane Matthew caused historic flooding, extensive damage and widespread power outages within the Duke Energy Progress service territory. Duke Energy Progress filed a petition with the North Carolina Utilities Commission (NCUC) requesting an accounting order to defer incremental operation and maintenance and capital costs incurred in response to Hurricane Matthew and other significant 2016 storms. The NCUC will address this request in Duke Energy Progress' currently pending rate case. A final order from the NCUC that disallows the deferral and future recovery of all or a significant portion of the incremental storm restoration costs incurred could result in an adverse impact on Electric Utilities and Infrastructure's financial position, results of operations and cash flows. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
Duke Energy has several rate cases pending. Duke Energy Kentucky filed an electric rate case with the Kentucky Public Service Commission (KPSC) on September 1, 2017, to recover costs of capital investments in generation, transmission and distribution systems and to recover other incremental expenses since its previous rate case. Duke Energy Carolinas and Duke Energy Progress filed general rate cases with the NCUC on August 25, 2017, and June 1, 2017, respectively, to recover costs of complying with Coal Combustion Residuals (CCR) regulations and the Coal Ash Act, as well as costs of capital investments in generation, transmission and distribution systems and any increase in expenditures subsequent to previous rate cases. In March 2017, Duke Energy Ohio filed an electric distribution base rate case application and supporting testimony with the Public Utility Commission of Ohio (PUCO). Electric Utilities and Infrastructure's earnings could be impacted adversely if these rate increases are delayed or denied by the KPSC, NCUC or PUCO. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information.
On August 29, 2017, Duke Energy Florida filed a 2017 Second Revised and Restated Settlement Agreement (2017 Settlement) with the FPSC. On November 20, 2017, the FPSC issued an order to approve the 2017 Settlement. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information about the 2017 Settlement. In accordance with the 2017 Settlement, Duke Energy Florida will not seek recovery of any costs associated with the ongoing Westinghouse contract litigation, which is currently being appealed. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information about the litigation. An unfavorable appeals ruling on that matter could have an adverse impact on Electric Utilities and Infrastructure’s financial position, results of operations and cash flows.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
Gas Utilities and Infrastructure
|
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | | | Variance |
| | | | Variance |
|
| | | | | | 2017 vs. |
| | | | 2016 vs. |
|
| (in millions) | 2017 |
| | 2016 |
| | 2016 |
| | 2015 |
| | 2015 |
|
| Operating Revenues | $ | 1,836 |
| | $ | 901 |
| | $ | 935 |
| | $ | 541 |
| | $ | 360 |
|
| Operating Expenses | | | | |
|
| | | |
|
|
| Cost of natural gas | 632 |
| | 265 |
| | 367 |
| | 141 |
| | 124 |
|
| Operation, maintenance and other | 393 |
| | 186 |
| | 207 |
| | 126 |
| | 60 |
|
| Depreciation and amortization | 231 |
| | 115 |
| | 116 |
| | 79 |
| | 36 |
|
| Property and other taxes | 106 |
| | 70 |
| | 36 |
| | 62 |
| | 8 |
|
| Total operating expenses | 1,362 |
|
| 636 |
| | 726 |
| | 408 |
| | 228 |
|
| (Loss) Gains on Sales of Other Assets and Other, net | — |
| | (1 | ) | | 1 |
| | 6 |
| | (7 | ) |
| Operating Income | 474 |
| | 264 |
| | 210 |
| | 139 |
| | 125 |
|
| Other Income and Expenses | 66 |
| | 24 |
| | 42 |
| | 3 |
| | 21 |
|
| Interest Expense | 105 |
| | 46 |
| | 59 |
| | 25 |
| | 21 |
|
| Income Before Income Taxes | 435 |
| | 242 |
| | 193 |
| | 117 |
| | 125 |
|
| Income Tax Expense | 116 |
| | 90 |
| | 26 |
| | 44 |
| | 46 |
|
| Segment Income | $ | 319 |
| | $ | 152 |
| | $ | 167 |
| | $ | 73 |
| | $ | 79 |
|
| | | | | | | | | | |
Piedmont LDC throughput (dekatherms)(a) | 468,259,777 |
| | 120,908,508 |
| | 347,351,269 |
| | — |
| | 120,908,508 |
|
| Duke Energy Midwest LDC throughput (MCF) | 80,934,836 |
| | 81,870,489 |
| | (935,653 | ) | | 84,523,814 |
| | (2,653,325 | ) |
| |
| (a) | Includes throughput subsequent to Duke Energy's acquisition of Piedmont on October 3, 2016. |
Year Ended December 31, 2017, as Compared to 2016
Gas Utilities and Infrastructure's higher results were primarily due to the inclusion of Piedmont's earnings in the current year as a result of Duke Energy's acquisition of Piedmont on October 3, 2016, as well as additional equity earnings from investments in the ACP and Sabal Trail pipelines.
Operating Revenues. The variance was driven primarily by:
an $884 million increase in operating revenues due to the inclusion of Piedmont's operating revenues beginning in October 2016; and
a $47 million increase in Piedmont's fourth quarter results due to colder weather, higher wholesalenatural gas prices, Integrity Management Rider (IMR) rate adjustments, customer growth and new power generation customers.
Operating Expenses. The variance was driven primarily by:
a $686 million increase in operating expenses due to the inclusion of Piedmont's operating expenses beginning in October 2016; and
a $34 million increase in Piedmont's fourth quarter results primarily due to higher natural gas costs passed through to customers due to the higher price per dekatherm of natural gas.
Other Income and customer growth.Expenses. The increase was driven primarily by higher equity earnings from pipeline investments.
Industrial customers –Interest Expense. The variance was primarily due to the inclusion of Piedmont's interest expense beginning in October 2016.
Income Tax Expense. The variance was primarily due to an increase in pretax income due to the inclusion of Piedmont's earnings beginning in October 2016, partially offset by prior period true-ups. The effective tax rates for the years ended December 31, 2017, and 2016 were 26.7 percent and 37.2 percent, respectively. The decrease in the effective tax rate was primarily due to the prior period true-ups and the impact of the Tax Act. See the Tax Cuts and Jobs Act section above for additional information on the Tax Act.
Year Ended December 31, 2016, as Compared to 2015
Gas Utilities and Infrastructure's higher results were primarily due to the inclusion of Piedmont's earnings subsequent to the merger on October 3, 2016, and higher equity earnings from pipeline investments. Piedmont's earnings included in Gas Utilities and Infrastructure's results were $67 million for the year ended December 31, 2016.
Operating Revenues. The variance was driven primarily by:
a $398 million increase in operating revenues due to the inclusion of Piedmont's operating revenues beginning in October 2016,
Partially offset by:
a $38 million decrease in fuel revenues driven by lower natural gas prices and decreased sales volumes for Midwest operations.
Operating Expenses. The variance was driven primarily by:
a $276 million increase in operating expenses due to the inclusion of Piedmont's operating expenses beginning in October 2016.
Partially offset by:
a $38 million decrease in the cost of natural gas, primarily due to decreased volumes and lower natural gas prices for Midwest operations.
Other Income and Expenses. The increase was driven primarily by higher equity earnings from pipeline investments.
Interest Expense. The variance was primarily due to the inclusion of Piedmont's interest expenses beginning in October 2016.
Income Tax Expense. The variance was primarily due to an increase in pretax income. The effective tax rates for the years ended December 31, 2016, and 2015 were 37.2 percent and 37.6 percent, respectively.
Matters Impacting Future Gas Utilities and Infrastructure Results
Gas Utilities and Infrastructure has a 24 percent ownership interest in Constitution Pipeline Company, LLC (Constitution), a natural gas pipeline project slated to transport natural gas supplies to major northeastern markets. On April 22, 2016, the New York State Department of Environmental Conservation denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution has stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved. As a result of the permitting delays and project uncertainty, total anticipated contributions by Duke Energy can no longer be reasonably estimated. To the extent the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward, an impairment charge of up to the recorded investment in the project, net of salvage value and any cash and working capital returned, may be recorded. Due to the FERC’s January 2018 ruling and the resulting increase in uncertainty, Duke Energy is evaluating the potential to recognize a pretax impairment charge on its investment in Constitution during the first quarter of 2018 of up to the current carrying amount of the investment, net of salvage value and any cash and working capital returned. With the project on hold, funding of project costs has ceased until resolution of legal actions. At December 31, 2017, Duke Energy's investment in Constitution was $81 million. See Note 4 and Note 12 to the Consolidated Financial Statements, "Regulatory Matters," and "Investments in Unconsolidated Affiliates," respectively, for additional information.
Gas Utilities and Infrastructure has a 47 percent ownership interest in ACP, which is building an approximately 600-mile interstate natural gas pipeline intended to transport diverse natural gas supplies into southeastern markets. Affected states (West Virginia, Virginia and North Carolina) have issued certain necessary permits; the project remains subject to other pending federal and state approvals, which will allow full construction activities to begin. In early 2018, the FERC issued series of Partial Notices to Proceed which authorized the project to begin limited construction-related activities along the pipeline route. The project has a targeted in-service date of late 2019. Due to delays in obtaining the required permits to commence construction and the conditions imposed upon the project by the permits, ACP's project manager estimates the project pipeline development costs have increased from a range of $5.0 billion to $5.5 billion to a range of $6.0 billion to $6.5 billion, excluding financing costs. Project construction activities, schedule and final costs are still subject to uncertainty due to potential additional permitting delays, construction productivity and other conditions and risks that could result in potential higher project costs and a potential delay in the targeted in-service date. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information.
Rapidly rising interest rates without timely or adequate updates to the regulated allowed return on equity or failure to achieve the anticipated benefits of the Piedmont merger, including cost savings and growth targets, could significantly impact the estimated fair value of reporting units in Gas Utilities and Infrastructure. In the event of a significant decline in the estimated fair value of the reporting units, goodwill impairment charges could be recorded. The carrying value of goodwill within Gas Utilities and Infrastructure was approximately $1,924 million at December 31, 2017.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
|
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | | | Variance |
| | | | Variance |
|
| | | | | | 2017 vs. |
| | | | 2016 vs. |
|
| (in millions) | 2017 |
| | 2016 |
| | 2016 |
| | 2015 |
| | 2015 |
|
| Operating Revenues | $ | 460 |
| | $ | 484 |
| | $ | (24 | ) | | $ | 286 |
| | $ | 198 |
|
| Operating Expenses | | | | |
|
| | | |
|
|
| Operation, maintenance and other | 267 |
| | 337 |
| | (70 | ) | | 197 |
| | 140 |
|
| Depreciation and amortization | 155 |
| | 130 |
| | 25 |
| | 104 |
| | 26 |
|
| Property and other taxes | 33 |
| | 25 |
| | 8 |
| | 18 |
| | 7 |
|
| Impairment charges | 99 |
| | — |
| | 99 |
| | 3 |
| | (3 | ) |
| Total operating expenses | 554 |
| | 492 |
| | 62 |
| | 322 |
| | 170 |
|
| Gains on Sales of Other Assets and Other, net | 1 |
| | 5 |
| | (4 | ) | | 1 |
| | 4 |
|
| Operating Loss | (93 | ) | | (3 | ) | | (90 | ) | | (35 | ) | | 32 |
|
| Other Income and Expenses | (12 | ) | | (83 | ) | | 71 |
| | 2 |
| | (85 | ) |
| Interest Expense | 87 |
| | 53 |
| | 34 |
| | 44 |
| | 9 |
|
| Loss Before Income Taxes | (192 | ) | | (139 | ) | | (53 | ) | | (77 | ) | | (62 | ) |
| Income Tax Benefit | (628 | ) | | (160 | ) | | (468 | ) | | (128 | ) | | (32 | ) |
| Less: Loss Attributable to Noncontrolling Interests | (5 | ) | | (2 | ) | | (3 | ) | | (1 | ) | | (1 | ) |
| Segment Income | $ | 441 |
| | $ | 23 |
| | $ | 418 |
| | $ | 52 |
| | $ | (29 | ) |
| | | | | | | | | | |
| Renewable plant production, GWh | 8,260 |
| | 7,446 |
| | 814 |
| | 5,577 |
| | 1,869 |
|
| Net proportional MW capacity in operation | 2,907 |
| | 2,892 |
| | 15 |
| | 1,943 |
| | 949 |
|
Year Ended December 31, 2017, as Compared to 2016
Commercial Renewables' higher earnings were primarily due to the Tax Act, partially offset by pretax impairment charges. The following is a detailed discussion of the variance drivers by line item.
Operating Revenues. The decrease was primarily due to lower engineering, procurement and construction revenues from REC Solar, a California-based provider of solar installations acquired by Duke Energy in 2015.
Operating Expenses. The increase was primarily due to $99 million in pretax impairment charges in the current year related to a wholly owned non-contracted wind project and other investments and higher expenses associated with new wind and solar projects, partially offset by lower operations and maintenance expense at REC Solar due to fewer projects under construction. See Notes 10 and 11 to the Consolidated Financial Statements, “Property, Plant and Equipment” and "Goodwill and Intangible Assets," respectively, for additional information.
Other Income and Expenses. The variance was primarily due to a $71 million pretax impairment charge in the prior year related to certain equity method investments. For additional information, see Note 12 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates.”
Interest Expense. The variance was primarily due to new project financings and less capitalized interest due to fewer projects under construction.
Income Tax Benefit.The variance was primarily due to the impact of the Tax Act and higher production tax credits (PTCs), partially offset by lower investment tax credits (ITCs). See the Tax Cuts and Jobs Act section above for additional information on the Tax Act and the impact on the effective tax rate.
Year Ended December 31, 2016, as Compared to 2015
Commercial Renewables' lower earnings were primarily due to an impairment charge related to certain equity method investments in wind projects, partially offset by new wind and solar generation placed in service and improved wind production. The following is a detailed discussion of variance drivers by line item.
Operating Revenues. The variance was primarily due to a $135 million increase due to growth of REC Solar and a $66 million increase from new wind and solar generation placed in service and improved wind production.
Operating Expenses. The variance was primarily due to a $130 million increase in operating expenses due to growth of REC Solar and a $36 million increase in operating expenses due to new wind and solar generation placed in service.
Other Income and Expenses. The variance was due to a $71 million pretax impairment charge related to certain equity method investments in wind projects. See Note 12 to the Consolidated Financial Statements, "Investments in Unconsolidated Affiliates," for additional information.
Income Tax Benefit.The variance was primarily due to a decrease in pretax income and the impact of PTCs for the renewables portfolio.
Matters Impacting Future Commercial Renewables Results
Changes or variability in assumptions used in calculating the fair value of the Commercial Renewables reporting units for goodwill testing purposes, including but not limited to legislative actions related to tax credit extensions, long-term growth rates and discount rates could significantly impact the estimated fair value of the Commercial Renewables reporting units. In the event of a significant decline in the estimated fair value of the Commercial Renewables reporting units, goodwill or other asset impairment charges could be recorded. The carrying value of goodwill within Commercial Renewables was approximately $93 million at December 31, 2017.
Persistently low market pricing for wind resources, primarily in the Electric Reliability Council of Texas West market and the future expiration of tax incentives including ITCs and PTCs could result in adverse impacts to the future results of Commercial Renewables.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
|
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | | | Variance |
| | | | Variance |
|
| | | | | | 2017 vs. |
| | | | 2016 vs. |
|
| (in millions) | 2017 |
| | 2016 |
| | 2016 |
| | 2015 |
| | 2015 |
|
| Operating Revenues | $ | 138 |
| | $ | 117 |
| | $ | 21 |
| | $ | 135 |
| | $ | (18 | ) |
| Operating Expenses | | | | |
|
| | | |
|
|
| Fuel used in electric generation and purchased power | 58 |
| | 51 |
| | 7 |
| | 48 |
| | 3 |
|
| Operation, maintenance and other | 44 |
| | 371 |
| | (327 | ) | | 188 |
| | 183 |
|
| Depreciation and amortization | 131 |
| | 152 |
| | (21 | ) | | 135 |
| | 17 |
|
| Property and other taxes | 14 |
| | 28 |
| | (14 | ) | | 35 |
| | (7 | ) |
| Impairment charges | 7 |
| | 2 |
| | 5 |
| | 3 |
| | (1 | ) |
| Total operating expenses | 254 |
| | 604 |
| | (350 | ) | | 409 |
| | 195 |
|
| Gains on Sales of Other Assets and Other, net | 21 |
| | 23 |
| | (2 | ) | | 18 |
| | 5 |
|
| Operating Loss | (95 | ) | | (464 | ) | | 369 |
| | (256 | ) | | (208 | ) |
| Other Income and Expenses | 127 |
| | 75 |
| | 52 |
| | 98 |
| | (23 | ) |
| Interest Expense | 574 |
| | 693 |
| | (119 | ) | | 393 |
| | 300 |
|
| Loss Before Income Taxes | (542 | ) | | (1,082 | ) | | 540 |
| | (551 | ) | | (531 | ) |
| Income Tax Expense (Benefit) | 353 |
| | (446 | ) | | 799 |
| | (262 | ) | | (184 | ) |
| Less: Income attributable to Noncontrolling Interests | 10 |
| | 9 |
| | 1 |
| | 10 |
| | (1 | ) |
| Net Expense | $ | (905 | ) | | $ | (645 | ) | | $ | (260 | ) | | $ | (299 | ) | | $ | (346 | ) |
Year Ended December 31, 2017, as Compared to 2016
Other’s higher net expense was driven by the Tax Act, partially offset by prior year losses on forward-starting interest rate swaps and other costs related to the Piedmont acquisition, decreased severance expenses, prior year donations to the Duke Energy Foundation and insurance proceeds resulting from settlement of the shareholder litigation related to the Progress Energy merger. The following is a detailed discussion of the variance drivers by line item.
Operating Revenues. The increase was primarily due to higher consumptionOVEC (Ohio Valley Electric Corporation) revenues and prior year customer credits related to Piedmont merger commitments. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information.
Operating Expenses. The decrease was primarily due to lower transaction and integration costs associated with the Piedmont acquisition, prior year severance expenses related to cost savings initiatives, donations to the Duke Energy Foundation in 2016 as well as prior year depreciation expense and other integration costs related to the Progress Energy merger. The Duke Energy Foundation is a nonprofit organization funded by Duke Energy shareholders that makes charitable contributions to selected nonprofits and government subdivisions.
Other Income and Expenses. The increase was primarily driven by insurance proceeds resulting from colder weathersettlement of the shareholder litigation related to the Progress Energy merger, higher earnings from the equity method investment in NMC and increased returns on investments that fund certain employee benefit obligations.
Interest Expense. The decrease was primarily due to prior year losses on forward-starting interest rate swaps related to Piedmont pre-acquisition financing, partially offset by higher interest costs on $3.75 billion of debt issued in August 2016 to fund the acquisition. For additional information see Notes 2, 6 and 14 to the Consolidated Financial Statements, "Acquisitions and Dispositions," "Debt and Credit Facilities" and "Derivatives and Hedging," respectively.
Income Tax Benefit. The variance was primarily due to the impact of the Tax Act and a decrease in pretax loss. See the Tax Cuts and Jobs Act section above for additional information on the Tax Act and the impact on the effective tax rate.
Year Ended December 31, 2016, as Compared to 2015
Other’s higher net expense was driven by costs related to the Piedmont acquisition, higher charitable donations and higher interest expense related to the Piedmont acquisition financing. The following is a detailed discussion of the variance drivers by line item.
Operating Revenues. The decrease was primarily due to customer credits recorded related to Piedmont merger commitments. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information.
Operating Expenses. The increase was primarily due to transaction and integration costs associated with the Piedmont acquisition and increased donations to the Duke Energy Foundation, partially offset by a decrease in severance accruals.
Other Income and Expenses. The variance was primarily due to lower earnings from NMC, partially offset by higher returns on investments that support employee benefit obligations.
Interest Expense. The increase was primarily due to Piedmont acquisition financing, including bridge facility costs and losses on forward-starting interest rate swaps. For additional information see Notes 2 and 14 to the Consolidated Financial Statements, "Acquisitions and Dispositions" and "Derivatives and Hedging," respectively.
Income Tax Benefit. The variance was primarily due to an increase in pretax losses, partially offset by a decrease in the effective tax rate. The effective tax rates for the years ended December 31, 2016, and 2015 were 41.2 percent and 47.5 percent, respectively. The decrease in the effective tax rate was primarily due to the benefit from legal entity restructuring recorded in 2015.
Matters Impacting Future Other Results
Included in Other is Duke Energy Ohio's 9 percent ownership interest in the Ohio Valley Electric Corporation (OVEC), which owns 2,256 MW of coal-fired generation capacity. As a counterparty to an inter-company power agreement (ICPA), Duke Energy Ohio has a contractual arrangement to receive entitlements to capacity and energy from OVEC’s power plants through June 2040 commensurate with its power participation ratio, which is equivalent to Duke Energy Ohio's ownership interest. Costs, including fuel, operating expenses, fixed costs, debt amortization and interest expense, are allocated to counterparties to the ICPA, including Duke Energy Ohio, based on their power participation ratio. The value of the ICPA is subject to variability due to fluctuations in power prices and changes in OVEC’s costs of business. Deterioration in the credit quality or bankruptcy of one or more parties to the ICPA could increase the costs of OVEC. In addition, certain proposed environmental rulemaking costs could result in future increased cost allocations. For information on Duke Energy's regulatory filings related to OVEC, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”
The retired Beckjord generating station (Beckjord), a nonregulated facility retired during 2014, is not subject to the U.S. Environmental Protection Agency (EPA) rule related to the disposal of CCR from electric utilities. However, if costs are incurred as a result of environmental regulations or to mitigate risk associated with on-site storage of coal ash, the costs could have an adverse impact on Other's financial position, results of operations and cash flows.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
(LOSS) INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX |
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | | | Variance |
| | | | Variance |
|
| | | | | | 2017 vs. |
| | | | 2016 vs. |
|
| (in millions) | 2017 |
| | 2016 |
| | 2016 |
| | 2015 |
| | 2015 |
|
| (Loss) Income From Discontinued Operations, net of tax | $ | (6 | ) | | $ | (408 | ) | | $ | 402 |
| | $ | 177 |
| | $ | (585 | ) |
Year Ended December 31, 2017, as Compared to 2016
The variance was primarily driven by the prior year loss on the disposal of Duke Energy's Latin American generation business and an impairment charge related to certain assets in Central America, partially offset by a tax benefit related to historic unremitted foreign earnings and immaterial out of period tax adjustments unrelated to the Disposal Groups. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information.
Year Ended December 31, 2016, as Compared to 2015
The variance was primarily driven by the 2016 loss on the disposal of Duke Energy's Latin American generation business and an impairment charge related to certain assets in Central America, partially offset by a tax benefit related to historic unremitted foreign earnings and immaterial out of period tax adjustments unrelated to the Disposal Groups. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information.
SUBSIDIARY REGISTRANTS
As a result of the Tax Act, the Subsidiary Registrants revalued their deferred tax assets and deferred tax liabilities, as of December 31, 2017, to account for the future impact of lower corporate tax rates on these deferred tax amounts. For the Subsidiary Registrants regulated operations, where the reduction is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters" for additional information on the Tax Act's impact to the regulatory asset and liability accounts. The FERC and state utility commissions will determine the regulatory treatment of the impacts of the Tax Act for the Subsidiary Registrants. The Subsidiary Registrants’ future results of operations, financial condition and cash flows could be adversely impacted by the Tax Act, subsequent amendments or corrections, or the actions of the FERC, state utility commissions or credit rating agencies related to the Tax Act. The change in each Subsidiary Registrant's effective tax rate for the year ended December 31, 2017, was primarily due to the impact of the Tax Act, unless noted below. The following table shows the expense (benefit) recorded on the Subsidiary Registrant's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2017, and the effective tax rate for each Subsidiary Registrant. |
| | | | | | | | | |
| | | | Effective Tax Rate |
| | Impacts of | | Years Ended December 31, | |
| (in millions) | the Tax Act(a)(b) | | 2017 |
| | 2016 |
|
| Duke Energy Carolinas | $ | 15 |
| | 34.9 | % | | 35.2 | % |
| Progress Energy | (246 | ) | (c) | 17.2 | % | | 33.7 | % |
| Duke Energy Progress | (40 | ) | (d) | 29.0 | % | (h) | 33.4 | % |
| Duke Energy Florida | (226 | ) | (c) | 6.1 | % | | 36.9 | % |
| Duke Energy Ohio | (23 | ) | (e) | 23.4 | % | | 28.9 | % |
| Duke Energy Indiana | 55 |
| (f) | 46.0 | % | | 37.1 | % |
| Piedmont | (2 | ) | (d)(g) | 30.8 | % | | 38.3 | % |
| |
| (a) | Except where noted below, amounts are included within Income Tax Expense From Continuing Operations or Income Tax Expense on the Consolidated Statement of Operations and Comprehensive Income. |
| |
| (b) | See Notes 4 and 22 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets. |
| |
| (c) | Amount primarily relates to the remeasurement of deferred tax liabilities that are excluded for ratemaking purposes related to abandoned assets and certain wholesale fixed rate contracts. |
| |
| (d) | Amount primarily relates to the remeasurement of deferred tax liabilities of certain wholesale fixed rate contracts. |
| |
| (e) | Amount primarily relates to the remeasurement of deferred tax assets that are excluded for ratemaking purposes related to a prior transfer of certain electric generating assets. |
| |
| (f) | Amount primarily relates to the remeasurement of deferred tax liabilities that are excluded for ratemaking purposes related to impaired assets. |
| |
| (g) | Includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations and Comprehensive Income. |
| |
| (h) | The decrease in the effective tax rate was primarily due to the impact of the Tax Act and lower North Carolina corporate tax rates. |
DUKE ENERGY CAROLINAS
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Duke Energy Carolinas is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | Variance |
|
| Operating Revenues | $ | 7,302 |
| | $ | 7,322 |
| | $ | (20 | ) |
| Operating Expenses | | | | |
|
|
| Fuel used in electric generation and purchased power | 1,822 |
| | 1,797 |
| | 25 |
|
| Operation, maintenance and other | 1,961 |
| | 2,106 |
| | (145 | ) |
| Depreciation and amortization | 1,090 |
| | 1,075 |
| | 15 |
|
| Property and other taxes | 281 |
| | 276 |
| | 5 |
|
| Impairment charges | — |
| | 1 |
| | (1 | ) |
| Total operating expenses | 5,154 |
| | 5,255 |
| | (101 | ) |
| Gain (Loss) on Sales of Other Assets and Other, net | 1 |
| | (5 | ) | | 6 |
|
| Operating Income | 2,149 |
| | 2,062 |
| | 87 |
|
| Other Income and Expenses, net | 139 |
| | 162 |
| | (23 | ) |
| Interest Expense | 422 |
| | 424 |
| | (2 | ) |
| Income Before Income Taxes | 1,866 |
| | 1,800 |
| | 66 |
|
| Income Tax Expense | 652 |
| | 634 |
| | 18 |
|
| Net Income | $ | 1,214 |
| | $ | 1,166 |
| | $ | 48 |
|
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Carolinas. The below percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Amounts are not weather-normalized. |
| | | | | |
| Increase (Decrease) over prior year | 2017 | | 2016 |
| Residential sales | (4.8 | )% | | 0.1 | % |
| General service sales | (1.8 | )% | | 0.7 | % |
| Industrial sales | (0.8 | )% | | (0.9 | )% |
| Wholesale power sales | 6.3 | % | | 9.8 | % |
| Joint dispatch sales | 18.2 | % | | (2.3 | )% |
| Total sales | (1.4 | )% | | 1.8 | % |
| Average number of customers | 1.5 | % | | 1.4 | % |
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues. The variance was driven primarily by:
a $179 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year.
Partially offset by:
a $74 million increase in rider revenues and retail pricing primarily related to energy efficiency programs;
a $41 million increase in weather-normal sales volumes to retail customers, net of fuel revenues;
a $30 million increase in fuel revenues primarily due to changes in generation mix partially offset by lower retail sales; and
a $7 million increase in wholesale power revenues, net of sharing and fuel, primarily due to additional volumes for customers served under long-term contracts.
Operating Expenses.The variance was driven primarily by:
a $145 million decrease in operations, maintenance and other expense primarily due to lower expenses at generating plants, lower costs associated with merger commitments related to the Piedmont acquisition in 2016, lower severance expenses, and lower employee benefit costs, partially offset by higher energy efficiency program costs.
Partially offset by:
a $25 million increase in fuel expense (including purchased power) primarily due to changes in generation mix, partially offset by lower retail sales; and
a $15 million increase in depreciation and amortization expense primarily due to additional plant in service, partially offset by lower amortization of certain regulatory assets.
Other Income and Expenses.The variance was primarily due to a decrease in recognition of post in-service equity returns for projects that had been completed prior to being reflected in customer rates.
Income Tax Expense. The variance was primarily due to an increase in pretax income and the impact of the Tax Act, offset by the impact of research credits and the manufacturing deduction. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Matters Impacting Future Results
An order from regulatory authorities disallowing recovery of costs related to closure of ash impoundments could have an adverse impact on Duke Energy Carolinas' financial position, results of operations and cash flows. See Notes 4 and 9 to the Consolidated Financial Statements, “Regulatory Matters” and "Asset Retirement Obligations," respectively, for additional information.
On May 18, 2016, the NCDEQ issued proposed risk classifications for all coal ash surface impoundments in North Carolina. All ash impoundments not previously designated as high priority by the Coal Ash Act were designated as intermediate risk. Certain impoundments classified as intermediate risk, however, may be reassessed in the future as low risk pursuant to legislation enacted on July 14, 2016. Duke Energy Carolinas' estimated AROs related to the closure of North Carolina ash impoundments are based upon the mandated closure method or a probability weighting of potential closure methods for the impoundments that may be reassessed to low risk. As the final risk ranking classifications in North Carolina are delineated, final closure plans and corrective action measures are developed and approved for each site, the closure work progresses, and the closure method scope and remedial action methods are determined, the complexity of work and the amount of coal combustion material could be different than originally estimated and, therefore, could materially impact Duke Energy Carolinas' financial position. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations," for additional information.
Duke Energy Carolinas is a party to multiple lawsuits and subject to fines and other penalties related to operations at certain North Carolina facilities with ash basins. The outcome of these lawsuits, fines and penalties could have an adverse impact on Duke Energy Carolinas’ financial position, results of operations and cash flows. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.
Duke Energy Carolinas filed a general rate case on August 25, 2017, to recover costs of complying with CCR regulations and the Coal Ash Act, as well as costs of capital investments in generation, transmission and distribution systems and any increase in expenditures subsequent to previous rate cases. Duke Energy Carolinas' earnings could be adversely impacted if the rate increase is delayed or denied by the NCUC.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
PROGRESS ENERGY
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Progress Energy is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | Variance |
|
| Operating Revenues | $ | 9,783 |
| | $ | 9,853 |
| | $ | (70 | ) |
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 3,417 |
| | 3,644 |
| | (227 | ) |
| Operation, maintenance and other | 2,220 |
| | 2,386 |
| | (166 | ) |
| Depreciation and amortization | 1,285 |
| | 1,213 |
| | 72 |
|
| Property and other taxes | 503 |
| | 487 |
| | 16 |
|
| Impairment charges | 156 |
| | 7 |
| | 149 |
|
| Total operating expenses | 7,581 |
| | 7,737 |
| | (156 | ) |
| Gains on Sales of Other Assets and Other, net | 26 |
| | 25 |
| | 1 |
|
| Operating Income | 2,228 |
| | 2,141 |
| | 87 |
|
| Other Income and Expenses, net | 128 |
| | 114 |
| | 14 |
|
| Interest Expense | 824 |
| | 689 |
| | 135 |
|
| Income From Continuing Operations Before Income Taxes | 1,532 |
| | 1,566 |
| | (34 | ) |
| Income Tax Expense From Continuing Operations | 264 |
| | 527 |
| | (263 | ) |
| Income from Continuing Operations | 1,268 |
| | 1,039 |
| | 229 |
|
| Income from Discontinued Operations, net of tax | — |
| | 2 |
| | (2 | ) |
| Net Income | 1,268 |
| | 1,041 |
| | 227 |
|
| Less: Net Income Attributable to Noncontrolling Interests | 10 |
| | 10 |
| | — |
|
| Net Income Attributable to Parent | $ | 1,258 |
| | $ | 1,031 |
| | $ | 227 |
|
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues. The variance was driven primarily by:
a $231 million decrease in fuel revenues primarily due to lower retail sales and changes in generation mix at Duke Energy Progress; and
an $87 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year.
Partially offset by:
a $108 million increase in retail pricing primarily due to Duke Energy Florida’s base rate adjustment for the Osprey Acquisition and the completion of the Hines Energy Complex Chiller Uprate Project, as well as the Duke Energy Progress South Carolina rate case;
a $76 million increase in rider revenues related to energy efficiency programs at Duke Energy Progress, as well as nuclear asset securitization beginning in July 2016 and extended uprate project revenues beginning in 2017 at Duke Energy Florida; and
a $51 million increase in weather-normal sales volumes to retail customers.
Operating Expenses.The variance was driven primarily by:
a $227 million decrease in fuel expense and purchased power primarily due to lower retail sales and changes in generation mix at Duke Energy Progress; and
a $166 million decrease in operations, maintenance and other expense primarily due to lower plant outage, storm restoration and labor costs.
Partially offset by:
a $149 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year at Duke Energy Florida and the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year at Duke Energy Progress related to the partial settlement in the North Carolina rate case; and
a $72 million increase in depreciation and amortization expense primarily due to additional plant in service, as well as nuclear regulatory asset amortization at Duke Energy Florida.
Interest Expense. The variance was due to higher debt outstanding, as well as interest charges on North Carolina fuel over collections at Duke Energy Progress and lower debt returns driven by the CR3 regulatory asset debt return ending in June 2016 upon securitization at Duke Energy Florida.
Income Tax Expense. The variance was primarily due to the impact of the Tax Act. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Matters Impacting Future Results
An order from regulatory authorities disallowing recovery of costs related to closure of ash impoundments could have an adverse impact on Progress Energy’s financial position, results of operations and cash flows. See Notes 4 and 9 to the Consolidated Financial Statements, “Regulatory Matters” and "Asset Retirement Obligations," respectively, for additional information.
On May 18, 2016, the NCDEQ issued proposed risk classifications for all coal ash surface impoundments in North Carolina. All ash impoundments not previously designated as high priority by the Coal Ash Act were designated as intermediate risk. Certain impoundments classified as intermediate risk, however, may be reassessed in the future as low risk pursuant to legislation enacted on July 14, 2016. Progress Energy's estimated AROs related to the closure of North Carolina ash impoundments are based upon the mandated closure method or a probability weighting of potential closure methods for the impoundments that may be reassessed to low risk. As the final risk ranking classifications in North Carolina are delineated, final closure plans and corrective action measures are developed and approved for each site, the closure work progresses, and the closure method scope and remedial action methods are determined, the complexity of work and the amount of coal combustion material could be different than originally estimated and, therefore, could materially impact Progress Energy's financial position. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations," for additional information.
Duke Energy Progress is a party to multiple lawsuits and subject to fines and other penalties related to operations at certain North Carolina facilities with ash basins. The outcome of these lawsuits, fines and penalties could have an adverse impact on Progress Energy’s financial position, results of operations and cash flows. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.
In the fourth quarter of 2016, Hurricane Matthew caused historic flooding, extensive damage and widespread power outages within the Duke Energy Progress service territory. Duke Energy Progress filed a petition with the North Carolina Utilities Commission (NCUC) requesting an accounting order to defer incremental operation and maintenance and capital costs incurred in response to Hurricane Matthew and other significant 2016 storms. The NCUC will address this request in Duke Energy Progress' currently pending rate case. A final order from the NCUC that disallows the deferral and future recovery of all or a significant portion of the incremental storm restoration costs incurred could result in an adverse impact on Electric Utilities and Infrastructure's financial position, results of operations and cash flows. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
Duke Energy Progress filed a general rate case with the NCUC on June 1, 2017. Duke Energy Progress will seek to recover costs of complying with CCR regulations and the Coal Ash Act, as well as costs of capital investments in generation, transmission and distribution systems and any increase in expenditures subsequent to previous rate cases. Progress Energy's earnings could be adversely impacted if the rate increase is delayed or denied by the NCUC.
On August 29, 2017, Duke Energy Florida filed the 2017 Settlement with the FPSC. On November 20, 2017, the FPSC issued an order to approve the 2017 Settlement. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information about the 2017 Settlement. In accordance with the 2017 Settlement, Duke Energy Florida will not seek recovery of any costs associated with the ongoing Westinghouse contract litigation, which is currently being appealed. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies” for additional information about the litigation. An unfavorable appeals ruling on that matter could have an adverse impact on Electric Utilities and Infrastructure’s financial position, results of operations and cash flows.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
DUKE ENERGY PROGRESS
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Duke Energy Progress is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | Variance |
|
| Operating Revenues | $ | 5,129 |
| | $ | 5,277 |
| | $ | (148 | ) |
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 1,609 |
| | 1,830 |
| | (221 | ) |
| Operation, maintenance and other | 1,389 |
| | 1,504 |
| | (115 | ) |
| Depreciation and amortization | 725 |
| | 703 |
| | 22 |
|
| Property and other taxes | 156 |
| | 156 |
| | — |
|
| Impairment charges | 19 |
| | 1 |
| | 18 |
|
| Total operating expenses | 3,898 |
| | 4,194 |
| | (296 | ) |
| Gains on Sales of Other Asset and Other, net | 4 |
| | 3 |
| | 1 |
|
| Operating Income | 1,235 |
| | 1,086 |
| | 149 |
|
| Other Income and Expenses, net | 65 |
| | 71 |
| | (6 | ) |
| Interest Expense | 293 |
| | 257 |
| | 36 |
|
| Income Before Income Taxes | 1,007 |
| | 900 |
| | 107 |
|
| Income Tax Expense | 292 |
| | 301 |
| | (9 | ) |
| Net Income | $ | 715 |
| | $ | 599 |
| | $ | 116 |
|
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Progress. The below percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Amounts are not weather-normalized. |
| | | | | |
| Increase (Decrease) over prior year | 2017 |
| | 2016 |
|
| Residential sales | (2.6 | )% | | (1.5 | )% |
| General service sales | (1.3 | )% | | 0.2 | % |
| Industrial sales | 1.1 | % | | (0.1 | )% |
| Wholesale power sales | (2.9 | )% | | 18.4 | % |
| Joint dispatch sales | (17.1 | )% | | 17.7 | % |
| Total sales | (3.2 | )% | | 6.4 | % |
| Average number of customers | 1.4 | % | | 1.3 | % |
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues.The variance was driven primarily by:
a $238 million decrease in fuel revenues due to lower retail sales and changes in generation mix; and
a $37 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year, partially offset by lower lost revenues related to hurricanes in the current year.
Partially offset by:
a $40 million increase in rider revenues primarily due to energy efficiency programs;
a $38 million increase in retail sales due to the South Carolina rate case; and
a $31 million increase in wholesale power revenues, net of fuel, primarily due to higher peak demand.
Operating Expenses.The variance was driven primarily by:
a $221 million decrease in fuel used in electric generation and purchased power primarily due to lower retail sales and changes in generation mix; and
a $115 million decrease in operation, maintenance and other expense primarily due to lower nuclear outage costs and lower storm restoration costs.
Partially offset by:
a $22 million increase in depreciation and amortization expense primarily due to additional plant in service; and
an $18 million increase in impairment charges primarily due to the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year related to the partial settlement in the North Carolina rate case.
Interest Expense. The variance was due to higher debt outstanding, as well as interest charges on North Carolina fuel overcollections.
Income Tax Expense. The variance was primarily due to the impact of the Tax Act and lower North Carolina corporate tax rates, partially offset by an increase in pretax net income. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Matters Impacting Future Results
An order from regulatory authorities disallowing recovery of costs related to closure of ash impoundments could have an adverse impact on Duke Energy Progress’ financial position, results of operations and cash flows. See Notes 4 and 9 to the Consolidated Financial Statements, “Regulatory Matters” and "Asset Retirement Obligations," respectively, for additional information.
On May 18, 2016, the NCDEQ issued proposed risk classifications for all coal ash surface impoundments in North Carolina. All ash impoundments not previously designated as high priority by the Coal Ash Act were designated as intermediate risk. Certain impoundments classified as intermediate risk, however, may be reassessed in the future as low risk pursuant to legislation enacted on July 14, 2016. Duke Energy Progress' estimated AROs related to the closure of North Carolina ash impoundments are based upon the mandated closure method or a probability weighting of potential closure methods for the impoundments that may be reassessed to low risk. As the final risk ranking classifications in North Carolina are delineated, final closure plans and corrective action measures are developed and approved for each site, the closure work progresses, and the closure method scope and remedial action methods are determined, the complexity of work and the amount of coal combustion material could be different than originally estimated and, therefore, could materially impact Duke Energy Progress' financial position. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations," for additional information.
Duke Energy Progress is a party to multiple lawsuits and subject to fines and other penalties related to operations at certain North Carolina facilities with ash basins. The outcome of these lawsuits, fines and penalties could have an adverse impact on Duke Energy Progress’ financial position, results of operations and cash flows. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information.
In the fourth quarter of 2016, Hurricane Matthew caused historic flooding, extensive damage and widespread power outages within the Duke Energy Progress service territory. Duke Energy Progress filed a petition with the North Carolina Utilities Commission (NCUC) requesting an accounting order to defer incremental operation and maintenance and capital costs incurred in response to Hurricane Matthew and other significant 2016 storms. The NCUC will address this request in Duke Energy Progress' currently pending rate case. A final order from the NCUC that disallows the deferral and future recovery of all or a significant portion of the incremental storm restoration costs incurred could result in an adverse impact on Electric Utilities and Infrastructure's financial position, results of operations and cash flows. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
Duke Energy Progress filed a general rate case with the NCUC on June 1, 2017. Duke Energy Progress will seek to recover costs of complying with CCR regulations and the Coal Ash Act, as well as costs of capital investments in generation, transmission and distribution systems and any increase in expenditures subsequent to previous rate cases. Duke Energy Progress' earnings could be adversely impacted if the rate increase is delayed or denied by the NCUC. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
DUKE ENERGY FLORIDA
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Duke Energy Florida is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | Variance |
|
| Operating Revenues | $ | 4,646 |
| | $ | 4,568 |
| | $ | 78 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 1,808 |
| | 1,814 |
| | (6 | ) |
| Operation, maintenance and other | 818 |
| | 865 |
| | (47 | ) |
| Depreciation and amortization | 560 |
| | 509 |
| | 51 |
|
| Property and other taxes | 347 |
| | 333 |
| | 14 |
|
| Impairment charges | 138 |
| | 6 |
| | 132 |
|
| Total operating expenses | 3,671 |
| | 3,527 |
| | 144 |
|
| Gains on Sales of Other Asset and Other, net | 1 |
| | — |
| | 1 |
|
| Operating Income | 976 |
| | 1,041 |
| | (65 | ) |
| Other Income and Expenses, net | 61 |
| | 44 |
| | 17 |
|
| Interest Expense | 279 |
| | 212 |
| | 67 |
|
| Income Before Income Taxes | 758 |
| | 873 |
| | (115 | ) |
| Income Tax Expense | 46 |
| | 322 |
| | (276 | ) |
| Net Income | $ | 712 |
| | $ | 551 |
| | $ | 161 |
|
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Florida. The below percentages for retail customer classes represent billed sales only. Wholesale power sales include both billed and unbilled sales. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Amounts are not weather-normalized. |
| | | | | |
| Increase (Decrease) over prior year | 2017 |
| | 2016 |
|
| Residential sales | (2.3 | )% | | 1.7 | % |
| General service sales | (1.3 | )% | | (0.1 | )% |
| Industrial sales | (2.4 | )% | | (2.9 | )% |
| Wholesale power sales | 20.1 | % | | 35.2 | % |
| Total sales | 0.5 | % | | 0.9 | % |
| Average number of customers | 1.6 | % | | 1.5 | % |
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues. The variance was driven primarily by:
a $70 million increase in retail pricing primarily due to the base rate adjustment for the Osprey acquisition and the completion of the Hines Energy Complex Chiller Uprate Project;
a $45 million increase in weather-normal sales volumes to retail customers in the current year; and
a $36 million increase in rider revenues primarily due to nuclear asset securitization beginning in July 2016 and extended power uprate project revenues beginning in 2017.
Partially offset by:
a $50 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year, including lost revenues related to Hurricane Irma; and
a $34 million decrease in wholesale power revenues primarily due to contracts that expired in the prior year.
Operating Expenses. The variance was driven primarily by:
a $132 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year; and
a $51 million increase in depreciation and amortization expense primarily due to nuclear regulatory asset amortization, as well as additional plant in service.
Partially offset by:
a $47 million decrease in operations and maintenance expense primarily due to lower planned outage costs, lower severance expenses and lower employee benefit costs, partially offset by higher storm restoration costs in the current year.
Other Income and Expenses. The variance was primarily driven by higher AFUDC equity.
Interest Expense. The variance was primarily due to higher debt outstanding and lower debt returns driven by the Crystal River Unit 3 regulatory asset debt return ending in June 2016 upon securitization.
Income Tax Expense.The variance was primarily due to the impact of the Tax Act and lower pretax earnings. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Matters Impacting Future Results
On August 29, 2017, Duke Energy Florida filed the 2017 Settlement with the FPSC. On November 20, 2017, the FPSC issued an order to approve the 2017 Settlement. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information about the 2017 Settlement. In accordance with the 2017 Settlement, Duke Energy Florida will not seek recovery of any costs associated with the ongoing Westinghouse contract litigation, which is currently being appealed. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies” for additional information about the litigation. An unfavorable appeals ruling on that matter could have an adverse impact on Electric Utilities and Infrastructure’s financial position, results of operations and cash flows.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
DUKE ENERGY OHIO
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Duke Energy Ohio is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| 2016 |
| Variance |
|
| Operating Revenues | | |
|
|
| Regulated electric | $ | 1,373 |
| $ | 1,410 |
| $ | (37 | ) |
| Nonregulated electric and other | 42 |
| 31 |
| 11 |
|
| Regulated natural gas | 508 |
| 503 |
| 5 |
|
| Total operating revenues | 1,923 |
| 1,944 |
| (21 | ) |
| Operating Expenses | | | |
| Fuel used in electric generation and purchased power – regulated | 369 |
| 442 |
| (73 | ) |
| Fuel used in electric generation and purchased power – nonregulated | 58 |
| 51 |
| 7 |
|
| Cost of natural gas | 107 |
| 103 |
| 4 |
|
| Operation, maintenance and other | 524 |
| 512 |
| 12 |
|
| Depreciation and amortization | 261 |
| 233 |
| 28 |
|
| Property and other taxes | 278 |
| 258 |
| 20 |
|
| Impairment charges | 1 |
| — |
| 1 |
|
| Total operating expenses | 1,598 |
| 1,599 |
| (1 | ) |
| Gains on Sales of Other Assets and Other, net | 1 |
| 2 |
| (1 | ) |
| Operating Income | 326 |
| 347 |
| (21 | ) |
| Other Income and Expenses, net | 17 |
| 9 |
| 8 |
|
| Interest Expense | 91 |
| 86 |
| 5 |
|
| Income from Continuing Operations Before Income Taxes | 252 |
| 270 |
| (18 | ) |
| Income Tax Expense from Continuing Operations | 59 |
| 78 |
| (19 | ) |
| Income from Continuing Operations | 193 |
| 192 |
| 1 |
|
| (Loss) Income from Discontinued Operations, net of tax | (1 | ) | 36 |
| (37 | ) |
| Net Income | $ | 192 |
| $ | 228 |
| $ | (36 | ) |
The following table shows the percent changes in GWh sales of electricity, dekatherms of natural gas delivered and average number of electric and natural gas customers for Duke Energy Ohio. The below percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Amounts are not weather-normalized. |
| | | | | | | | | | | |
| | Electric | | Natural Gas |
| Increase (Decrease) over prior year | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| Residential sales | (4.0 | )% | | 0.7 | % | | (2.6 | )% | | (7.8 | )% |
| General service sales | (3.1 | )% | | 1.3 | % | | 0.7 | % | | (3.6 | )% |
| Industrial sales | (2.7 | )% | | (0.7 | )% | | (2.8 | )% | | (5.1 | )% |
| Wholesale electric power sales | 65.7 | % | | (53.9 | )% | | n/a |
| | n/a |
|
| Other natural gas sales | n/a |
| | n/a |
| | (0.3 | )% | | 6.2 | % |
| Total sales | (2.1 | )% | | (1.1 | )% | | (1.1 | )% | | (3.1 | )% |
| Average number of customers | 0.8 | % | | 0.8 | % | | 0.7 | % | | 0.5 | % |
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues. The variance was driven primarily by:
a $69 million decrease in fuel revenues primarily due to lower electric fuel costs and a decrease in electric and natural gas sales volumes; and
a $16 million decrease in electric retail sales, net of fuel revenues, due to less favorable weather in the current year.
Partially offset by:
a $38 million increase in rider revenues primarily due to growth in energy efficiency programs and a rate increase for the distribution capital investment rider, partially offset by a decrease in the percentage of income payment plan rider due to a rate decrease;
a $10 million increase in PJM Interconnection, LLC (PJM) transmission revenues;
a $9 million increase in other revenues related to OVEC; and
a $6 million increase in non-native sales for resale.
Operating Expenses. The variance was driven by:
a $66 million decrease in fuel expense, primarily due to lower sales volumes and lower electric fuel costs.
Partially offset by:
a $28 million increase in depreciation and amortization expense due to additional plant in service and a true-up related to SmartGrid assets in the prior year;
a $20 million increase in property and other taxes due to higher property taxes; and
a $12 million increase in operations, maintenance and other expense primarily due to higher energy efficiency program costs and higher transmission and distribution operations costs; partially offset by lower fossil/hydro operations costs due to timing of outage schedules.
Income Tax Expense. The variance was primarily due to the impact of the Tax Act. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Income from Discontinued Operations, Net of Tax. The variance was primarily driven by a prior year income tax benefit resulting from immaterial out of period deferred tax liability adjustments related to the Midwest Generation Disposal Group. See Note 2 to the Consolidated Financial Statements, "Acquisitions and Dispositions," for additional information.
Matters Impacting Future Results
An order from regulatory authorities disallowing recovery of costs related to closure of ash basins could have an adverse impact on Duke Energy Ohio's financial position, results of operations and cash flows. See Notes 4 and 9 to the Consolidated Financial Statements, “Regulatory Matters” and "Asset Retirement Obligations," respectively, for additional information.
Duke Energy Ohio’s nonregulated Beckjord station, a facility retired during 2014, is not subject to the EPA rule related to the disposal of CCR from electric utilities. However, if costs are incurred as a result of environmental regulations or to mitigate risk associated with on-site storage of coal ash at the facility, the costs could have an adverse impact on Duke Energy Ohio's financial position, results of operations and cash flows.
Duke Energy Ohio has a 9 percent ownership interest in OVEC, which owns 2,256 MW of coal-fired generation capacity. As a counterparty to an ICPA, Duke Energy Ohio has a contractual arrangement to receive entitlements to capacity and energy from OVEC’s power plants through June 2040 commensurate with its power participation ratio, which is equivalent to Duke Energy Ohio’s ownership interest. Costs, including fuel, operating expenses, fixed costs, debt amortization and interest expense, are allocated to counterparties to the ICPA, including Duke Energy Ohio, based on their power participation ratio. The value of the ICPA is subject to variability due to fluctuations in power prices and changes in OVEC’s costs of business. Deterioration in the credit quality or bankruptcy of one or more parties to the ICPA could increase the costs of OVEC. In addition, certain proposed environmental rulemaking costs could result in future increased cost allocations.
On March 2, 2017, Duke Energy Ohio filed an electric distribution base rate application with the PUCO to address recovery of electric distribution system capital investments and any increase in expenditures subsequent to previous rate cases. The application also includes requests to continue certain current riders and establish new riders related to LED Outdoor Lighting Service and regulatory mandates. Duke Energy Ohio's earnings could be adversely impacted if the rate case and requested riders are delayed or denied by the PUCO. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information.
On September 1, 2017, Duke Energy Kentucky filed a base rate case with the KPSC to recover costs of capital investments in generation, transmission and distribution systems and to recover other incremental expenses since its last rate case filed in 2006. The application also includes request to establish new riders. Duke Energy Kentucky’s earnings could be adversely impacted if the rate increase is delayed or denied by the KPSC.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
DUKE ENERGY INDIANA
Introduction
Management’s Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended December 31, 2017, 2016 and 2015.
Basis of Presentation
The results of operations and variance discussion for Duke Energy Indiana is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| 2016 |
| Variance |
|
| Operating Revenues | $ | 3,047 |
| $ | 2,958 |
| $ | 89 |
|
| Operating Expenses | | | |
| Fuel used in electric generation and purchased power | 966 |
| 909 |
| 57 |
|
| Operation, maintenance and other | 733 |
| 723 |
| 10 |
|
| Depreciation and amortization | 458 |
| 496 |
| (38 | ) |
| Property and other taxes | 76 |
| 58 |
| 18 |
|
| Impairment charges | 18 |
| 8 |
| 10 |
|
| Total operating expenses | 2,251 |
| 2,194 |
| 57 |
|
| Gains on Sales of Other Assets and Other, net | — |
| 1 |
| (1 | ) |
| Operating Income | 796 |
| 765 |
| 31 |
|
| Other Income and Expenses, net | 37 |
| 22 |
| 15 |
|
| Interest Expense | 178 |
| 181 |
| (3 | ) |
| Income Before Income Taxes | 655 |
| 606 |
| 49 |
|
| Income Tax Expense | 301 |
| 225 |
| 76 |
|
| Net Income | $ | 354 |
| $ | 381 |
| $ | (27 | ) |
The following table shows the percent changes in GWh sales and average number of customers for Duke Energy Indiana. The below percentages for retail customer classes represent billed sales only. Total sales includes billed and unbilled retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Amounts are not weather-normalized. |
| | | | | |
| Increase (Decrease) over prior year | 2017 |
| | 2016 |
|
| Residential sales | (3.8 | )% | | (0.4 | )% |
| General service sales | (2.4 | )% | | 0.7 | % |
| Industrial sales | 0.3 | % | | 0.4 | % |
| Wholesale power sales | (10.5 | )% | | 10.8 | % |
| Total sales | (3.6 | )% | | 2.5 | % |
| Average number of customers | 0.8 | % | | 1.1 | % |
Year Ended December 31, 2017, as Compared to 2016
Operating Revenues.The variance was driven primarily by:
a $67 million increase in rate rider revenues primarily related to the Edwardsport IGCC plant, the Transmission, Distribution and Storage System Improvement Charge (TDSIC) and energy efficiency programs; and
a $48 million increase in fuel revenues primarily due to higher purchased power costs passed through to customers slightlyand higher financial transmission rights (FTR) revenues.
Partially offset by decreased transportation revenues.by:
Power generation customers –a $13 million decrease in retail sales due to less favorable weather in the increase iscurrent year; and
a $13 million decrease in wholesale power revenues, net of fuel, primarily due to increased transportation services.a decrease in demand rates and contracts that expired in the current year.
Secondary market – theOperating Expenses. The variance was driven primarily by:
a $57 million increase isin fuel used in electric generation and purchased power expenses, primarily due to higher margin salespurchased power volumes, partially offset by favorable fuel prices;
an $18 million increase in property and other taxes primarily due to higher franchise taxes;
a $10 million increase in operations, maintenance and other expense primarily due to growth in energy efficiency programs and higher transmission costs; and
a $10 million increase in impairments and other charges primarily due to the impairment of certain metering equipment not recoverable in customer rates.
Partially offset by:
a $38 million decrease in depreciation and amortization primarily due to the recognition of certain asset retirement obligations in 2016 that were subsequently deferred in 2017, partially offset by new IGCC rates that result in a lower deferral amount and higher depreciation due to additional plant in service.
Other Income and Expense. The variance was driven primarily by higher AFUDC equity.
Income Tax Expense. The variance was primarily due to the impact of the Tax Act and an increase in pretax income. See the Subsidiary Registrants section above for additional information on the Tax Act and the impact on the effective tax rate.
Matters Impacting Future Results
On April 17, 2015, the EPA published in the Federal Register a rule to regulate the disposal of CCR from electric utilities as solid waste. Duke Energy Indiana has interpreted the rule to identify the coal ash basin sites impacted and has assessed the amounts of coal ash subject to the rule and a method of compliance. Duke Energy Indiana's interpretation of the requirements of the CCR rule is subject to potential legal challenges and further regulatory approvals, which could result in additional ash basin closure requirements, higher costs of compliance and greater AROs. Additionally, Duke Energy Indiana has retired facilities that are not subject to the CCR rule. Duke Energy Indiana may incur costs at these facilities to comply with environmental regulations or to mitigate risks associated with on-site storage of coal ash. An order from regulatory authorities disallowing recovery of costs related to sustained colder-than-normal weatherclosure of ash basins could have an adverse impact on Duke Energy Indiana's financial position, results of operations and increased wholesale market volatility. Secondary market transactions consist of off-system salescash flows. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
In August 2016, the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement between Duke Energy Indiana and capacity releasemultiple parties that resolves all disputes, claims and asset management arrangements and are part of our regulatory gas supply management program with regulatory approved sharing mechanisms between our utility customers and our shareholders.
Margin decoupling mechanism –issues from the decrease is primarilyIURC proceedings related to colder weatherpost-commercial operating performance and recovery of ongoing operating and capital costs at the Edwardsport IGCC generating facility. The settlement agreement imposed a cost cap for retail recoverable operations and maintenance costs through 2017. An inability to manage future operating costs may result in North Carolina. As discussedunfavorable orders that could have an adverse impact on Duke Energy Indiana's financial position, results of operations and cash flows.
Within this Item 7, see the Tax Cuts and Jobs Act above as well as Liquidity and Capital Resources below for risks associated with the Tax Act.
PIEDMONT
Introduction
Management’s Discussion and Analysis should be read in “Financial Conditionconjunction with the accompanying Consolidated Financial Statements and Liquidity,”Notes for the year ended December 31, 2017, Piedmont's Annual Report on Form 10-K for the year ended October 31, 2016, and the Form 10-QT as of December 31, 2016, for the transition period from November 1, 2016 to December 31, 2016. The unaudited results of operations for the year ended December 31, 2016, was derived from data previously reported in the reports noted above.
Basis of Presentation
The results of operations and variance discussion for Piedmont is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | Variance |
|
| Operating Revenues | | | | | |
| Regulated natural gas | $ | 1,319 |
| | $ | 1,201 |
| | $ | 118 |
|
| Nonregulated natural gas and other | 9 |
| | 10 |
| | (1 | ) |
| Total operating revenues | 1,328 |
| | 1,211 |
| | 117 |
|
| Operating Expenses | | | | | |
| Cost of natural gas | 524 |
| | 451 |
| | 73 |
|
| Operation, maintenance and other | 315 |
| | 353 |
| | (38 | ) |
| Depreciation and amortization | 148 |
| | 138 |
| | 10 |
|
| Property and other taxes | 48 |
| | 43 |
| | 5 |
|
| Impairment charges | 7 |
| | — |
| | 7 |
|
| Total operating expenses | 1,042 |
| | 985 |
| | 57 |
|
| Operating Income | 286 |
| | 226 |
| | 60 |
|
| Equity in (losses) earnings of unconsolidated affiliates | (6 | ) | | 26 |
| | (32 | ) |
| Gain on sale of unconsolidated affiliates | — |
| | 132 |
| | (132 | ) |
| Other income and expenses, net | — |
| | 1 |
| | (1 | ) |
| Total other income and expenses | (6 | ) | | 159 |
| | (165 | ) |
| Interest Expense | 79 |
| | 69 |
| | 10 |
|
| Income Before Income Taxes | 201 |
| | 316 |
| | (115 | ) |
| Income Tax Expense | 62 |
| | 121 |
| | (59 | ) |
| Net Income | $ | 139 |
| | $ | 195 |
| | $ | (56 | ) |
The following table shows the percent changes in dekatherms delivered and average number of customers. The percentages for all throughput deliveries represent billed and unbilled sales. Amounts are not weather-normalized. |
| | | | |
| Increase (Decrease) over prior year | 2017 |
| 2016 |
|
| Residential deliveries | (8.1 | )% | (0.8 | )% |
| Commercial deliveries | (4.3 | )% | 1.6 | % |
| Industrial deliveries | (2.2 | )% | 0.5 | % |
| Power generation deliveries | (5.8 | )% | 10.7 | % |
| For resale | (20.9 | )% | 1.3 | % |
| Total throughput deliveries | (5.4 | )% | 6.3 | % |
| Secondary market volumes | (4.2 | )% | 120.6 | % |
| Average number of customers | 1.7 | % | 1.6 | % |
Piedmont's throughput was 468,259,777 dekatherms and 495,122,794 dekatherms for the years ended December 31, 2017, and 2016, respectively. Due to the margin decoupling mechanism in North Carolina and weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee, changes in throughput deliveries do not have a material impact on Piedmont's revenues or earnings. The margin decoupling mechanism adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.
Weather normalization adjustment (WNA) mechanisms – the decrease is due to colder weather in South Carolina and Tennessee. As discussed in “Financial Condition and Liquidity,” the The WNA mechanisms partiallymostly offset the impact of colder- or warmer-than-normal weather on bills rendered.
IMR mechanisms – the increaserendered, but do not ensure full recovery of approved margin during periods when winter weather is due to the IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014.significantly warmer or colder than normal.
2013 comparedYear Ended December 31, 2017, as Compared to 2012:2016
Operating Revenues.The variance was driven primarily by:
Residential and commercial customers – thea $74 million increase is primarily due to colder weather, customer growth and higher wholesalenatural gas costs passed through to customers.
Industrial customers – the increase is primarily due to colder weather and customer growth.
Power generation customers – the increase is primarily due to increased transportation services due to new contracts that began in June 2012 and June 2013.
Secondary market – the increase is primarily due to higher commoditynatural gas costs, partially offset by decreased activity.prices;
Margin decoupling mechanism – the decrease is duea $34 million increase in revenues to colder weather in North Carolina.
WNA mechanisms – the decrease is due to colder weather in South Carolinaresidential and Tennessee.
Costcommercial customers, net of Gas
Changes in cost of gas for 2014 and 2013 compared with the same prior periods are presented below.
|
| | | | | | | | |
| Changes in Cost of Gas - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Commodity gas costs passed through to sales customers | | $ | 137.5 |
| | $ | 96.8 |
|
| Commodity gas costs in secondary market transactions | | (11.0 | ) | | 24.5 |
|
| Pipeline demand charges | | (7.1 | ) | | 22.3 |
|
| Regulatory approved gas cost mechanisms | | 3.6 |
| | (34.2 | ) |
| Total | | $ | 123.0 |
| | $ | 109.4 |
|
2014 compared to 2013:
Commoditynatural gas costs passed through to sales customers, – theprimarily due to Integrity Management Rider (IMR) rate adjustments and customer growth. Increase is also due to new power generation customers, and is partially offset by wholesale marketing revenue; and
a $10 million increase isin revenues due to merger-related bill credits applied to customer bills in 2016.
Operating Expenses.The variance was driven by:
a $73 million increase in costs of natural gas primarily due to higher volumes sold due to colder weather and higher wholesalenatural gas costs passed through to sales customers.
Commodity gas costs in secondary market transactions – the decrease is primarily due to decreased activity, partially offset by higher average wholesale gas costs.
Pipeline demand charges – the decrease is due to decreased demand costs and increased capacity release revenues, slightly offset by decreased asset manager payments.
Regulatory approved gas cost mechanisms – the increase is primarily due to demand cost true-ups, slightly offset by other regulatory mechanisms.
2013 compared to 2012:
Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and slightly higher wholesale gas costs passed through to sales customers.
Commodity gas costs in secondary market transactions – the increase is primarily due to increased average wholesale gas costs, partially offset by decreased activity.
Pipeline demand charges – the increase is primarily due to increased demand costs, decreased asset manager payments and decreased capacity release revenues.
Regulatory approved gas cost mechanisms – the decrease is primarily due to commodity gas cost true-ups.
In all three states, we are authorized to recover from customers all prudently incurred gas costs. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are in current “Regulatory assets” or current “Regulatory liabilities” in the Consolidated Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements in this Form 10-K.
Margin
Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory pass through of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas
commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 41% of revenues for the years ended October 31, 2014 and 2013 and 36% for the year ended October 31, 2012. Our pipeline transportation and storage costs accounted for 10%, 12% and 11% for the years ended October 31, 2014, 2013 and 2012 respectively.
In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansionhigher price per dekatherm of natural gas service to larger industrial customers.
Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These regulatory mechanisms by jurisdiction are presented below. |
| | | | | | |
Regulatory Mechanism | | North Carolina | | South Carolina | | Tennessee |
WNA mechanism* | | | | X | | X |
Margin decoupling mechanism * | | X | | | | |
Natural gas rate stabilization mechanism | | | | X | | |
Secondary market activity ** | | X | | X | | X |
Incentive plan for gas supply ** | | | | | | X |
IMR mechanism | | X | | | | X |
Negotiated margin loss treatment | | X | | X | | |
Uncollectible gas cost recovery | | X | | X | | X |
| | | | | | |
* Residential and commercial customers only. |
** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million. |
Changes in margin for 2014 and 2013 compared with the same prior periods are presented below.gas;
|
| | | | | | | | |
| Changes in Margin - Increase (Decrease) |
| |
| 2014 vs. |
| 2013 vs. |
| In millions |
| 2013 |
| 2012 |
| Residential and commercial customers |
| $ | 31.2 |
|
| $ | 15.6 |
|
| Industrial customers |
| — |
|
| 5.3 |
|
| Power generation customers | | 21.3 |
| | 24.0 |
|
| Secondary market activity | | 16.4 |
| | (0.7 | ) |
| Net gas cost adjustments | | (0.2 | ) | | 1.8 |
|
| Total | | $ | 68.7 |
| | $ | 46.0 |
|
2014 compared to 2013:
Residential and commercial customers – the increase is primarily due to the general ratea $15 million increase in North Carolina effective January 1, 2014, the IMR rate adjustments mentioned above, customer growth in all three states depreciation expenseand increased volumes delivered in South Carolinaproperty and Tennessee due to colder weather.
Power generation customers – the increase is primarily due to increased transportation services.
Secondary market activity – the increase is primarily due to higher margin sales related to increased wholesale market volatility and sustained colder-than-normal weather.
2013 compared to 2012:
Residential and commercial customers – the increase is primarily due to increased volumes delivered due to colder weather, customer growth in all three states and the general rate increase in Tennessee, effective March 1, 2012.
Industrial customers – the increase is primarily due to higher consumption in the industrial market from colder weather and customer growth.
Power generation customers – the increase is primarily due to increased transportation services due to new contracts placed in service in June 2012 and June 2013.
Secondary market activity – the decrease is primarily due to lower commodity gas price volatility and decreased activity.
Operations and Maintenance Expenses
Changes in O&M expenses for 2014 and 2013 compared with the same prior periods are presented below.
|
| | | | | | | | |
| Changes in Operations and Maintenance Expenses - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Payroll | | $ | 9.6 |
| | $ | 1.8 |
|
| Regulatory | | 4.2 |
| | 1.0 |
|
| Bad debt | | 2.1 |
| | 1.4 |
|
| Contract labor | | 1.9 |
| | 2.4 |
|
| Employee benefits | | (0.3 | ) | | (1.1 | ) |
| Other | | 0.3 |
| | 5.0 |
|
| Total | | $ | 17.8 |
| | $ | 10.5 |
|
2014 compared to 2013:
Payroll – the increase is primarilyfranchise taxes due to additional employees, employee overtime because of colder-than-normal winter weatherplant in service; and incentive plan accruals.
Regulatory – thea $7 million increase is primarily due to increased amortizationan impairment of regulatory assets with approved amortization amounts established in the North Carolina general rate proceeding, effective January 1, 2014, and an increase in the North Carolina regulatory fee due to increased revenues.
Bad debt – the increase is primarily due to a higher level of net charge-offs from customer receivables due to the colder weather experienced this past winter and increased accruals to reflect higher aging receivables.
Contract labor – the increase is primarily due to increased call volume and collection efforts for customer receivablessoftware resulting from the colder winter, increasedplanned accounting system and process improvement projects and pipeline integrityintegration in 2018.
Partially offset by:
a $38 million decrease in operations, maintenance and safety programs.
2013 compared to 2012:
Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.
Payroll – the increase is due to increases in incentive plan accruals.
Bad debt – the increase is primarily due to a higher level of projected charge-offs due to higher bills.
Regulatory – the increase is primarily due to amortization of regulatory assets with new amortization amounts established in the Tennessee general rate proceeding effective in March 2012.
Employee benefits – the decrease is primarily due to reduced group medical insurance expense from lower claims and a regulatory pension deferral in Tennessee in 2013other related to the funding of the defined benefit plan in November 2012 compared to no plan fundingacquisition and integration expenses recorded in the prior year partially offset by an increase in pension expense.
Depreciation
Depreciation expense increased from $103.2 millioncosts paid to $119 million over the three-year period 2012 to 2014outside parties, primarily due to increases in plant in service, particularly related to major utility plant additions to serve new power generation customers, transmission integrity investmentsfinancial and upgrades to our liquefied natural gas facilities.
General Taxes
General taxes increased $2.7 million in 2014 compared with 2013 primarily due to increases in propertylegal advisory, severance expenses, retention costs and franchise taxes as a resultacceleration of increased property and increases to payroll taxes as a result of higher incentive payoutsplans, and an increased payroll base. Changes in general taxesaccrual for 2013 compared with the same prior period are insignificant.
Other Income (Expense)
Other Income (Expense) is comprised of income from equity method investments, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service agreements, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprisedour commitment of charitable contributions and miscellaneous expenses.
community support.
Changes in Other Income (Expense) for 2014 and 2013 compared withExpense. The variance was driven by:
a $132 million decrease in gain on sale of unconsolidated affiliates recorded in the
same prior
period are presented below.year due to Piedmont’s sale of its 15 percent ownership interest in SouthStar Energy Services, LLC (SouthStar) on October 3, 2016; and |
| | | | | | | | |
| Changes in Other Income (Expense) - Increase (Decrease) to Income |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Income from equity method investments: | | | | |
| SouthStar | | $ | 5.0 |
| | $ | 1.3 |
|
| Constitution | | 1.7 |
| | 1.0 |
|
| Other | | — |
| | (0.1 | ) |
| Total | | 6.7 |
| | 2.2 |
|
| Non-operating income | | (1.0 | ) | | 1.5 |
|
| Non-operating expense | | 0.8 |
| | (3.3 | ) |
| Income Taxes | | (3.0 | ) | | 0.5 |
|
| Total | | $ | 3.5 |
| | $ | 0.9 |
|
2014 compared with 2013:
Income froma $32 million decrease in equity method investments from SouthStar – the increase isin (losses) earnings of unconsolidated affiliates primarily due to equity earnings from the expansion of the business into Illinois markets beginninginvestment in September 2013, and favorable weather and customer usage in Georgia, partially offset by higher general and administrative expenses. For further information on the contribution of the Illinois business to SouthStar and our cash contribution in our equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.
Income from equity method investments from Constitution – the increase is primarily due to higher capitalized interest associated with increased capital expenditures on the project.
Non-operating income – the decrease is primarily due to a $2 million write-off of an investment that we accounted for on the cost basis. This investment was presented in “Other noncurrent assets” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets.
2013 compared with 2012:
Income from equity method investments from SouthStar – the increase is primarily due to higher average customer usage from colder weather compared to the prior year, net of weather derivatives, the recording of a lower of cost or market inventory adjustment in the prior year and new margin from the Illinois business that was contributed toimpacts of the venture with our sharing beginning in September 2013, partially offset by higher gas costs, increased operating expenses and lower retail price spreads.
Income from equity method investments from Constitution – the increase is primarily due to recording earnings of $1
million due to the allowance for funds used during construction (AFUDC), partially offset by operating expenses.
Non-operating income – the increase is primarily due to a $.7 million increase in non-regulated business income plus a gain from a land retirement.
Non-operating expense – the increase is primarily due to $1.8 million of cumulative amortization of non-land costs related to the allowed deferral of a regulatory asset for certain non-real estate costs, construction of which was suspended in March 2009, as includedTax Act in the 2013 settlement agreement with the NCUC Public Staff. We had a balance of $6.7 million of capital costs held in “Plant held for future use” comprised of $3.2 million in land costs and $3.5 million in non-land development costs. Under the NCUC approved settlement of the 2013 North Carolina general rate proceeding, we agreed to the amortization and collection of $1.2 million of the non-real estate costs to be amortized over 38 months beginning January 1, 2014, which we recorded as a regulatory asset along with a portion of the costs that we allocated to South Carolina operations. In addition, charitable contributions increased $.8 millioncurrent year.
Income Tax Expense. The variance was primarily due to the funding of our charitable foundation.
Utility Interest Charges
Changes in utility interest charges for 2014 and 2013 compared with the same prior periods are presented below.
|
| | | | | | | | |
| Changes in Utility Interest Charges - Increase (Decrease) |
| | | 2014 vs. | | 2013 vs. |
| In millions | | 2013 | | 2012 |
| Borrowed AFUDC | | $ | 14.5 |
| | $ | (5.8 | ) |
| Regulatory interest expense, net | | 8.1 |
| | 0.1 |
|
| Interest expense on long-term debt | | 7.4 |
| | 12.7 |
|
| Interest expense on short-term debt | | (0.4 | ) | | (1.5 | ) |
| Other | | 0.1 |
| | (0.7 | ) |
| Total | | $ | 29.7 |
| | $ | 4.8 |
|
2014 compared to 2013:
Borrowed AFUDC – the increase is due to a decrease in capitalized interest on a lower basepretax income and the impact of construction expenditures in the current period resulting fromTax Act. See the timing of projects being placed into service.
Regulatory interest expense, net – the increase is primarily due to the recording of interest expense on amounts due to customers compared with the recording of interest income in the prior year on amounts due from customers.
Interest expense on long-term debt – the increase is primarily due to higher amounts of debt outstanding in the current periods.
2013 compared to 2012:
Interest expense on long-term debt – the increase is primarily due to the issuance of debt in 2013 and a full year of interest expense on the debt issued in 2012.
Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily resulting from increased construction expenditures.
Interest expense on short-term debt – the decrease is primarily due to lower balances outstanding during the current period at interest rates that are 34 basis points lower than the prior year period. We paid down short-term debt as we issued long-term debt and equity securities during our fiscal year.
Financial Condition and Liquidity
Our financial strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. The needSubsidiary Registrants section above for long-term capital is driven by the level of and timing of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC. Foradditional information on the issuance of long-term debt and equity securities, see Note 4 and Note 6, respectively to the consolidated financial statements in this Form 10-K.
To meet our capital and liquidity requirements outside of the long-term capital markets, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily provides the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned investments in customer growth, pipeline integrity programs, system infrastructure and contributions to our joint ventures.
The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gasTax Act and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventoryimpact on the effective tax rate.
Matters Impacting Future Results
Within this Item 7, see the Tax Cuts and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.
We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by reduced tax payments due to the utilization of federal net operating loss (NOL) carryforwards resulting from bonus depreciation,Jobs Act above as well as the ability to recoverLiquidity and earn on investments in infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities” in this Form 10-K.
Short-Term Debt. We have an $850 million five-year revolving syndicated credit facility that expires in October 2017. We pay an annual fee of $35,000 plus 8.5 basis pointsCapital Resources below for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.
We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsecured debt.
We did not have any borrowings under the revolving syndicated credit facility for the year ended October 31, 2014. Highlights for our short-term debt as of October 31, 2014 and 2013 and for the quarter and year ended October 31, 2014 and 2013 are presented below.
|
| | | | | | | | | | | | |
| | | Credit | | Commercial | | Total |
| In thousands | | Facility | | Paper | | Borrowings |
| 2014 | | | | | | |
| End of period (October 31, 2014): | | | | | | |
| Amount outstanding | | $ | — |
| | $ | 355,000 |
| | $ | 355,000 |
|
| Weighted average interest rate | | — | % | | .17 | % | | .17 | % |
| | | | | | | |
| During the period (August 1, 2014 – October 31, 2014): | | | | | | |
| Average amount outstanding | | $ | — |
| | $ | 420,900 |
| | $ | 420,900 |
|
| Minimum amount outstanding | | — |
| | 275,000 |
| | 275,000 |
|
| Maximum amount outstanding | | — |
| | 535,000 |
| | 535,000 |
|
| Minimum interest rate | | — | % | | .10 | % | | .10 | % |
| Maximum interest rate | | — | % | | .25 | % | | .25 | % |
| Weighted average interest rate | | — | % | | .17 | % | | .17 | % |
| | | | | | | |
| Maximum amount outstanding during the month: | | | | | | |
| August 2014 | | $ | — |
| | $ | 525,000 |
| | $ | 525,000 |
|
| September 2014 | | — |
| | 535,000 |
| | 535,000 |
|
| October 2014 | | — |
| | 355,000 |
| | 355,000 |
|
| | | | | | | |
| During the year ended October 31, 2014: | | | | | | |
| Average amount outstanding | | $ | — |
| | $ | 441,500 |
| | $ | 441,500 |
|
| Minimum amount outstanding | | — |
| | 275,000 |
| | 275,000 |
|
| Maximum amount outstanding | | — |
| | 625,000 |
| | 625,000 |
|
| Minimum interest rate | | — | % | | .10 | % | | .10 | % |
| Maximum interest rate | | — | % | | .43 | % | | .43 | % |
| Weighted average interest rate | | — | % | | .19 | % | | .19 | % |
|
| | | | | | | | | | | | |
|
| Credit |
| Commercial |
| Total |
| In thousands |
| Facility |
| Paper |
| Borrowings |
| 2013 |
|
|
|
|
|
|
| End of period (October 31, 2013): |
|
|
|
|
|
|
| Amount outstanding |
| $ | — |
|
| $ | 400,000 |
|
| $ | 400,000 |
|
| Weighted average interest rate |
| — | % |
| .36 | % |
| .36 | % |
| | | | | | | |
| During the period (August 1, 2013 – October 31, 2013): |
|
|
|
|
|
|
| Average amount outstanding |
| $ | — |
|
| $ | 319,700 |
|
| $ | 319,700 |
|
| Minimum amount outstanding |
| — |
|
| 220,000 |
|
| 220,000 |
|
| Maximum amount outstanding |
| — |
|
| 475,000 |
|
| 475,000 |
|
| Minimum interest rate |
| — | % |
| .23 | % |
| .23 | % |
| Maximum interest rate |
| — | % |
| .43 | % |
| .43 | % |
| Weighted average interest rate |
| — | % |
| .28 | % |
| .28 | % |
|
|
|
|
|
|
|
| Maximum amount outstanding during the month: |
|
|
|
|
|
|
| August 2013 |
| $ | — |
|
| $ | 475,000 |
|
| $ | 475,000 |
|
| September 2013 |
| — |
|
| 335,000 |
|
| 335,000 |
|
| October 2013 |
| — |
|
| 430,000 |
|
| 430,000 |
|
| | | | | | | |
| During the year ended October 31, 2013: |
|
|
|
|
|
|
Average amount outstanding (1) |
| $ | — |
|
| $ | 397,800 |
|
| $ | 397,800 |
|
Minimum amount outstanding (1) |
| — |
|
| 220,000 |
|
| 220,000 |
|
Maximum amount outstanding (1) |
| 10,000 |
|
| 555,000 |
|
| 555,000 |
|
Minimum interest rate (2) |
| 1.12 | % |
| .23 | % |
| .23 | % |
| Maximum interest rate |
| 1.12 | % |
| .45 | % |
| 1.12 | % |
| Weighted average interest rate |
| 1.12 | % |
| .32 | % |
| .32 | % |
| | | | | | | |
(1) During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month. |
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program. |
As of October 31, 2014, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.8 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2014, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $493.2 million.
Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term debt to meet seasonal working capital needs. The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through monthly bills. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, construction activity and decreases in receipts from customers.
During the winter heating season, our trade accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to or from
customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.
Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills. Regulatory margin stabilizing and cost recovery mechanisms, such as decoupled tariffs and those that allow us to recover the gas cost portion of bad debt expense, mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.
Net cash provided by operating activities was $430.6 million in 2014, $313.2 million in 2013 and $304.5 million in 2012. Net cash provided by operating activities reflects a $9.4 million increase in net income for 2014 compared with 2013 primarily due to increased margin, partially offset by higher operating costs and utility interest charges. The effect of changes in working capital on net cash provided by operating activities is described below:
Trade accounts receivable and unbilled utility revenues decreased $17.3 million in the current period primarily due to the decrease in unbilled volumes in the month of October and amounts billed to customers. Volumes sold to weather-sensitive residential and commercial customers increased 11.2 million dekatherms as compared with the same prior period primarily due to 6.2% colder weather during the current period. Total throughput increased 23.1 million dekatherms as compared with the same prior period, largely from 10.8 million dekatherms, or 5.7% increased deliveries to power generation customers, as well as increased sales to residential and commercial customers.
Net amounts due from customers decreased $96.4 million in the current period primarily due to higher margin decoupling, WNA and deferred gas cost amounts due to customers.
Gas in storage increased $10.2 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections and increased volumes of gas in storage.
Prepaid gas costs increased $3.5 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.
Trade accounts payable decreased$11 million in the current period primarily due to decreased utility capital expenditures and natural gas purchases.
Primarily due to bonus depreciation, we generated a federal NOL in our tax years 2012 and 2013. We filed claims to carryback a portion of the NOLs to prior federal income tax returns. We recorded approximately $27 million in “Income taxes receivable” in “Current Assets” in the Consolidated Balance Sheets for the refundable income taxes from the carryback of these NOLs. Also, we utilized the carryforward of the NOLs to offset $28.6 million of federal income taxes payable in fiscal 2014. We anticipate that we will utilize the remaining portion of the NOL carryforwards prior to the expiration of the loss carryforward period.
The Tax Increase Prevention Act of 2014 (the Act) retroactively extends the 50% bonus depreciation that expired in December 2013 for a year to December 2014. Under this Act, we will be entitled to additional tax depreciation deductions for 2014. These additional deductions will result in generating a federal NOL in 2014. Our federal NOL carryforward position after considering this legislation will increase to approximately $275 million. We anticipate that we will generate future taxable income sufficient to utilize this carryforward prior to the expiration of the loss carryforward period.
Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated credits to customers of $8.4 million in 2014 and charges of $3 million and $13.3 million in 2013 and 2012, respectively. In Tennessee, adjustments are made directly to individual customer monthly bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities,” as presented in Note 1 to the consolidated financial statements in this Form 10-K, for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin decoupling mechanism reduced margin by $33.4 million in 2014 and increased margin
by $6 million and $46.8 million in 2013 and 2012, respectively. Our gas costs are recoverable through purchased gas adjustment (PGA) procedures and are not affected by the WNA or the margin decoupling mechanisms.
The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.
The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.
In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on the relative prices of energy. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the U.S. dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.
In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and O&M cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.
Cash Flows from Investing Activities. Net cash used in investing activities was $504.4 million in 2014, $663.5 million in 2013 and $549.3 million in 2012. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were $460.4 million in 2014 as compared to $600 million in 2013 primarily due to lower power generation service delivery project expenditures and lower maintenance expenditures. Gross utility capital expenditures were $600 million in 2013 compared to $529.6 million in 2012 primarily due to increased expenditures for system integrity projects, partially offset by decreased expenditures for the construction of power generation service delivery projects.
We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. Our program supports our system infrastructure, the growth in our customer base and large amounts for pipeline integrity, safety and compliance programs, including systems and technology infrastructure to enhance our pipeline system and integrity through a new work and asset management system. Significant utility construction expenditures are expected for growth and system integrity and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.
Detail of our forecasted 2015 – 2017 capital expenditures, including AFUDC, is presented below. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 50 – 60% in total debt and 40 – 50% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits.
|
| | | | | | | | | | | | |
| In millions | | 2015 | | 2016 | | 2017 |
| Customer growth and other | | $ | 230 |
| | $ | 285 |
| | $ | 295 |
|
| System integrity | | 270 |
| | 245 |
| | 295 |
|
| Total forecasted utility capital expenditures | | $ | 500 |
| | $ | 530 |
| | $ | 590 |
|
Our estimates for utility capital expenditures associated with system integrity have increased since 2013. These increases are primarily due to costsrisks associated with the development and enhancementTax Act.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Preparation of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs
include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management.
During fiscal 2012, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a Duke Energy Progress, Inc. (DEP), now a subsidiary of Duke Energy Corporation (Duke Energy), power generation facility located in Wayne County, North Carolina. This project was supported by a long-term service agreement with fixed monthly payments. In connection with this project, we increased our firm capacity entitlement on Cardinal Pipeline Company, L.L.C. (Cardinal) pipeline to serve the DEP Wayne County site, requiring Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system for us and another customer. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million related to this system expansion and received $5.4 million as a partial return of our capital investment with Cardinal's issuance of $45 million of long-term debt. Cardinal's expansion service for the project and our natural gas delivery service for DEP's Wayne County site were placed into service in June 2012.
During fiscal 2013, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a DEP power generation facility at their Sutton site near Wilmington, North Carolina. Our investment in the pipeline and compression facilities was supported by a long-term service agreement with fixed monthly payments.
Our Sutton project facilities created cost effective expansion capacity that we will also use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The approval of our 2013 NCUC rate settlement provided for the inclusion of this project in rate base in North Carolina. Beginning in 2015, a special contracts credit, representing a portion of margin on our power generation contracts, will reduce the IMR revenue requirement under the IMR mechanism.
In July 2013, we acquired an additional 5% membership interest in Pine Needle LNG Company, L.L.C. from Hess Corporation for $2.9 million, which increased our membership interest from 40% to 45%.
In September 2013, we made an additional $22.5 million capital contribution to our existing SouthStar investment associated with our partner contributing retail natural gas marketing assets and related customer accounts located in Illinois. For further information regarding this transaction, see Note 12 to the consolidated financial statements in this Form 10-K.
In November 2012, we became a 24% equity memberrequires the application of Constitution, a Delaware limited liability company. The purpose of the joint venture is to construct, ownaccounting policies, judgments, assumptions and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. Our contributions for the year ended October 31, 2014 were $37.6 million with our total equity contribution for the project totaling $53.5 million as of October 31, 2014. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The forecasted in-service date of the project is late 2015 or 2016. We expect our equity contributions will be an estimated $86 million and $35.4 million in our fiscal years 2015 and 2016, respectively, for total equity contributions of $175 million. In November 2014, we contributed $1.9 million to the project. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-K.
In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression to serve Duke Energy’s W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $38 million, with $8 million and $30 million in our fiscal years 2015 and 2016, respectively, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges.
In September 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL Resources, Inc. (AGL) announced the formation of ACP, a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by utilities and related companies, including us, under twenty-year contracts.
We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion, excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP. In November 2014, we contributed $.9 million to the project.
In connection with the ACP project, we plan to make additional utility capital investments in our natural gas delivery system of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve, predominately in fiscal 2017 and 2018. Ofestimates that amount, approximately $170 million will be supported by third-party contracts.
Cash Flows from Financing Activities. Net cash provided by financing activities was $75.4 million in 2014, $356.3 million in 2013 and $240 million in 2012. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We may sell common stock and long-term debt when market and other conditions favor such long-term financing to maintain our target capital structure of 40 – 50% equity to total capital. In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments. Funds are primarily used to finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program, pay quarterly dividends on our common stock and general corporate purposes.
Outstanding debt under our CP program decreased from $400 million as of October 31, 2013 to $355 million as of October 31, 2014 primarily due to net proceeds received from the issuance of long-term debt and our common stock, reduced utility capital expenditures and cash flow stemming from colder-than normal weather, partially offset by natural gas purchases, repayment of our long-term debt and investments in one of our equity method investments. On November 1, 2013, we entered into an agreement with the lenders under our five-year revolving syndicated credit facility to increase the aggregate commitment from $650 million to $850 million with an expiration date of October 1, 2017. Our unsecured CP program is backstopped by this credit facility. For further information on short-term debt, see Note 5 to the consolidated financial statements in this Form 10-K and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”
On June 6, 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment-grade securities. We plan to issue new long-term debt and equity capital in our fiscal years 2015 and 2016, at such amounts to support our capital investment program and maintain our target capital structure of 50 – 60% in total debt and 40 – 50% in common equity. In addition to issuing common stock under our DRIP and ESPP as described above, we expect to establish in the first quarter of 2015 an at-the-market equity sales program that may also include sales with a forward component. We anticipate that sales under this program would not exceed an aggregate of $170 million, as market conditions permit, and would be completed by the end of fiscal 2016. Any such shares of our common stock would be offered and sold under our shelf registration statement and related prospectuses.
On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settled on February 4, 2013 with net proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.
Under this same underwriting agreement, we had two FSAs totaling 1.6 million shares that had to be settled no later than mid-December 2013. Under the terms of the FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements. In December 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments.
We used the net proceeds from the equity transactions discussed above to finance capital expenditures, repay outstanding notes under the unsecured CP program and for general corporate purposes. For further information on our common stock and for more details on these equity issuance transactions, see Note 6 to the consolidated financial statements in this Form 10-K.
We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt. The table below presents the activity of our long-term debt during the three-year period ended October 31, 2014. For further information on our long-term debt instruments, see Note 4 to the consolidated financial statements in this Form 10-K.
|
| | | | | | | | | | |
| In millions | | Issued (Redeemed) | | Date Issued/Redeemed | | Cash Impact |
| Senior Notes: | | | | | | |
3.47%, due July 16, 2027 (1) (2) | | $ | 100 |
| | July 2012 | | $ | 100.0 |
|
3.57%, due July 16, 2027 (1) (2) | | 200 |
| | October 2012 | | 200.0 |
|
4.65%, due August 1, 2043 (3) | | 300 |
| | August 2013 | | 299.9 |
|
4.10%, due September 18, 2034 (1) | | 250 |
| | September 2014 | | 249.6 |
|
| | | | | | | |
| Medium-Term Notes: | | | | | | |
| 5.00%, due December 19, 2013 | | (100 | ) | | December 2013 | | (100 | ) |
| | | | | | | |
(1) The net proceeds were used to finance capital expenditures, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes. |
(2) In March 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended rate of 3.54%. |
(3) The net proceeds were used to finance capital expenditures, to repay the balance of $100 million of our 5% Medium-Term Notes listed below, to repay outstanding short-term notes under our unsecured CP program and for general corporate purposes. |
From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Note 6 to the consolidated financial statements in this Form 10-K. During 2014 and 2013, we did not repurchase any of our common stock. Under our Common Stock Open Market Purchase Program, we repurchased and retired .8 million shares for $26.5 million during 2012. We do not anticipate repurchasing our common stock in our fiscal year 2015.
During 2014, we issued $25.6 million of common stock through DRIP and ESPP. During 2013 and 2012, we issued $24.6 million and $22.1 million, respectively, through these plans.
We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share over the past three fiscal years. Dividends of $99.2 million, $92.1 million and $85.7 million in 2014, 2013 and 2012, respectively, were paid on common stock. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2014, our ability to pay dividends was not restricted. On December 12, 2014, the Board of Directors declared a quarterly dividend on common stock of $.32 per share, payable January 15, 2015 to shareholders of record at the close of business on December 24, 2014. For further information, see Note 4 to the consolidated financial statements in this Form 10-K.
Our targeted capitalization ratio is 50 – 60% in total debt and 40 – 50% in common equity. The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2014 and 2013 are summarized in the table below.
|
| | | | | | | | | | | | | | |
| | | October 31 | | October 31 |
| In thousands | | 2014 | | Percentage | | 2013 | | Percentage |
| Short-term debt | | $ | 355,000 |
| | 12 | % | | $ | 400,000 |
| | 14 | % |
| Current portion of long-term debt | | — |
| | — | % | | 100,000 |
| | 3 | % |
| Long-term debt | | 1,424,430 |
| | 46 | % | | 1,174,857 |
| | 41 | % |
| Total debt | | 1,779,430 |
| | 58 | % | | 1,674,857 |
| | 58 | % |
| Common stockholders’ equity | | 1,308,602 |
| | 42 | % | | 1,188,596 |
| | 42 | % |
| Total capitalization (including short-term debt) | | $ | 3,088,032 |
| | 100 | % | | $ | 2,863,453 |
| | 100 | % |
Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving syndicated credit facility and our unsecured CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.
The lenders under our revolving syndicated credit facility and our unsecured CP program are major financial institutions, all of which have investment grade credit ratings as of October 31, 2014. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.
As of October 31, 2014, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A2” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our unsecured CP program at “A1” and “P1”, respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.
We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2014, there has been no event of default giving rise to acceleration of our debt.
The default provisions of some or all of our senior debt include:
Failure to make principal or interest payments,
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Change in control, and
Failure to observe or perform covenants, including:
Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;
Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;
Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;
Restrictions on permitted liens;
Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.
Contractual Obligations and Commitments
We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2014, our estimated recorded and unrecorded contractual obligations are as follows. We have conditional asset retirement obligations for underground mains and services of $14.6 million that are not included in the table because we cannot reasonably estimate payments by periods.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| | | Less than | | 1-3 | | 3-5 | | More than | | |
| In thousands | | 1 year | | Years | | Years | | 5 Years | | Total |
| Recorded contractual obligations: | | | | | | | | | | |
| | | | | | | | | | | |
| Long-term debt (1) | | $ | — |
| | $ | 75,000 |
| | $ | — |
| | $ | 1,350,000 |
| | $ | 1,425,000 |
|
| Short-term debt (2) | | 355,000 |
| | �� |
| | — |
| | — |
| | 355,000 |
|
| Total recorded contractual obligations | | 355,000 |
| | 75,000 |
| | — |
| | 1,350,000 |
| | 1,780,000 |
|
| | | | | | | | | | | |
| Unrecorded contractual obligations and | | | | | | | | | | |
| commitments: (3) | | | | | | | | | | |
| | | | | | | | | | | |
| Pipeline and storage capacity (4) | | 158,984 |
| | 437,424 |
| | 246,091 |
| | 513,697 |
| | 1,356,196 |
|
| Gas supply reservation fees (5) | | 8,657 |
| | 272 |
| | — |
| | — |
| | 8,929 |
|
| Interest on long-term debt (6) | | 69,609 |
| | 204,949 |
| | 131,811 |
| | 736,555 |
| | 1,142,924 |
|
| Capital contributions to joint ventures (7) | | 106,734 |
| | 159,847 |
| | 88,612 |
| | — |
| | 355,193 |
|
| Telecommunications and information | | | | | | | | | | |
| technology (8) | | 14,601 |
| | 5,648 |
| | 80 |
| | — |
| | 20,329 |
|
| Qualified and nonqualified pension plan | | | | | | | | | | |
| funding (9) | | 11,821 |
| | 36,571 |
| | 2,590 |
| | — |
| | 50,982 |
|
| Postretirement benefits plan funding (9) | | 1,500 |
| | 4,000 |
| | 1,300 |
| | — |
| | 6,800 |
|
| Operating leases (10) | | 4,600 |
| | 13,013 |
| | 8,362 |
| | 23,134 |
| | 49,109 |
|
| Other purchase obligations (11) | | 41,008 |
| | — |
| | — |
| | — |
| | 41,008 |
|
| Surety bonds (10) | | 4,782 |
| | — |
| | — |
| | — |
| | 4,782 |
|
| Letters of credit (2) | | 1,797 |
| | — |
| | — |
| | — |
| | 1,797 |
|
| Total unrecorded contractual obligations | | | | | | | | | | |
| and commitments | | 424,093 |
| | 861,724 |
| | 478,846 |
| | 1,273,386 |
| | 3,038,049 |
|
| Total contractual obligations and | | | | | | | | | | |
| commitments | | $ | 779,093 |
| | $ | 936,724 |
| | $ | 478,846 |
| | $ | 2,623,386 |
| | $ | 4,818,049 |
|
| |
(1) | See Note 4 to the consolidated financial statements in this Form 10-K. |
| |
(2) | See Note 5 to the consolidated financial statements in this Form 10-K. |
| |
(3) | In accordance with generally acceptable accounting principles in the United States (GAAP), these items are not reflected in the Consolidated Balance Sheets. |
| |
(4) | Recoverable through PGA procedures. |
| |
(5) | Reservation fees are fixed payments and are recoverable through PGA procedures. |
| |
(6) | Includes accrued interest of $20.8 million as of October 31, 2014. |
| |
(7) | See Note 12 to the consolidated financial statements in this Form 10-K. |
| |
(8) | Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees. |
| |
(9) | Estimated funding beyond five years is not available. See Note 9 to the consolidated financial statements in this Form 10-K. |
| |
(10) | See Note 8 to the consolidated financial statements in this Form 10-K. Operating lease payments do not include payment for common area maintenance, utilities or tax payments. |
| |
(11) | Consists primarily of pipeline products, vehicles, contractors and merchandise. |
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than letters of credit, surety bonds and operating leases. The letters of credit are discussed in Note 5 to the consolidated financial statements in this Form 10-K. The surety bonds and operating leases are discussed in Note 8 to the consolidated financial statements in this Form 10-K.
Critical Accounting Estimates
We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions thatcan significantly affect the reported results of operations, cash flows or the amounts of assets and liabilities at the date ofrecognized in the financial statementsstatements. Judgments made include the likelihood of success of particular projects, possible legal and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimatesregulatory challenges, earnings assumptions on historical experience, where applicable,pension and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluatebenefit fund investments and anticipated recovery of costs, especially through regulated operations.
Management discusses these policies, estimates and assumptions with senior members of management on a regular basis and make adjustments in subsequent periodsprovides periodic updates on management decisions to reflect more current information if we determine that modifications in assumptions and estimates are warranted.
Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting estimates presented below with the Audit Committee of the Board of Directors.
Revenue Recognition. Utility sales Management believes the areas described below require significant judgment in the application of accounting policy or in making estimates and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. In South Carolina and Tennessee, we have WNA mechanismsassumptions that are designed to protect a portion of our residentialinherently uncertain and commercial customer revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The mechanisms also serve to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of weather and consumption patterns. The margin earned monthly under the margin decoupling mechanism resultsthat may change in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanisms. Without the WNA and margin decoupling mechanisms, our operating revenues and margin would have been higher by $41.8 million in 2014 and lower by $9 million and by $60.1 million in 2013 and 2012, respectively.subsequent periods.
New in 2014 is the IMR that was implemented in North Carolina and Tennessee to separately track and recover costs associated with capital expenditures in order to comply with pipeline safety and integrity requirements on an annual basis outside general rate cases. Under the North Carolina IMR tariff, we make annual filings each November to capture such costs closed to plant through October with revised rates effective the following February. Under the Tennessee IMR, we file to adjust rates to be effective each JanuaryFor further information, see Note 1 based on capital expenditures incurred through the previous October. Without the IMR in North Carolina, our operating revenues and margin would have been lower by $.6 million for the period February 1, 2014 through October 31, 2014. Without the IMR in Tennessee, our operating revenues and margin would have been lower by $10.1 million for the period January 1, 2014 through October 31, 2014.
Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.
Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to the accounting regulations required by rate-regulatedConsolidated Financial Statements, "Summary of Significant Accounting Policies."
Regulated Operations Accounting
Substantially all of Duke Energy’s regulated operations and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatoryregulated operations accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatorytreatment. As a result, Duke Energy is required to record assets and liabilities relatedthat would not be recorded for nonregulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities are recorded when it is probable that a regulator will require Duke Energy to those portions ceasingmake refunds to meet such criteria and include them as an adjustmentcustomers or reduce rates to net incomecustomers for previous collections or accumulated other comprehensive incomedeferred revenue for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event couldcosts that have a material effect on our results of operations in the period this action was recorded.
yet to be incurred.
Management continually assesses whether therecorded regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment offor similar costs in ourDuke Energy’s jurisdictions, litigation of rate orders, recent rate orders to other regulated entities, levels of actual return on equity compared to approved rates of return on equity and the status of any pending or potential legislation thatderegulation legislation. If future recovery of costs ceases to be probable, asset write-offs would affectbe recognized in operating income. Additionally, regulatory agencies can provide flexibility in the regulatory environment. Based on our assessment that reflectsmanner and timing of the current politicaldepreciation of property, plant and regulatory climate at the stateequipment, recognition of asset retirement costs and federal levels, we believe that allamortization of our regulatory assets, are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.
Regulatory assets asmay disallow recovery of October 31, 2014 and 2013 totaled $213.9 million and $246.3 million, respectively. Regulatory liabilities asall or a portion of October 31, 2014 and 2013 totaled $604.8 million and $541.9 million, respectively. The detail of thesecertain assets. For further information on regulatory assets and liabilities, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”
As required by regulated operations accounting rules, significant judgment can be required to determine if an otherwise recognizable incurred cost, such as closure costs for ash impoundments, qualifies to be deferred for future recovery as a regulatory asset. Significant judgment can also be required to determine if revenues previously recognized are for entity specific costs that are no longer expected to be incurred or have not yet been incurred and are therefore a regulatory liability. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for a more in-depth discussion of Regulatory Assets and Liabilities.
Regulated operations accounting rules also require recognition of a disallowance (also called "impairment") loss if it becomes probable that part of the cost of a plant under construction (or a recently completed or an abandoned plant) will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made. For example, if a cost cap is presentedset for a plant still under construction, the amount of the disallowance is a result of a judgment as to the ultimate cost of the plant. Other disallowances can require judgments on allowed future rate recovery. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for a discussion of disallowances recorded.
When it becomes probable that regulated assets will be abandoned, the cost of the asset is removed from plant in “Rate-Regulated Basisservice. The value that may be retained as a regulatory asset on the balance sheet for the abandoned property is dependent upon amounts that may be recovered through regulated rates, including any return. As such, an impairment charge, if any, could be partially or fully offset by the establishment of Accounting”a regulatory asset if rate recovery is probable. The impairment for a disallowance of costs for regulated plants under construction, recently completed or abandoned is based on discounted cash flows.
For further information, see Note 4 to the Consolidated Financial Statements, "Regulatory Matters."
Goodwill Impairment Assessments
Duke Energy allocates goodwill to reporting units, which are either the Business Segments listed in Note 13 to the consolidated financial statementsConsolidated Financial Statements or one level below based on how the Business Segment is managed. Duke Energy is required to test goodwill for impairment at least annually and more frequently if it is more likely than not that the fair value is less than the carrying value. Duke Energy performs its annual impairment test as of August 31.
Application of the goodwill impairment test requires management's judgment, including determining the fair value of the reporting unit, which management estimates using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables within the utility and energy industries. Significant assumptions used in this Form 10-K.these fair value analyses include discount and growth rates, future rates of return expected to result from ongoing rate regulation, utility sector market performance and transactions, forecasted earnings base, projected operating and capital cash flows for Duke Energy’s business and the fair value of debt.
Estimated future cash flows under the income approach are based to a large extent on Duke Energy’s internal business plan, and adjusted as appropriate for Duke Energy’s views of market participant assumptions. Duke Energy’s internal business plan reflects management’s assumptions related to customer usage and attrition based on internal data and economic data obtained from third-party sources, projected commodity pricing data and potential changes in environmental regulations. The business plan assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of returns on equity, anticipated earnings/returns related to significant future capital investments, continued recovery of cost of service, the renewal of certain contracts and the future of renewable tax credits. Management also makes assumptions regarding operation, maintenance and general and administrative costs based on the expected outcome of the aforementioned events. In estimating cash flows, Duke Energy incorporates expected growth rates, regulatory and economic stability, the ability to renew contracts and other factors, into its revenue and expense forecasts.
One of the most significant assumptions that Duke Energy utilizes in determining the fair value of its reporting units under the income approach is the discount rate applied to the estimated future cash flows. Management determines the appropriate discount rate for each of its reporting units based on the weighted average cost of capital (WACC) for each individual reporting unit. The WACC takes into account both the after-tax cost of debt and cost of equity. A major component of the cost of equity is the current risk-free rate on 20-year U.S. Treasury bonds. In the 2017 impairment tests, Duke Energy considered implied WACCs for certain peer companies in determining the appropriate WACC rates to use in its analysis. As each reporting unit has a different risk profile based on the nature of its operations, including factors such as regulation, the WACC for each reporting unit may differ. Accordingly, the WACCs were adjusted, as appropriate, to account for company specific risk premiums. The discount rates used for calculating the fair values as of August 31, 2017, for each of Duke Energy’s reporting units ranged from 5.3 percent to 6.7 percent. The underlying assumptions and estimates are made as of a point in time. Subsequent changes, particularly changes in the discount rates, authorized regulated rates of return or growth rates inherent in management’s estimates of future cash flows, could result in future impairment charges.
One of the most significant assumptions utilized in determining the fair value of reporting units under the market approach is implied market multiples for certain peer companies. Management selects comparable peers based on each peer’s primary business mix, operations, and market capitalization compared to the applicable reporting unit and calculates implied market multiples based on available projected earnings guidance and peer company market values as of August 31.
In December 2016, Duke Energy disposed of its International operations and no longer has goodwill associated with the International operations. For further information, see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.”
Duke Energy primarily operates in environments that are rate-regulated. In such environments, revenue requirements are adjusted periodically by regulators based on factors including levels of costs, sales volumes and costs of capital. Accordingly, Duke Energy’s regulated utilities operate to some degree with a buffer from the direct effects, positive or negative, of significant swings in market or economic conditions. However, significant changes in discount rates over a prolonged period may have a material impact on the fair value of equity.
As of August 31, 2017, all of the reporting units’ estimated fair value of equity substantially exceeded the carrying value of equity, except for the Commercial Renewables reporting units. The goodwill at the Energy Management Solutions reporting unit of Commercial Renewables was evaluated for recoverability in 2017, and Duke Energy recorded impairment charges of $29 million.
The Commercial Renewables reporting units are impacted by a multitude of factors including, legislative actions related to tax credit extensions, long-term growth rate assumptions and discount rates. As of August 31, 2017, the Renewables reporting unit’s estimated fair value of equity exceeded the carrying value of equity by less than 10 percent. Management continues to monitor these assumptions for any indicators that the fair value of the reporting unit could be below the carrying value and will assess goodwill for impairment as appropriate.
For further information, see Note 11 to the Consolidated Financial Statements, "Goodwill and Intangible Assets."
Asset Retirement Obligations
AROs are recognized for legal obligations associated with the retirement of property, plant and equipment. Substantially all AROs are related to regulated operations. When recording an ARO, the present value of the projected liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The liability is accreted over time. For operating plants, the present value of the liability is added to the cost of the associated asset and depreciated over the remaining life of the asset. For retired plants, the present value of the liability is recorded as a regulatory asset unless determined not to be recoverable.
The present value of the initial obligation and subsequent updates are based on discounted cash flows, which include estimates regarding timing of future cash flows, selection of discount rates and cost escalation rates, among other factors. These estimates are subject to change. Depreciation expense is adjusted prospectively for any changes to the carrying amount of the associated asset. The Duke Energy Registrants receive amounts to fund the cost of the ARO for regulated operations through a combination of regulated revenues and earnings on the nuclear decommissioning trust fund (NDTF). As a result, accretion expense and depreciation of the associated ARO asset are netted and deferred as a regulatory asset or liability.
Obligations for nuclear decommissioning are based on site-specific cost studies. Duke Energy Carolinas and Duke Energy Progress assume prompt dismantlement of the nuclear facilities after operations are ceased. Duke Energy Florida assumes Crystal River Unit 3 will be placed into a safe storage configuration until eventual dismantlement is completed by 2074. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida also assume that spent fuel will be stored on-site until such time that it can be transferred to a yet to be built U.S. Department of Energy (DOE) facility.
Obligations for closure of ash basins are based upon discounted cash flows of estimated costs for site-specific plans, if known, or probability weightings of the potential closure methods if the closure plans are under development and multiple closure options are being considered and evaluated on a site-by-site basis.
For further information, see Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations."
Long-Lived Asset Impairment Assessments, Excluding Regulated Operations, and Equity Method Investments
Property, plant and equipment, excluding plant held for sale, is stated at the lower of carrying value (historical cost less accumulated depreciation and previously recorded impairments) or fair value, if impaired. Duke Energy evaluates property, plant and equipment for impairment when events or changes in circumstances (such as a significant change in cash flow projections or the determination that it is more likely than not that an asset or asset group will be sold) indicate the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with their carrying value.
Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted future cash flows. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value and recording a loss if the carrying value is greater than the fair value. Additionally, determining fair value requires probability weighting future cash flows to reflect expectations about possible variations in their amounts or timing and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.
When determining whether an asset or asset group has been impaired, management groups assets at the lowest level that has discrete cash flows.
Investments in affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of the investment is less than book value. It the decline in value is considered to be other than temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment.
For further information, see Notes 10 and 12 to the Consolidated Financial Statements, "Property, Plant and Equipment" and “Investments in Unconsolidated Affiliates,” respectively.
Revenue Recognition
Revenues on sales of electricity and natural gas are recognized when service is provided or the product is delivered. As retail meters are read, invoices are prepared and the invoice amount is generally recognized as "billed" revenue. Operating revenues also include "unbilled" electric and natural gas revenues for the amount of service provided or product delivered after the last meter reading prior to the end of the accounting period. Unbilled retail revenues are estimated by applying an average revenue per kilowatt-hour (kWh), per thousand cubic feet (Mcf) or per dekatherm (dth) for all customer classes to the number of estimated kWh, Mcf or dth delivered but not yet billed.
For wholesale customers, the invoice amount is generally recognized as “billed” revenue. Although meters are read as of the end of the month, invoices have typically not been prepared. An estimate of the wholesale invoice is included in the reported amount of “unbilled” revenue.
The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors that impact the change in the unbilled revenue receivable balance, including seasonality, weather, customer usage patterns, customer mix, timing of rendering customer bills, meter readings schedules and the average price in effect for customer classes.
Pension and PostretirementOther Post-Retirement Benefits. We have
The calculation of pension expense, other post-retirement benefit expense and net pension and other post-retirement assets or liabilities require the use of assumptions and election of permissible accounting alternatives. Changes in assumptions can result in different expense and reported asset or liability amounts and future actual experience can differ from the assumptions. Duke Energy believes the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate applied to future projected benefit payments. Additionally, the health care cost trend rate assumption is critical to Duke Energy’s estimate of other post-retirement benefits.
Duke Energy elects to amortize net actuarial gain or loss amounts that are in excess of 10 percent of the greater of the market-related value of plan assets or the plan's projected benefit obligation, into net pension or other post-retirement benefit expense over the average remaining service period of active participants expected to benefit under the plan. If all or almost all of a traditionalplan's participants are inactive, the average remaining life expectancy of the inactive participants is used instead of average remaining service period. Prior service cost or credit, which represents an increase or decrease in a plan's pension benefit obligation resulting from plan amendment, is amortized on a straight-line basis over the average expected remaining service period of active participants expected to benefit under the plan. If all or almost all of a plan's participants are inactive, the average remaining life expectancy of the inactive participants is used instead of average remaining service period.
Duke Energy maintains and the Subsidiary Registrants participate in, qualified, non-contributory defined benefit pensionretirement plans. Most participants in the qualified plans earn benefits calculated using a cash balance formula. Under a cash balance formula, a plan (qualified pension plan) coveringparticipant accumulates a retirement benefit consisting of pay credits based upon a percentage, which varies with age and years of service, of current eligible employees. We also provide certain other postretirementearnings and current interest credits. Certain plan participants earn benefits that use a final average earnings formula. Certain executives are participants in non-qualified, non-contributory defined benefit retirement plans. These qualified and non-qualified, non-contributory defined benefit plans are closed to new participants.
Duke Energy provides some health care and life insurance benefits tofor retired employees on a contributory and non-contributory basis. Certain employees are eligible employees. For further information and our reported costs of providingfor these benefits see Note 9if they have met age and service requirements at retirement, as defined in the plans.
Assets for Duke Energy’s qualified pension and other post-retirement benefits (401(h) accounts) are maintained in the Duke Energy Master Retirement Trust (Master Trust). Duke Energy also invests other post-retirement assets in Voluntary Employees' Beneficiary Association trusts. The investment objective is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the consolidated financial statements in this Form 10-K. We recognizepurpose of promoting the security of plan benefits for participants.
As of December 31, 2017, Duke Energy assumes pension and other post-retirement plan assets will generate a long-term rate of return of 6.50 percent. The expected long-term rate of return was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers, where applicable. The asset allocation targets were set after considering the investment objective and the risk profile. Equity securities are held for their higher expected returns. Debt securities are primarily held to hedge the qualified pension liability. Hedge funds, real estate and other global securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the impact of individual managers on investments.
In 2013, Duke Energy adopted a de-risking investment strategy for the Master Trust. As the funded status of ourthe pension plans increase, the targeted allocation to fixed-income assets may be increased to better manage Duke Energy's pension liability and reduce funded status volatility. The asset allocation for the Master Trust is 63 percent fixed-income assets and 37 percent return-seeking assets. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocations when considered appropriate.
Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 3.6 percent as of December 31, 2017. Discount rates used to measure benefit plans as an assetplan obligations for financial reporting purposes reflect rates at which pension benefits could be effectively settled. As of December 31, 2017, Duke Energy determined its discount rate for U.S. pension and other post-retirement obligations using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or liabilityhigher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with anythe market value of the bonds selected.
Future changes in the funded status recorded as a regulatoryplan asset or liability as allowed by our state regulatory commissions.
The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographicsreturns, assumed discount rates and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.
Several statistical and other factors
which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the
plans. These factors include assumptions about the discount rate usedparticipants in
determiningDuke Energy’s pension and post-retirement plans will impact future
benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense
or other postretirement benefit costs recorded in future periods, and
weliabilities. Duke Energy cannot predict with certainty what these factors will be in the future.
The following table presents the approximate effect on Duke Energy’s 2017 pretax pension expense, pretax other post-retirement expense, pension obligation and other post-retirement benefit obligation if a 0.25 percent change in rates were to occur. |
| | | | | | | | | | | | | | | |
| | Qualified and Non- | | Other Post-Retirement |
| | Qualified Pension Plans | | Plans |
| (in millions) | 0.25 | % | | (0.25 | )% | | 0.25 | % | | (0.25 | )% |
| Effect on 2017 pretax pension and other post-retirement expense | | | | | | | |
| Expected long-term rate of return | $ | (21 | ) | | $ | 21 |
| | $ | (1 | ) | | $ | 1 |
|
| Discount rate | (17 | ) | | 19 |
| | (1 | ) | | 1 |
|
| Effect on pension and other post-retirement benefit obligation at December 31, 2017 | |
| | |
| | |
| | |
|
| Discount rate | (223 | ) | | 229 |
| | (17 | ) | | 17 |
|
The discount rate has been separately determined for each69
Duke Energy’s other post-retirement plan by projecting the plan’s cash flows and developinguses a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AA or better by either Moody’s or S&P that have a yield higher than the regression mean yield curve. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from 4.55% in 2013 to 4.13% in 2014. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 3.98% in 2013 to 3.69% in 2014. Similarly, the weighted average discount rate for postretirement benefits changed from 4.44% in 2013 to 4.03% in 2014. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates,rate covering both pre- and post-age 65 retired plan participants, which is comprised of a medical care trend rate, which reflects the initialnear- and long-term expectation of increases in medical costs, and a prescription drug trend rate, which reflects the near- and long-term expectation of increases in prescription drug costs. As of December 31, 2017, the health care cost trend rate was assumed7 percent, trending down to 4.75 percent by 2024. The following table presents the approximate effect on Duke Energy’s 2017 pretax other post-retirement expense and other post-retirement benefit obligation if a 1 percentage point change in the health care trend rate were to occur. These plans are closed to new hires. |
| | | | | | | |
| | Other Post-Retirement |
| | Plans |
| (in millions) | 1 | % | | (1 | )% |
| Effect on 2017 other post-retirement expense | $ | 5 |
| | $ | (4 | ) |
| Effect on other post-retirement benefit obligation at December 31, 2017 | 27 |
| | (24 | ) |
For further information, see Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans.”
Income Taxes
Duke Energy and its subsidiaries file a consolidated federal income tax return and other state returns. The Subsidiary Registrants entered into a tax-sharing agreement with Duke Energy. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. Deferred income taxes have been provided for temporary differences between GAAP and tax bases of assets and liabilities because the differences create taxable or tax-deductible amounts for future periods. ITCs associated with regulated operations are deferred and amortized as a reduction of income tax expense over the estimated useful lives of the related properties.
Accumulated deferred income taxes are valued using the enacted tax rate expected to apply to taxable income in the periods in which the deferred tax asset or liability is expected to be 7.40%settled or realized. In the event of a change in 2014 declining gradually to 5% by 2027.
In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plantax rates, deferred tax assets and other postretirement benefit assets to be approximately 55% equity securities and 45% fixed income securities.liabilities are remeasured as of the enactment date of the new rate. To the extent that the change in the value of the deferred tax represents an obligation to customers, the impact of the remeasurement is deferred to a regulatory liability. Remaining impacts are recorded in income from continuing operations. Other impacts of the Tax Act have been recorded on a provisional basis, see Note 22, “Income Taxes,” for additional information. If Duke Energy's estimate of the tax effect of reversing temporary differences is not reflective of actual outcomes, is modified to reflect new developments or interpretations of the tax law, revised to incorporate new accounting principles, or changes in the expected timing or manner of the reversal then Duke Energy's results of operations could be impacted.
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
Duke Energy relies primarily upon cash flows from operations, debt and equity issuances and its existing cash and cash equivalents to fund its liquidity and capital requirements. Duke Energy’s capital requirements arise primarily from capital and investment expenditures, repaying long-term debt and paying dividends to shareholders. Duke Energy’s projected primary sources and uses for the next three fiscal years are included in the table below. |
| | | | | | | | | | | |
| (in millions) | 2018 |
| | 2019 |
| | 2020 |
|
Uses: | |
| | |
| | |
|
| Capital expenditures | $ | 10,950 |
| | $ | 10,975 |
| | $ | 9,050 |
|
Debt maturities and reduction in short-term debt(a) | 3,135 |
| | 3,500 |
| | 2,850 |
|
Dividend payments(b) | 2,575 |
| | 2,750 |
| | 2,875 |
|
Sources: | | | | | |
| Net cash flows from operations | $ | 7,945 |
| | $ | 9,150 |
| | $ | 9,390 |
|
Debt issuances and increase in short-term debt(c) | 6,000 |
| | 7,100 |
| | 3,050 |
|
Equity issuances(d) | 2,000 |
| | 350 |
| | 350 |
|
| |
| (a) | Excludes capital leases. Duke Energy projects a reduction in short-term debt in 2020. |
| |
| (b) | Subject to approval by the Board of Directors. |
| |
| (c) | Duke Energy projects an increase in short-term debt in 2018 and 2019. |
| |
| (d) | 2018 equity issuances to be achieved through a public offering and through issuances under the Equity Distribution Agreement and the Dividend Reinvestment Program (DRIP). See Note 18 to the Consolidated Financial Statements, "Common Stock" for additional information. |
Among other provisions, the Tax Act lowers the corporate federal income tax rate from 35 percent to 21 percent and eliminates bonus depreciation for regulated utilities. For Duke Energy’s regulated operations, the reduction in federal income taxes is expected to result in lower regulated customer rates. However, due to its existing NOL (Net operating loss) position and other tax credits, Duke Energy does not expect to be a significant federal cash tax payer through at least 2022. As a result, any reduction in customer rates could cause a material reduction in consolidated cash flows from operations in the short-term. Over time, the reduction in deferred tax liabilities resulting from the Tax Act will increase Duke Energy’s regulated rate base investments and customer rates. See the Credit Ratings section below for additional information on the impact of returnthe Tax Act on the Duke Energy Registrants' credit ratings. Impacts of Tax Act to Duke Energy’s cash flows and credit metrics are subject to the regulatory actions of its state commissions and the FERC, which are currently pending. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information.
In order to strengthen its balance sheet and credit metrics and bolster cash flows, Duke Energy plans to issue $2 billion of common stock equity during 2018, including its previous plan to issue $350 million annually through its DRIP beginning in 2018, as well as reduce its capital expenditures during 2018-2022 by approximately $1 billion.
The Subsidiary Registrants generally maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. The Subsidiary Registrants, excluding Progress Energy, support their short-term borrowing needs through participation with Duke Energy and certain of its other subsidiaries in a money pool arrangement. The companies with short-term funds may provide short-term loans to affiliates participating under this arrangement. See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities,” for additional discussion of the money pool arrangement.
Duke Energy and the Subsidiary Registrants, excluding Progress Energy, may also use short-term debt, including commercial paper and the money pool, as a bridge to long-term debt financings. The levels of borrowing may vary significantly over the course of the year due to the timing of long-term debt financings and the impact of fluctuations in cash flows from operations. From time to time, Duke Energy’s current liabilities exceed current assets realized duringresulting from the use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate due to the seasonality of its businesses.
Credit Facilities and Registration Statements
See Note 6 to the Consolidated Financial Statements, "Debt and Credit Facilities," for further information regarding credit facilities and shelf registration statements available to Duke Energy and the Duke Energy Registrants.
CAPITAL EXPENDITURES
Duke Energy continues to focus on reducing risk and positioning its business for future success and will invest principally in its strongest business sectors. Duke Energy’s projected capital and investment expenditures for the next three fiscal years are included in the table below. |
| | | | | | | | | |
| (in millions) | 2018 |
| 2019 |
| 2020 |
|
| New generation | $ | 780 |
| $ | 260 |
| $ | 135 |
|
| Regulated renewables | 155 |
| 415 |
| 365 |
|
| Environmental | 610 |
| 35 |
| 30 |
|
| Nuclear fuel | 500 |
| 410 |
| 455 |
|
| Major nuclear | 390 |
| 335 |
| 230 |
|
| Customer additions | 490 |
| 485 |
| 515 |
|
| Grid modernization and other transmission and distribution projects | 2,585 |
| 3,515 |
| 3,415 |
|
| Maintenance and other | 2,665 |
| 2,445 |
| 2,230 |
|
| Total Electric Utilities and Infrastructure | 8,175 |
| 7,900 |
| 7,375 |
|
| Gas Utilities and Infrastructure | 2,350 |
| 2,275 |
| 950 |
|
| Commercial Renewables and Other | 425 |
| 800 |
| 725 |
|
| Total projected capital and investment expenditures | $ | 10,950 |
| $ | 10,975 |
| $ | 9,050 |
|
DEBT MATURITIES
See Note 6 to the Consolidated Financial Statements, "Debt and Credit Facilities," for further information regarding significant components of Current Maturities of Long-Term Debt on the Consolidated Balance Sheets.
DIVIDEND PAYMENTS
In 2017, Duke Energy paid quarterly cash dividends for the 91st consecutive year and expects to continue its policy of paying regular cash dividends in the future. There is greaterno assurance as to the amount of future dividends because they depend on future earnings, capital requirements, financial condition and are subject to the discretion of the Board of Directors.
Duke Energy targets a dividend payout ratio of between 70 percent and 75 percent, based upon adjusted diluted EPS. In 2016 and 2017, Duke Energy increased the dividend by approximately 4 percent annually. Through 2022, the annual dividend growth rate is expected to be between approximately 4 to 6 percent.
Dividend and Other Funding Restrictions of Duke Energy Subsidiaries
As discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” Duke Energy’s wholly owned public utility operating companies have restrictions on the amount of funds that can be transferred to Duke Energy through dividends, advances or loans as a result of conditions imposed by various regulators in conjunction with merger transactions. Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures and Articles of Incorporation, which, in certain circumstances, limit their ability to make cash dividends or distributions on common stock. Additionally, certain other Duke Energy subsidiaries have other restrictions, such as minimum working capital and tangible net worth requirements pursuant to debt and other agreements that limit the amount of funds that can be transferred to Duke Energy. At December 31, 2017, the amount of restricted net assets of wholly owned subsidiaries of Duke Energy that may not be distributed to Duke Energy in the form of a loan or dividend is less than 25 percent of Duke Energy’s net assets. Duke Energy does not have any legal or other restrictions on paying common stock dividends to shareholders out of its consolidated equity accounts. Although these restrictions cap the amount of funding the various operating subsidiaries can provide to Duke Energy, management does not believe these restrictions will have a significant impact on Duke Energy’s ability to access cash to meet its payment of dividends on common stock and other future funding obligations.
CASH FLOWS FROM OPERATING ACTIVITIES
Cash flows from operations of Electric Utilities and Infrastructure and Gas Utilities and Infrastructure are primarily driven by sales of electricity and natural gas, respectively, and costs of operations. These cash flows from operations are relatively stable and comprise a substantial portion of Duke Energy’s operating cash flows. Weather conditions, working capital and commodity price fluctuations and unanticipated expenses including unplanned plant outages, storms, legal costs and related settlements can affect the timing and level of cash flows from operations.
Duke Energy believes it has sufficient liquidity resources through the commercial paper markets, and ultimately, the Master Credit Facility, to support these operations. Cash flows from operations are subject to a number of other factors, including, but not limited to, regulatory constraints, economic trends and market volatility (see Item 1A, “Risk Factors,” for additional information).
At December 31, 2017, Duke Energy had cash and cash equivalents and short-term investments of $358 million.
DEBT ISSUANCES
Depending on availability based on the issuing entity, the credit rating of the issuing entity, and market conditions, the Subsidiary Registrants prefer to issue first mortgage bonds and secured debt, followed by unsecured debt. This preference is the result of generally higher credit ratings for first mortgage bonds and secured debt, which typically result in lower interest costs. Duke Energy Corporation primarily issues unsecured debt.
See to Note 6 to the Consolidated Financial Statements, "Debt and Credit Facilities," for further information regarding significant debt issuances.
Duke Energy’s capitalization is balanced between debt and equity as shown in the table below. |
| | | | | | | | |
| | Projected 2018 |
| | Actual 2017 |
| | Actual 2016 |
|
| Equity | 44 | % | | 43 | % | | 45 | % |
| Debt | 56 | % | | 57 | % | | 55 | % |
Duke Energy’s fixed charges coverage ratio, calculated using Securities and Exchange Commission (SEC) guidelines, was 2.9 times for 2017, 2.7 times for 2016 and 3.1 times for 2015.
Restrictive Debt Covenants
Duke Energy’s debt and credit agreements contain various financial and other covenants. Duke Energy's Master Credit Facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65 percent for each borrower, excluding Piedmont, and 70 percent for Piedmont. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements or sublimits thereto. As of December 31, 2017, each of the Duke Energy Registrants was in compliance with all covenants related to their debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.
Credit Ratings
Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Rating Services (S&P) and Fitch Ratings, Inc. provide credit ratings for various
Duke Energy Registrants. The following table includes Duke Energy and certain subsidiaries’ credit ratings and ratings outlook as of February 2018. |
| | | | | |
| Moody's | | S&P | | Fitch |
| Duke Energy Corporation | Negative | (a) | Stable | | Negative |
| Issuer Credit Rating | Baa1 | | A- | | BBB+ |
| Senior Unsecured Debt | Baa1 | | BBB+ | | BBB+ |
| Commercial Paper | P-2 | | A-2 | | F-2 |
| Duke Energy Carolinas | Stable | | Stable | | N/A |
| Senior Secured Debt | Aa2 | | A | | N/A |
| Senior Unsecured Debt | A1 | | A- | | N/A |
| Progress Energy | Stable | | Stable | | N/A |
| Senior Unsecured Debt | Baa2 | | BBB+ | | N/A |
| Duke Energy Progress | Stable | | Stable | | N/A |
| Senior Secured Debt | Aa3 | | A | | N/A |
| Duke Energy Florida | Stable | | Stable | | N/A |
| Senior Secured Debt | A1 | | A | | N/A |
| Senior Unsecured Debt | A3 | | A- | | N/A |
| Duke Energy Ohio | Positive | | Stable | | N/A |
| Senior Secured Debt | A2 | | A | | N/A |
| Senior Unsecured Debt | Baa1 | | A- | | N/A |
| Duke Energy Indiana | Stable | | Stable | | N/A |
| Senior Secured Debt | Aa3 | | A | | N/A |
| Senior Unsecured Debt | A2 | | A- | | N/A |
| Duke Energy Kentucky | Stable | | Stable | | N/A |
| Senior Unsecured Debt | Baa1 | | A- | | N/A |
| Piedmont Natural Gas | Negative | (a) | Stable | | N/A |
| Senior Unsecured | A2 | | A- | | N/A |
| |
| (a) | In January 2018, Moody's revised the ratings outlook for Duke Energy Corporation and Piedmont from stable to negative, principally due to risk of deterioration in credit metrics resulting from the Tax Act. See the Tax Cuts and Jobs Act section above for additional information on the Tax Act. |
Credit ratings are intended to provide credit lenders a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold. The Duke Energy Registrants’ credit ratings are dependent on the rating agencies’ assessments of their ability to meet their debt principal and interest obligations when they come due. If, as a result of market conditions or other factors, the Duke Energy Registrants are unable to maintain current balance sheet strength, or if earnings and cash flow outlook materially deteriorates, credit ratings could be negatively impacted.
Cash Flow Information
The following table summarizes Duke Energy’s cash flows for the three most recently completed fiscal years. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Cash flows provided by (used in): | | | | | |
| Operating activities | $ | 6,634 |
| | $ | 6,817 |
| | $ | 6,700 |
|
| Investing activities | (8,450 | ) | | (11,533 | ) | | (5,277 | ) |
| Financing activities | 1,782 |
| | 4,251 |
| | (2,602 | ) |
| Changes in cash and cash equivalents included in assets held for sale | — |
| | 474 |
| | 1,099 |
|
| Net (decrease) increase in cash and cash equivalents | (34 | ) | | 9 |
| | (80 | ) |
| Cash and cash equivalents at beginning of period | 392 |
| | 383 |
| | 463 |
|
| Cash and cash equivalents at end of period | $ | 358 |
| | $ | 392 |
| | $ | 383 |
|
OPERATING CASH FLOWS
The following table summarizes key components of Duke Energy’s operating cash flows for the three most recently completed fiscal years. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
|
| 2016 |
|
| 2015 |
|
| Net income | $ | 3,064 |
| | $ | 2,170 |
| | $ | 2,831 |
|
| Non-cash adjustments to net income | 5,380 |
| | 5,305 |
| | 4,800 |
|
| Contributions to qualified pension plans | (19 | ) | | (155 | ) | | (302 | ) |
| Payments for AROs | (571 | ) | | (608 | ) | | (346 | ) |
| Working capital | (1,220 | ) | | 105 |
| | (283 | ) |
| Net cash provided by operating activities | $ | 6,634 |
|
| $ | 6,817 |
|
| $ | 6,700 |
|
For the year ended December 31, 2017, compared to 2016, the variance was driven primarily by:
a $1,325 million decrease in working capital due to weather, payment of merger transaction and integration related costs and increased property tax payments in 2017.
Offset by:
a $969 million increase in net income after non-cash adjustments primarily due to the inclusion of Piedmont's earnings for a full year, favorable pricing and weather-normal retail volumes driven by the residential class in the Electric Utilities and Infrastructure Segment combined with continued strong cost control;
a $136 million decrease in contributions to qualified pension plans; and
a $37 million decrease in payments to AROs.
For the year ended December 31, 2016, compared to 2015, the variance was driven primarily by:
a $388 million increase in cash flows from working capital primarily due to the sale of the International business; and
a $147 million decrease in contributions to qualified pension plans.
Offset by:
a $262 million increase in payments for AROs; and
a $156 million decrease in net income after non-cash adjustments due to higher storm costs offset by favorable weather, increased rider revenues, higher wholesale margins and strong cost control.
INVESTING CASH FLOWS
The following table summarizes key components of Duke Energy’s investing cash flows for the three most recently completed fiscal years. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
|
| 2016 |
|
| 2015 |
|
| Capital, investment and acquisition expenditures | $ | (8,198 | ) | | $ | (13,215 | ) | | $ | (8,363 | ) |
| Available for sale securities, net | 27 |
| | 83 |
| | 3 |
|
| Net proceeds from the sales of discontinued operations and other assets, net of cash divested | — |
| | 1,418 |
| | 2,968 |
|
| Other investing items | (279 | ) | | 181 |
| | 115 |
|
| Net cash used in investing activities | $ | (8,450 | ) |
| $ | (11,533 | ) |
| $ | (5,277 | ) |
The primary use of cash related to investing activities is capital, investment and acquisition expenditures, detailed by reportable business segment in the following table. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
|
| 2016 |
|
| 2015 |
|
| Electric Utilities and Infrastructure | $ | 7,024 |
| | $ | 6,649 |
| | $ | 6,852 |
|
| Gas Utilities and Infrastructure | 907 |
| | 5,519 |
| | 234 |
|
| Commercial Renewables | 92 |
| | 857 |
| | 1,019 |
|
| Other | 175 |
| | 190 |
| | 258 |
|
| Total capital, investment and acquisition expenditures | $ | 8,198 |
|
| $ | 13,215 |
|
| $ | 8,363 |
|
For the year ended December 31, 2017, compared to 2016, the variance was driven primarily by:
a $5,017 million decrease in capital, investment and acquisition expenditures mainly due to the Piedmont acquisition in the prior year.
Partially offset by:
a $1,418 million decrease in net proceeds from sales of discontinued operations due to the prior year sale of the International business.
For the year ended December 31, 2016, compared to 2015, the variance was driven primarily by:
a $4,852 million increase in capital, investment and acquisition expenditures mainly due to the Piedmont acquisition; and
a $1,550 million decrease in net proceeds from sales of discontinued operations mainly due to the variance in proceeds between the 2015 sale of the Midwest generation business and the 2016 sale of the International business.
FINANCING CASH FLOWS
The following table summarizes key components of Duke Energy’s financing cash flows for the three most recently completed fiscal years. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Issuance of common stock | $ | — |
| | $ | 731 |
| | $ | 17 |
|
| Issuances (Repayments) of long-term debt, net | 4,593 |
| | 7,315 |
| | (74 | ) |
| Notes payable and commercial paper | (362 | ) | | (1,447 | ) | | 1,245 |
|
| Dividends paid | (2,450 | ) | | (2,332 | ) | | (2,254 | ) |
| Repurchase of common shares | — |
| | — |
| | (1,500 | ) |
| Other financing items | 1 |
| | (16 | ) | | (36 | ) |
| Net cash provided by (used in) financing activities | $ | 1,782 |
| | $ | 4,251 |
| | $ | (2,602 | ) |
For the year ended December 31, 2017, compared to 2016, the variance was driven primarily by:
a $2,722 million net decrease in proceeds from issuances of long-term debt driven principally by the prior year $3,750 million of senior unsecured notes used to fund a portion of the Piedmont acquisition, offset primarily by $900 million of first mortgage bonds issued by Duke Energy Florida in the current year to fund capital expenditures for ongoing construction and capital maintenance and for general corporate purposes;
a $731 million decrease in proceeds from stock issuances used to fund a portion of the Piedmont acquisition in 2016; and
a $118 million current year increase in dividends paid.
Partially offset by:
a $1,085 million decrease in net borrowings from notes payable and commercial paper primarily due to the use of proceeds from $1,294 million nuclear asset-recovery bonds issued at Duke Energy Florida in 2016 to pay down outstanding commercial paper.
For the year ended December 31, 2016, compared to 2015, the variance was driven primarily by:
a $7,389 million increase in proceeds from net issuances of long-term debt mainly due to the issuances of $3,750 million of senior unsecured notes used to fund a portion of the Piedmont acquisition, $1,294 million of nuclear asset-recovery bonds and other issuances primarily used to fund capital expenditures, pay down outstanding commercial paper and repay debt maturities;
a $1,500 million decrease in cash outflows due to the 2015 repurchase of 19.8 million common shares under the ASR; and
a $714 million increase in proceeds resulting from the issuance of common stock to fund the acquisition of Piedmont.
Partially offset by:
a $2,692 million increase in cash outflows for the net payments of notes payable and commercial paper primarily through the use of proceeds from $1,294 million nuclear asset-recovery bonds issued at Duke Energy Florida, further increased by the use of short-term debt in 2015 to repay long-term debt maturities at Duke Energy Florida in advance of the 2016 proceeds from the nuclear asset-recovery bonds.
Off-Balance Sheet Arrangements
Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.
Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than the assumed rate, that year’s qualified pension planwholly owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and postretirement benefits plan costscredit risk, which are not affected; instead, this gainalways included on the Consolidated Balance Sheets. The possibility of Duke Energy, either on its own or loss reduces or increaseson behalf of Spectra Energy Capital, LLC (Spectra Capital) through indemnification agreements entered into as part of the January 2, 2007, spin-off of Spectra Energy Corp, having to honor its contingencies is largely dependent upon the future costsoperations of the plans oversubsidiaries, investees and other third parties, or the average remaining service periodoccurrence of certain future events.
Duke Energy performs ongoing assessments of its respective guarantee obligations to determine whether any liabilities have been incurred as a result of potential increased non-performance risk by third parties for active employees. The expected long-term rate of return on plan assets was 8% in 2012which Duke Energy has issued guarantees.
See Note 7 to the Consolidated Financial Statements, “Guarantees and 2013. The expected long-term rate of return was reduced to 7.75%Indemnifications,” for 2014. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.78% in 2012, decreasing to 3.76% in 2013, and further decreasing to 3.72% in 2014 due to changes in the demographicsdetails of the participants.guarantee arrangements.
Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantees, there would not be a material impact to the consolidated results of operations, cash flows or financial position.
Other than the guarantee arrangements discussed above, normal operating lease arrangements and off-balance sheet debt related to non-consolidated VIEs, Duke Energy does not have any material off-balance sheet financing entities or structures. For additional information, see Notes 5, 7 and 17 to the Consolidated Financial Statements, “Commitments and Contingencies,” "Guarantees and Indemnifications" and "Variable Interest Entities," respectively.
Contractual Obligations
Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations as of December 31, 2017. |
| | | | | | | | | | | | | | | | | | | |
| | Payments Due By Period |
| | | | | | | | | | More than |
|
| | | | Less than |
| | 2-3 years |
| | 4-5 years |
| | 5 years |
|
| | | | 1 year |
| | (2019 & |
| | (2021 & |
| | (2023 & |
|
| (in millions) | Total |
| | (2018) |
| | 2020) |
| | 2022) |
| | beyond) |
|
Long-term debt(a) | $ | 49,962 |
| | $ | 3,127 |
| | $ | 7,062 |
| | $ | 6,541 |
| | $ | 33,232 |
|
Interest payments on long-term debt(b) | 30,943 |
| | 2,014 |
| | 3,590 |
| | 3,144 |
| | 22,195 |
|
Capital leases(c) | 1,601 |
| | 168 |
| | 343 |
| | 345 |
| | 745 |
|
Operating leases(c) | 1,786 |
| | 233 |
| | 386 |
| | 285 |
| | 882 |
|
Purchase obligations:(d) | |
| | |
| | |
| | |
| | |
|
Fuel and purchased power(e)(f) | 30,956 |
| | 4,506 |
| | 6,085 |
| | 4,474 |
| | 15,891 |
|
Other purchase obligations(g) | 8,726 |
| | 6,642 |
| | 1,406 |
| | 121 |
| | 557 |
|
Nuclear decommissioning trust annual funding(h) | 285 |
| | 14 |
| | 28 |
| | 28 |
| | 215 |
|
Total contractual cash obligations(i)(j) | $ | 124,259 |
| | $ | 16,704 |
| | $ | 18,900 |
| | $ | 14,938 |
| | $ | 73,717 |
|
| |
| (a) | See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities.” |
| |
| (b) | Interest payments on variable rate debt instruments were calculated using December 31, 2017, interest rates and holding them constant for the life of the instruments. |
| |
| (c) | See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies.” Amounts in the table above include the interest component of capital leases based on the interest rates stated in the lease agreements and exclude certain related executory costs. Amounts exclude contingent lease obligations. |
| |
| (d) | Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected on the Consolidated Balance Sheets have been excluded from the above table. |
| |
| (e) | Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity and natural gas transportation contracts, as well as undesignated contracts and contracts that qualify as normal purchase/normal sale (NPNS). For contracts where the price paid is based on an index, the amount is based on market prices at December 31, 2017, or the best projections of the index. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting arrangements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. |
| |
| (f) | Amounts exclude obligations under the OVEC purchase power agreement. See Note 17 to the Consolidated Financial Statements, "Variable Interest Entities," for additional information. |
| |
| (g) | Includes contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for new generation plants, wind and solar facilities, plant refurbishments, maintenance and day-to-day contract work and commitments to buy certain products. Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase cannot be determined. |
| |
| (h) | Related to future annual funding obligations to NDTF through nuclear power stations' relicensing dates. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations." |
| |
| (i) | Unrecognized tax benefits of $25 million are not reflected in this table as Duke Energy cannot predict when open income tax years will close with completed examinations. See Note 22 to the Consolidated Financial Statements, "Income Taxes." |
Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.
| |
| (j) | The table above excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing and amount of cash payments that will be required. Additionally, the table above excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of pension and other post-retirement benefit plans (see Note 21 to the Consolidated Financial Statements, "Employee Benefit Plans"), AROs, including ash management expenditures (see Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations") and regulatory liabilities (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also excluded are Deferred Income Taxes and ITCs recorded on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. |
During 2014, we recorded costsQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Management Policies
The Enterprise Risk Management policy framework at Duke Energy includes strategy, operational, project execution and financial or transaction related risks. Enterprise Risk Management includes market risk as part of $6.4 millionthe financial and transaction related risks in its framework.
Duke Energy is exposed to our qualified pension plan and postretirement benefits plan. We estimate 2015 expenses for these two plans to be in the range of $7 to $8 million representing an increase of $.6 to $1.6 million from 2014. These estimates reflect the lower discountmarket risks associated with commodity prices, interest rates and a 7.50% assumed rate of return on the plan assets.
The following reflects the sensitivity of pension costequity prices. Duke Energy has established comprehensive risk management policies to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculationmonitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are constant.
|
| | | | | | | | |
| | | Change in | | | Impact on 2014 | | | Impact on Projected |
| Actuarial Assumption | | Assumption | | | Benefit Cost | | | Benefit Obligation |
| | | | | | Increase (Decrease) In thousands |
| Discount rate | | (0.25)% | | $ | 594 | | $ | 7,566 |
| Rate of return on plan assets | | (0.25)% | | | 727 | | | N/A |
| Rate of increase in compensation | | 0.25% | | | 741 | | | 4,209 |
The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.
|
| | | | | | | | |
| | | | | | Impact on 2014 | | | Impact on Accumulated |
| | | Change in | | | Postretirement | | | Postretirement Benefit |
| Actuarial Assumption | | Assumption | | | Benefit Cost | | | Obligation |
| | | | | | Increase (Decrease) |
| | | | | | In thousands |
| Discount rate | | (0.25)% | | $ | — | | $ | 995 |
| Rate of return on plan assets | | (0.25)% | | | 14 | | | N/A |
| Health care cost trend rate | | 0.25% | | | 8 | | | 210 |
We utilize accounting methods consistently applied that are allowed under GAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Gas Supply and Regulatory Proceedings
The source of our gas supply that we distribute to our customers is contracted from a diverse portfolio of major and independent producers and marketers and interstate and intrastate pipeline and storage operators. In November 2012, we continued to diversify our supply portfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams – Transco under its Leidy Southeast expansion project to transport the Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in late 2015. Also, in October 2014, we contracted for long-term pipeline capacity from the Marcellus and Utica shale basins in central West Virginia under the ACP project that is proposed to be effectiveresponsible for the winter 2018 – 2019 season. We believe that these new natural gas supplies will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.
Natural gas demand is continuing to grow in our service area as discussed in the preceding section of “Cash Flows from Investing Activities” in this Form 10-K. For further information on our equity ventures with ACP to serve our expanding markets, see Note 12 to the consolidated financial statements in this Form 10-K.
As approved by our state regulatory commissions, secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit margins to earnings; however, the programs allow us to act as a wholesale marketer of natural gas and transportation capacity when market conditions permit and when the supply and capacity are not required to serve our retail distribution system. For further information on secondary market transactions, see Note 2 to the consolidated financial statements in this Form 10-K.
We continue to work with our regulatory commissions to earn a fair rate of return on invested capital for our shareholders and provide safe, reliable natural gas distribution service to our customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial statements in this Form 10-K.
Equity Method Investments
For information about our equity method investments, see Note 12 to the consolidated financial statements in this Form 10-K.
Environmental Matters
We have developed an environmental self-assessment plan to examine our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 8 to the consolidated financial statements in this Form 10-K.
Accounting Guidance
For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements in this Form 10-K.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to various formsoverall approval of market risk including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with definedmanagement policies and procedures under the directiondelegation of approval and authorization levels. The Finance and Risk Management Committee of the Treasurer andBoard of Directors receives periodic updates from the Chief Risk Officer and our Enterpriseother members of management on market risk positions, corporate exposures and overall risk management activities. The Chief Risk Management (ERM) program,Officer is responsible for the overall governance of managing commodity price risk, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight,monitoring exposure limits.
The following disclosures about market risk contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and senior management takes an active roleuncertainties that could cause actual results or outcomes to differ materially from those expressed in the developmentforward-looking statements. Please review Item 1A, “Risk Factors,” and “Cautionary Statement Regarding Forward-Looking Information” for a discussion of the factors that may impact any such forward-looking statements made herein.
Commodity Price Risk
Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. Duke Energy’s exposure to these fluctuations is limited by the cost-based regulation of its regulated operations as these operations are typically allowed to recover substantially all of these costs through various cost-recovery clauses, including fuel clauses, formula based contracts, or other cost-sharing mechanisms. While there may be a delay in timing between when these costs are incurred and when they are recovered through rates, changes from year to year generally do not have a material impact on operating results of these regulated operations.
Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. Duke Energy employs established policies and procedures.procedures to manage risks associated with these market fluctuations, which may include using various commodity derivatives, such as swaps, futures, forwards and options. For additional information, see Note 14 to the Consolidated Financial Statements, “Derivatives and Hedging.”
The inputs and methodologies used to determine the fair value of contracts are validated by an internal group separate from Duke Energy’s deal origination function. While Duke Energy uses common industry practices to develop its valuation techniques, changes in its pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.
Hedging Strategies
Duke Energy closely monitors risks associated with commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, coal and natural gas forward contracts and options to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge against exposure to the prices of power, fuel for generation and natural gas for customers.
The majority of instruments used to manage Duke Energy’s commodity price exposure are either not designated as hedges or do not qualify for hedge accounting. These instruments are referred to as undesignated contracts. Mark-to-market changes for undesignated contracts entered into by regulated businesses are reflected as regulatory assets or liabilities on the Consolidated Balance Sheets. Undesignated contracts entered into by unregulated businesses are marked-to-market each period, with changes in the fair value of the derivative instruments reflected in earnings.
Duke Energy may also enter into other contracts that qualify for the NPNS exception. When a contract meets the criteria to qualify as NPNS, Duke Energy applies such exception. Income recognition and realization related to NPNS contracts generally coincide with the physical delivery of the commodity. For contracts qualifying for the NPNS exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract as long as the transaction remains probable of occurring.
Generation Portfolio Risks
The Duke Energy Registrants optimize the value of their generation portfolios, which include generation assets, fuel and emission allowances. Modeled forecasts of future generation output and fuel requirements are based on forward power and fuel markets. The component pieces of the portfolio are bought and sold based on models and forecasts of generation in order to manage the economic value of the portfolio in accordance with the strategies of the business units.
During our current fiscal year,77
For the BoardElectric Utilities segment, the generation portfolio not utilized to serve retail operations or committed load is subject to commodity price fluctuations. However, the impact on the Consolidated Statements of Directors delegated oversightOperations is partially offset by mechanisms in these regulated jurisdictions that result in the sharing of our ERM programnet profits from these activities with retail customers.
Interest Rate Risk
Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed-rate debt and commercial paper. Duke Energy manages interest rate exposure by limiting variable-rate exposures to a percentage of total debt and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, which may include instruments such as, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. See Notes 1, 6, 14 and 16 to the FinanceConsolidated Financial Statements, “Summary of Significant Accounting Policies,” “Debt and Enterprise Risk (FER) Committee. All other committeesCredit Facilities,” “Derivatives and Hedging,” and “Fair Value Measurements.”
At December 31, 2017, Duke Energy had $687 million notional amount of our Boardfloating-to-fixed swaps outstanding, $500 million notional amount of Directors have enhanced monitoringfixed-to-floating swaps outstanding and $400 million forward-starting swaps outstanding. Duke Energy had $6.1 billion of those risks relatingunhedged long- and short-term floating interest rate exposure at December 31, 2017. The impact of a 100 basis point change in interest rates on pretax income is approximately $61 million at December 31, 2017. This amount was estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges as of December 31, 2017.
See Note 14, "Derivatives and Hedging," to areas where they have oversight responsibility. The Board of Directors approved risk tolerancesthe Consolidated Financial Statements for major areas of risk exposure and will receive quarterly reports fromadditional information about the FER Committee and annual reports from management.forward-starting interest rate swaps related to the Piedmont acquisition.
We hold all financial instruments discussed below for purposes other than trading.
Credit Risk
Credit risk represents the loss that the Duke Energy Registrants would incur if a counterparty fails to perform under its contractual obligations. Where exposed to credit risk, the Duke Energy Registrants analyze the counterparty's financial condition prior to entering into an agreement and monitor exposure on an ongoing basis. The Duke Energy Registrants establish credit limits where appropriate in the context of contractual arrangements and monitor such limits.
We enter into contractsTo reduce credit exposure, the Duke Energy Registrants seek to include netting provisions with third partiescounterparties, which permit the offset of receivables and payables with such counterparties. The Duke Energy Registrants also frequently use master agreements with credit support annexes to buy and sell natural gas. Our policy requires counterpartiesfurther mitigate certain credit exposures. The master agreements provide for a counterparty to have an investment-grade credit rating at the time of the contract,post cash or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents a negotiated unsecured credit limit for each party to the agreement, determined in accordance with the Duke Energy Registrants’ internal corporate credit practices and standards. Collateral agreements generally also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.
The Duke Energy Registrants also obtain cash or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and durationletters of credit from certain counterparties to provide credit support outside of collateral agreements, where appropriate, based on a financial analysis of the counterparty’scounterparty and the regulatory or contractual terms and conditions applicable to each transaction. See Note 14 to the Consolidated Financial Statements, “Derivatives and Hedging,” for additional information regarding credit rating and/risk related to derivative instruments.
The Duke Energy Registrants’ principal counterparties for its electric and natural gas businesses are regional transmission organizations, distribution companies, municipalities, electric cooperatives and utilities located throughout the U.S. The Duke Energy Registrants have concentrations of receivables from such entities throughout these regions. These concentrations of receivables may affect the Duke Energy Registrants’ overall credit risk in that risk factors can negatively impact the credit quality of the entire sector.
The Duke Energy Registrants are also subject to credit risk from transactions with their suppliers that involve prepayments in conjunction with outsourcing arrangements, major construction projects and certain commodity purchases. The Duke Energy Registrants’ credit exposure to such suppliers may take the form of increased costs or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. Inproject delays in the event that a partyof non-performance. The Duke Energy Registrants' frequently require guarantees or letters of credit from suppliers to mitigate this credit risk.
Credit risk associated with the Duke Energy Registrants’ service to residential, commercial and industrial customers is unablegenerally limited to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management ofoutstanding accounts receivable. The Duke Energy Registrants mitigate this third party.
We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In all three states, gas costs related to uncollectible accounts are recovered through PGA procedures. To manage the non-gas cost customer credit risk we evaluateby requiring customers to provide a cash deposit, letter of credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standardsor surety bond until a satisfactory payment history is established, subject to the rules and regulations in effect in each retail jurisdiction, at which time the deposit is typically refunded. Charge-offs for retail customers have historically been insignificant to the operations of the Duke Energy Registrants and are typically recovered through retail rates. Management continually monitors customer charge-offs and payment patterns to ensure the adequacy of bad debt reserves. Duke Energy Ohio and Duke Energy Indiana sell certain of their accounts receivable and related collections through Cinergy Receivables Company LLC (CRC), a Duke Energy consolidated variable interest entity. Losses on collection are first absorbed by the equity of CRC and next by the subordinated retained interests held by Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana. See Note 17 to the Consolidated Financial Statements, “Variable Interest Entities.”
Duke Energy Carolinas has been established. Significant increasesthird-party insurance to cover certain losses related to asbestos-related injuries and damages above an aggregate self-insured retention. Duke Energy Carolinas’ cumulative payments began to exceed the self-insurance retention in 2008. Future payments up to the pricepolicy limit will be reimbursed by the third-party insurance carrier. The insurance policy limit for potential future insurance recoveries indemnification and medical cost claim payments is $797 million in excess of natural gas or colder-than-normal weather can slow our collection effortsthe self-insured retention. Receivables for insurance recoveries were $489 million and $587 million at December 31, 2017, and 2016, respectively. These amounts are classified in Other within Other Noncurrent Assets on the Consolidated Balance Sheets. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Duke Energy Carolinas believes the insurance recovery asset is probable of recovery as customers experience increased difficulty in paying their gas bills, leadingthe insurance carrier continues to higher than normal accounts receivable.have a strong financial strength rating.
PART II
Interest Rate Risk
We are exposedThe Duke Energy Registrants also have credit risk exposure through issuance of performance and financial guarantees, letters of credit and surety bonds on behalf of less than wholly owned entities and third parties. Where the Duke Energy Registrants have issued these guarantees, it is possible that they could be required to interest rateperform under these guarantee obligations in the event the obligor under the guarantee fails to perform. Where the Duke Energy Registrants have issued guarantees related to assets or operations that have been disposed of via sale, they attempt to secure indemnification from the buyer against all future performance obligations under the guarantees. See Note 7 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further information on guarantees issued by the Duke Energy Registrants.
Based on the Duke Energy Registrants’ policies for managing credit risk, their exposures and their credit and other reserves, the Duke Energy Registrants do not currently anticipate a materially adverse effect on their consolidated financial position or results of operations as a result of non-performance by any counterparty.
Marketable Securities Price Risk
As described further in Note 15 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” Duke Energy invests in debt and equity securities as part of various investment portfolios to fund certain obligations. The vast majority of investments in equity securities are within the NDTF and assets of the various pension and other post-retirement benefit plans.
Pension Plan Assets
Duke Energy maintains investments to facilitate funding the costs of providing non-contributory defined benefit retirement and other post-retirement benefit plans. These investments are exposed to price fluctuations in equity markets and changes in interest rates on short-term debt.rates. The equity securities held in these pension plans are diversified to achieve broad market participation and reduce the impact of any single investment, sector or geographic region. Duke Energy has established asset allocation targets for its pension plan holdings, which take into consideration the investment objectives and the risk profile with respect to the trust in which the assets are held. See Note 21 to the Consolidated Financial Statements, “Employee Benefit Plans,” for additional information regarding investment strategy of pension plan assets.
A significant decline in the value of plan asset holdings could require Duke Energy to increase funding of its pension plans in future periods, which could adversely affect cash flows in those periods. Additionally, a decline in the fair value of plan assets, absent additional cash contributions to the plan, could increase the amount of pension cost required to be recorded in future periods, which could adversely affect Duke Energy’s results of operations in those periods.
Nuclear Decommissioning Trust Funds
As required by the NRC, NCUC, PSCSC and FPSC, subsidiaries of Duke Energy maintain trust funds to fund the costs of nuclear decommissioning. As of OctoberDecember 31, 2014, all2017, these funds were invested primarily in domestic and international equity securities, debt securities, cash and cash equivalents and short-term investments. Per the NRC, Internal Revenue Code, NCUC, PSCSC and FPSC requirements, these funds may be used only for activities related to nuclear decommissioning. These investments are exposed to price fluctuations in equity markets and changes in interest rates. Duke Energy actively monitors its portfolios by benchmarking the performance of our long-term debt was issued at fixed rates,its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes.
Accounting for nuclear decommissioning recognizes that costs are recovered through retail and wholesale rates; therefore, fluctuations in investment prices do not subjectmaterially affect the Consolidated Statements of Operations, as changes in the fair value of these investments are primarily deferred as regulatory assets or regulatory liabilities pursuant to interest rate risk.
We have short-term borrowing arrangements to provide working capitalOrders by the NCUC, PSCSC, FPSC and general corporate liquidity. The levelFERC. Earnings or losses of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects,fund will ultimately impact the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.
As of October 31, 2014, we had $355 million of short-term debt outstanding as commercial paper at an interest rate of .17%. The carrying amount of our short-term debt approximates fair value. A changecosts recovered through retail and wholesale rates. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information regarding nuclear decommissioning costs. See Note 15 to the Consolidated Financial Statements, “Investments in Debt and Equity Securities,” for additional information regarding NDTF assets.
OTHER MATTERS
Ratios of 100 basis pointsEarnings to Fixed Charges
The Duke Energy Registrants’ ratios of earnings to fixed charges, as calculated using SEC guidelines, are included in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $4.4 million during 2014.tables below.
As of October 31, 2014, information about our long-term debt is presented below. |
| | | | | | | | |
| | Years Ended December 31, |
| | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | 2.9 |
| | 2.7 |
| | 3.1 |
|
| Duke Energy Carolinas | 4.8 |
| | 4.7 |
| | 4.7 |
|
| Progress Energy | 2.7 |
| | 3.0 |
| | 2.9 |
|
| Duke Energy Progress | 4.1 |
| | 4.0 |
| | 3.7 |
|
| Duke Energy Florida | 3.3 |
| | 4.3 |
| | 4.3 |
|
| Duke Energy Ohio | 3.4 |
| | 3.8 |
| | 3.6 |
|
| Duke Energy Indiana | 4.4 |
| | 4.1 |
| | 3.6 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Fair Value as |
| | | Expected Maturity Date | | | | of October 31, |
| In millions | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | Thereafter | | Total | | 2014 |
| Fixed Rate Long-term Debt | | $ | — |
| | $ | 40 |
| | $ | 35 |
| | $ | — |
| | $ | — |
| | $ | 1,350 |
| | $ | 1,425 |
| | $ | 1,617.5 |
|
| Average Interest Rate | | — | % | | 2.92 | % | | 8.51 | % | | — | % | | — | % | | 4.88 | % | | 4.92 | % | | |
|
| | | | | | | | | | | |
| | Year Ended | | Two Months Ended | | Years Ended October 31, |
| | December 31, 2017 |
| | December 31, 2016 |
| | 2016 | | 2015 |
| Piedmont | 3.3 |
| | 6.6 |
| | 4.7 |
| | 3.7 |
|
WeEnvironmental Regulations
The Duke Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time and result in new obligations of the Duke Energy Registrants.
The following sections outline various proposed and recently enacted legislation and regulations that may impact the Duke Energy Registrants. Refer to Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for further information regarding potential plant retirements and regulatory filings related to the Duke Energy Registrants.
Coal Combustion Residuals
In April 2015, EPA published a rule to regulate the disposal of CCR from electric utilities as solid waste. The federal regulation classifies CCR as nonhazardous waste and allows for beneficial use of CCR with some restrictions. The regulation applies to all new and existing landfills, new and existing surface impoundments receiving CCR and existing surface impoundments that are no longer receiving CCR but contain liquid located at stations currently generating electricity (regardless of fuel source). The rule establishes requirements regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring, protection and remedial procedures and other operational and reporting procedures to ensure the safe disposal and management of CCR. Various industry and environmental parties have mitigatedappealed EPA's CCR rule in the cash flow risk resultingU.S. Court of Appeals for the District of Columbia (D.C. Circuit Court). On April 18, 2016, EPA filed a motion with the federal court to settle five issues raised in litigation. On June 14, 2016, the court approved the motion with respect to all of those issues. Duke Energy does not expect a material impact from commodity purchasethe settlement or that it will result in additional ARO adjustments. On September 13, 2017, EPA responded to a petition by the Utility Solid Waste Activities Group that the agency would reconsider certain provisions of the final rule, and asked the D.C. Circuit Court to suspend the litigation. The D.C. Circuit Court denied EPA’s petition to suspend the litigation and oral argument was held on November 20, 2017. The court has not issued an order in the matter. Duke Energy cannot predict the outcome of the litigation.
In a November 15, 2017, status report filed with the D.C. Circuit Court, EPA listed the provisions it intends to reconsider, including provisions that warrant revision due to passage of the Water Infrastructure Improvements for the Nation Act, which allows for implementation of the CCR rule through state or federal permit programs. EPA has indicated it will issue a proposed rule in early 2018 that includes provisions from the June 2016 settlement with petitioners and additional provisions under reconsideration. The reconsideration would not repeal the CCR rule; rather, it would modify some requirements to align with the implementation of the rule through permit programs. At this time, Duke Energy does not expect a reconsideration rulemaking to have a material impact on its coal ash basin closure plans or compliance requirements under the CCR rule.
In addition to the requirements of the federal CCR regulation, CCR landfills and surface impoundments will continue to be independently regulated by most states. Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions and via wholesale contracts, under our regulatory gas cost recovery mechanisms thatwhich permit the recovery of these costs in a timely manner. However, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, includingnecessary and prudently incurred costs associated with our hedging programs underDuke Energy’s regulated operations. For more information, see Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations."
Coal Ash Management Act of 2014
AROs recorded on the Duke Energy Carolinas and Duke Energy Progress Consolidated Balance Sheets at December 31, 2017, and December 31, 2016, include the legal obligation for closure of coal ash basins and the disposal of related ash as a result of the Coal Ash Act, the EPA CCR rule and other agreements. The Coal Ash Act requires Duke Energy to undertake dam improvement projects and to provide access to a permanent alternative drinking water source to certain residents within a half-mile of coal ash basin compliance boundaries and to certain other potentially impacted residents. The legislation requires excavation of the Sutton, Riverbend and Dan River basins by August 1, 2019, and Asheville basins by August 1, 2022. Excavation at these sites may include a combination of transfer of coal ash to an engineered landfill or conversion for beneficial use. Basins at the H.F. Lee, Cape Fear and Weatherspoon sites are required to be closed through excavation no later than August 1, 2028. Excavation at these sites can include conversion of the basin to a lined industrial landfill, transfer of ash to an engineered landfill or conversion for beneficial use. The remaining basins are required to be closed no later than December 31, 2024, through conversion to a lined industrial landfill, transfer to an engineered landfill or conversion for beneficial use, unless certain dam improvement projects and alternative drinking water source projects are completed by October 15, 2018. Upon satisfactory completion of these projects, the closure deadline would be extended to December 31, 2029, and could include closure through the combination of a cap system and a groundwater monitoring system.
Additionally, the Coal Ash Act requires the installation and operation of three large-scale coal ash beneficiation projects to produce reprocessed ash for use in the concrete industry. Duke Energy selected the Buck, H.F. Lee and Cape Fear plants for these projects. Closure at these sites is required to be completed no later than December 31, 2029.
The Coal Ash Act includes a variance procedure for compliance deadlines and other issues surrounding the management of CCR and CCR surface impoundments and prohibits cost recovery mechanism allowedin customer rates for unlawful discharge of ash impoundment waters occurring after January 1, 2014. The Coal Ash Act leaves the decision on cost recovery determinations related to closure of ash impoundments to the normal ratemaking processes before utility regulatory commissions. Consistent with the requirements of the Coal Ash Act, Duke Energy has submitted comprehensive site assessments and groundwater corrective plans to NCDEQ and will submit to NCDEQ site-specific coal ash impoundment closure plans in advance of closure. These plans and all associated permits must be approved by eachNCDEQ before closure work can begin.
For further information on AROs, see Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations.”
Clean Water Act 316(b)
EPA published the final 316(b) cooling water intake structure rule on August 15, 2014, with an effective date of ourOctober 14, 2014. The rule applies to 26 of the electric generating facilities the Duke Energy Registrants own and operate. The rule allows for several options to demonstrate compliance and provides flexibility to the state regulators. Under our PGA procedures, differencesenvironmental permitting agencies to make determinations on controls, if any, that will be required for cooling water intake structures. Any required intake structure modifications and/or retrofits are expected to be installed in the 2019 to 2023 time frame. Petitions challenging the rule have been filed by several groups. Oral argument was held on September 14, 2017. It is unknown when the courts will rule on the petitions. The Duke Energy Registrants cannot predict the outcome of these matters.
Steam Electric Effluent Limitations Guidelines
On January 4, 2016, the final Steam Electric Effluent Limitations Guidelines (ELG) rule became effective. The rule establishes new requirements for wastewater streams associated with steam electric power generation and includes more stringent controls for any new coal plants that may be built in the future. As originally written, affected facilities were required to comply between 2018 and 2023, depending on the timing of Clean Water Act (CWA) discharge permits. Most of the steam electric generating facilities the Duke Energy Registrants own are affected sources. The Duke Energy Registrants are well-positioned to meet the majority of the requirements of the rule due to current efforts to convert to dry ash handling. Petitions challenging the rule have been filed by several groups. On March 16, 2015, Duke Energy Indiana filed its own legal challenge to the rule with the Seventh Circuit Court of Appeals specific to the ELG rule focused on the limits imposed on IGCC facilities (gasification wastewater). All challenges to the rule were consolidated in the Fifth Circuit Court of Appeals. On August 22, 2017, the Fifth Circuit Court of Appeals granted EPA’s Motion to Govern Further Proceedings, thereby severing and suspending the claims related to flue gas desulfurization wastewater, bottom ash transport water and gasification wastewater. Claims regarding gasification wastewater were stayed, pending the issuance of the variance to Duke Energy Indiana. The litigation will continue as to claims related to other waste streams.
On August 7, 2017, EPA issued a public notice regarding its proposed decision to grant a variance to Duke Energy Indiana for mercury and total dissolved solids for gasification wastewater at its Edwardsport facility. The public comment period has ended, but EPA has not finalized its decision. Separate from the litigation, EPA finalized a rule on September 18, 2017, postponing the earliest applicability date for bottom ash transport water and flue gas desulfurization wastewater from 2018 to 2020 and retaining the end applicability date of 2023. Also, as part of the rule, EPA reiterated its intent to review the limitation guidelines for bottom ash transport water and flue gas desulfurization wastewater and potentially to conduct a new rulemaking to revise those guidelines.
The Duke Energy Registrants cannot predict the outcome of these matters.
Estimated Cost and Impacts of Rulemakings
Duke Energy will incur capital expenditures to comply with the environmental regulations and rules discussed above. The following table provides five-year estimated costs, excluding AFUDC, of new control equipment that may need to be installed on existing power plants primarily to comply with the Coal Ash Act requirements for conversion to dry disposal of bottom ash and fly ash, CWA 316(b) and ELGs through December 31, 2022. The table excludes ash basin closure costs recorded in Asset retirement obligations on the Consolidated Balance Sheets. For more information related to AROs, see Note 9 to the Consolidated Financial Statements. |
| | | |
| (in millions) | Five-Year Estimated Costs |
|
| Duke Energy | $ | 920 |
|
| Duke Energy Carolinas | 380 |
|
| Progress Energy | 360 |
|
| Duke Energy Progress | 230 |
|
| Duke Energy Florida | 130 |
|
| Duke Energy Ohio | 70 |
|
| Duke Energy Indiana | 110 |
|
The Duke Energy Registrants also expect to incur increased fuel, purchased power, operation and maintenance and other expenses, in addition to costs for replacement generation for potential coal-fired power plant retirements, as a result of these regulations. Actual compliance costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts duemay be materially different from customers” in “Regulatory Assets” or any over-recoveries are included in “Amountsthese estimates due to customers” in “Regulatory Liabilities”reasons such as presented in Note 1the timing and requirements of EPA regulations and the resolution of legal challenges to the consolidated financial statements in this Form 10-K, for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts duerules. The Duke Energy Registrants intend to customers,” we incur a carrying charge that we must refundseek rate recovery of necessary and prudently incurred costs associated with regulated operations to our customers.comply with these regulations.
We manage our gas supply costs through81
Cross-State Air Pollution Rule
On December 3, 2015, EPA proposed a portfoliorule to lower the Cross-State Air Pollution Rule (CSAPR) Phase 2 state ozone season nitrogen oxide (NOX) emission budgets for 23 eastern states, including North Carolina, Ohio, Kentucky and Indiana. EPA also proposed to eliminate the CSAPR Phase 2 ozone season state NOX budgets for Florida and South Carolina. On September 7, 2016, EPA finalized a CSAPR Update Rule that reduces the CSAPR Phase 2 state ozone season NOX emission budgets for 22 eastern states, including Ohio, Kentucky and Indiana. In the final CSAPR Update Rule, EPA removed Florida, South Carolina and North Carolina from the ozone season NOx program. Beginning in 2017, Duke Energy Registrants in these states will not be subject to any CSAPR ozone season NOx emission limitations. For the states that remain in the program, the reduced state ozone season NOx emission budgets took effect on May 1, 2017. In Kentucky and Indiana, where Duke Energy Registrants own and operate coal-fired electric generating units (EGUs) subject to the final rule requirements, near-term responses include changing unit dispatch to run certain generating units less frequently and/or purchasing NOx allowances from the trading market. Longer term, upgrading the performance of short-existing NOx controls is an option. The Indiana Utility Group and long-term procurementthe Indiana Energy Association jointly filed a petition for reconsideration asking that EPA correct errors it made in calculating the Indiana budget and increase the budget accordingly. EPA has yet to act on the petition. Numerous parties have filed petitions with the D.C. Circuit Court challenging various aspects of the CSAPR Update Rule. Final briefs in the case are due April 9, 2018. The date for oral argument has not been established. The Duke Energy Registrants cannot predict the outcome of these matters.
Carbon Pollution Standards for New, Modified and Reconstructed Power Plants
On October 23, 2015, EPA published a final rule in the Federal Register establishing carbon dioxide (CO2) emissions limits for new, modified and reconstructed power plants. The requirements for new plants apply to plants that commenced construction after January 8, 2014. EPA set an emissions standard for coal units of 1,400 pounds of CO2 per gross MWh, which would require the application of partial carbon capture and storage contracts with various suppliers. We actively manage our supply portfolio(CCS) technology for a coal unit to balance salesbe able to meet the limit. Utility-scale CCS is not currently a demonstrated and delivery obligations. We injectcommercially available technology for coal-fired EGUs, and therefore the final standard effectively prevents the development of new coal-fired generation. EPA set a final standard of 1,000 pounds of CO2 per gross MWh for new natural gas into storage duringcombined-cycle units.
On March 28, 2017, President Trump signed an executive order directing EPA to review the summer monthsrule and withdrawdetermine whether to suspend, revise or rescind it. On the gas duringsame day, the winter heating season. InDepartment of Justice (DOJ) filed a motion with the normal courseD.C. Circuit Court requesting that the court stay the litigation of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments of various durations to hedge price volatility on a portion of our natural gas requirements, subject to regulatory review and approval.
We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe thatrule while it is unlikelyreviewed by EPA. Subsequent to the DOJ motion, the D.C. Circuit Court canceled oral argument in the case. On August 10, 2017, the court ordered that the litigation be suspended indefinitely. The rule remains in effect pending the outcome of litigation and EPA’s review. EPA has not announced a supplier default would have aschedule for completing its review. The Duke Energy Registrants cannot predict the outcome of these matters, but do not expect the impacts of the current final standards will be material effect on ourto Duke Energy's financial position, results of operations or cash flows.
Clean Power Plan
Our gas purchasing practicesOn October 23, 2015, EPA published in the Federal Register the final Clean Power Plan (CPP) rule that regulates CO2 emissions from existing fossil fuel-fired EGUs. The CPP established CO2 emission rates and mass cap goals that apply to existing fossil fuel-fired EGUs. Petitions challenging the rule were filed by several groups and on February 9, 2016, the Supreme Court issued a stay of the final CPP rule, halting implementation of the rule until legal challenges are subject to regulatory reviews in all three statesresolved. States in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Coststhe Duke Energy Registrants operate have never been disallowedsuspended work on the basisCPP in response to the stay. Oral arguments before 10 of prudencethe 11 judges on D.C. Circuit Court were heard on September 27, 2016. The court has not issued its opinion in any jurisdiction.the case.
On March 28, 2017, President Trump signed an executive order directing EPA to review the CPP and determine whether to suspend, revise or rescind the rule. On the same day, the DOJ filed a motion with the D.C. Circuit Court requesting that the court stay the litigation of the rule while it is reviewed by EPA. On April 28, 2017, the court issued an order to suspend the litigation for 60 days. On August 8, 2017, the court, on its own motion, extended the suspension of the litigation for an additional 60 days. On October 16, 2017, EPA issued a Notice of Proposed Rulemaking (NPR) to repeal the CPP based on a change to EPA’s legal interpretation of the section of the Clean Air Act (CAA) on which the CPP was based. In the proposal, EPA indicates that it has not determined whether it will issue a rule to replace the CPP, and if it will do so, when and what form that rule will take. The comment period on EPA's NPR ends April 26, 2018. On December 28, 2017, EPA issued an Advance Notice of Proposed Rulemaking (ANPRM) in which it seeks public comment on various aspects of a potential CPP replacement rule. The comment period on the ANPRM ends February 26, 2018. If EPA decides to move forward with a CPP replacement rule, it will need to issue a formal proposal for public comment. Litigation of the CPP remains on hold in the D.C. Circuit Court and the February 2016 U.S. Supreme Court stay of the CPP remains in effect. The Duke Energy Registrants cannot predict the outcome of these matters.
Global Climate Change
The Duke Energy Registrants’ greenhouse gas (GHG) emissions consist primarily of CO2 and result primarily from operating a fleet of coal-fired and natural gas-fired power plants. In 2017, the Duke Energy Registrants’ power plants emitted approximately 105 million tons of CO2. Future levels of CO2 emissions will be influenced by variables that include fuel prices, compliance with new or existing regulations, economic conditions that affect electricity demand and the technologies deployed to generate the electricity necessary to meet the customer demand.
PART II
Weather Risk
WeThe Duke Energy Registrants have taken actions that have resulted in a reduction of CO2 emissions over time. Actions have included the retirement of 47 coal-fired EGUs with a combined generating capacity of 5,425 MW. Much of that capacity has been replaced with state-of-the-art highly efficient natural gas-fired generation that produces far fewer CO2 emissions per unit of electricity generated. Duke Energy also has made investments to expand its portfolio of wind and solar projects, increase energy efficiency offerings and invest in its zero-CO2 emissions hydropower and nuclear plants. These efforts have diversified its system and significantly reduced CO2 emissions. Between 2005 and 2017, the Duke Energy Registrants have collectively lowered the CO2 emissions from their electricity generation by more than 31 percent, which lowers the exposure to any future mandatory CO2 emission reduction requirements or carbon tax, whether as a result of federal legislation, EPA regulation, state regulation or other as yet unknown emission reduction requirement. Duke Energy will continue to explore the use of currently-available and commercially-demonstrated technology to reduce CO2 emissions, including energy efficiency, wind, solar, storage, nuclear and carbon sequestration. Duke Energy will adjust to evolving and innovative technologies in a way that balances the reliability and affordability that customers expect. Under any future scenario involving mandatory CO2 limitations, the Duke Energy Registrants would plan to seek recovery of their compliance costs through appropriate regulatory mechanisms.
The Duke Energy Registrants recognize certain groups associate severe weather events with increasing levels of GHGs in the atmosphere and forecast the possibility these weather events could have a material impact on future results of operations should they occur more frequently and with greater severity. However, the uncertain nature of potential changes in extreme weather events (such as increased frequency, duration and severity), the long period of time over which any potential changes might take place and the inability to predict potential changes with any degree of accuracy, make estimating any potential future financial risk to the Duke Energy Registrants’ operations impossible. The Duke Energy Registrants have historically planned and prepared for extreme weather events, such as ice storms, tornadoes, hurricanes, severe thunderstorms, high winds and droughts they occasionally experience.
The Duke Energy Registrants annually, biannually or triennially prepare lengthy, forward-looking “integrated resource plans” (IRPs). These detailed, highly technical plans are exposedbased on the company’s thorough analysis of numerous factors that can impact the cost of producing and delivering electricity that influence long-term resource planning decisions. The IRP process helps to weatherevaluate a range of options, taking into account forecasts of future electricity demand, fuel prices, transmission improvements, new generating capacity, integration of renewables, energy storage, energy efficiency and demand response initiatives. The IRP process also helps evaluate potential environmental and regulatory scenarios to better mitigate policy and economic risks. The IRPs we file with regulators look out 10 to 20 years depending on the jurisdiction.
For a number of years, the Duke Energy Registrants have included a price on CO2 emissions in their IRP planning process to account for the potential regulation of CO2 emissions. Incorporating a price on CO2 emissions in the IRP allows for the evaluation of existing and future resource needs against potential climate change policy risk in our regulated utility segmentthe absence of policy certainty. One of the challenges with using a CO2 price, especially in South Carolinathe absence of a clear and Tennessee where revenues are collected from volumetric rates withoutcertain policy, is determining the appropriate price to use. To address this uncertainty and ensure the company remains agile, the Duke Energy Registrants typically use a margin decoupling mechanism. Our ratesrange of potential CO2 prices to reflect a range of potential policy outcomes.
The Duke Energy Registrants routinely take steps to reduce the potential impact of severe weather events on their electric distribution systems. The Duke Energy Registrants’ electric generating facilities are designed based onto withstand extreme weather events without significant damage. The Duke Energy Registrants maintain an assumptioninventory of normal weather. This risk is mitigatedcoal and oil on-site to mitigate the effects of any potential short-term disruption in fuel supply so they can continue to provide customers with an uninterrupted supply of electricity.
North Carolina Legislation
In July 2017, the North Carolina General Assembly passed House Bill 589 and it was subsequently enacted into law by the governor. The law includes, among other things, overall reform of the application of Public Utility Regulatory Policies Act of 1978 (PURPA) for new solar projects in the state, a WNA mechanismrequirement for the utility to procure approximately 2,600 MW of renewable energy through a competitive bidding process and recovery of costs related to the competitive bidding process through the fuel clause and a competitive procurement rider. The law stipulated certain deadlines for Duke Energy to file for NCUC approval of programs required under the law. Duke Energy has made some regulatory filings since the passage of the law and will continue to implement the requirements of House Bill 589.
Nuclear Matters
Following the events at the Fukushima Daiichi nuclear power station in Japan, in March 2011, the NRC formed a task force to conduct a comprehensive review of processes and regulations to determine whether the agency should make additional improvements to the nuclear regulatory system. Subsequently, the NRC targeted a set of improvements designed to offsetenhance accident mitigation, strengthen emergency preparedness and improve efficiency of NRC programs. Pursuant to the findings of the task force, in March 2012, the NRC issued three regulatory orders requiring safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at a plant, ensuring reliable hardened containment vents and enhancing spent fuel pool instrumentation. Duke Energy is committed to compliance with all safety enhancements ordered by the NRC and has completed actions on two of the three NRC orders, as required. The remaining order is focused only on enhancements to boiling water reactor designs which, for Duke Energy, is unique to Brunswick Steam Electric Plant. Actions associated with this third order will be completed by March 2019. With the NRC’s continuing review of this matter, Duke Energy cannot predict to what extent the NRC will impose additional licensing and safety-related requirements or the costs of complying with such requirements. Upon receipt of additional guidance from the NRC and a collaborative industry review, Duke Energy will be able to determine an implementation plan and associated costs. See Item 1A, “Risk Factors,” for further discussion of applicable risk factors.
New Accounting Standards
See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets during the months of November through March in South Carolina and October through April in Tennessee. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In North Carolina, we manage our weather risk through a year round margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold. We are exposed to weather risks in our industrial markets to the extent our margin is collected through volumetric rates in all of our jurisdictions.new accounting standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s83
See “Management’s Discussion and Analysis of Results of Operations and Financial Condition – Quantitative and Results of Operations.
Item 8. Financial Statements and Supplementary DataQualitative Disclosures About Market Risk.”
Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of this Form 10-K.84
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
| |
| Duke Energy Corporation (Duke Energy) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations | |
| Consolidated Statements of Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Duke Energy Carolinas, LLC (Duke Energy Carolinas) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Progress Energy, Inc. (Progress Energy) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Duke Energy Progress, LLC (Duke Energy Progress) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Duke Energy Florida, LLC (Duke Energy Florida) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Duke Energy Ohio, Inc. (Duke Energy Ohio) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Duke Energy Indiana, LLC (Duke Energy Indiana) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
| Piedmont Natural Gas Company, Inc. (Piedmont) | |
| Report of Independent Registered Public Accounting Firm | |
| Consolidated Statements of Operations and Comprehensive Income | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Cash Flows | |
| Consolidated Statements of Changes in Equity | |
| |
|
| |
| Combined Notes to Consolidated Financial Statements | |
| Note 1 – Summary of Significant Accounting Policies | |
| Note 2 – Acquisitions and Dispositions | |
| Note 3 – Business Segments | |
| Note 4 – Regulatory Matters | |
| Note 5 – Commitments and Contingencies | |
| Note 6 – Debt and Credit Facilities | |
| Note 7 – Guarantees and Indemnifications | |
| Note 8 – Joint Ownership of Generating and Transmission Facilities | |
| Note 9 – Asset Retirement Obligations | |
| Note 10 – Property, Plant and Equipment | |
| Note 11 – Goodwill and Intangible Assets | |
| Note 12 – Investments in Unconsolidated Affiliates | |
| Note 13 – Related Party Transactions | |
| Note 14 – Derivatives and Hedging | |
| Note 15 – Investments in Debt and Equity Securities | |
| Note 16 – Fair Value Measurements | |
| Note 17 – Variable Interest Entities | |
| Note 18 – Common Stock | |
| Note 19 – Severance | |
| Note 20 – Stock-Based Compensation | |
| Note 21 – Employee Benefit Plans | |
| Note 22 – Income Taxes | |
| Note 23 – Other Income and Expenses, Net | |
| Note 24 – Subsequent Events | |
| Note 25 – Quarterly Financial Data (Unaudited) | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors and Stockholders of Duke Energy Corporation
Piedmont Natural Gas Company, Inc.
Charlotte, North Carolina
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc.Duke Energy Corporation and subsidiaries (the “Company”"Company") as of OctoberDecember 31, 20142017 and 2013, and2016, the related consolidated statements of operations, comprehensive income, stockholders’changes in equity, and cash flows, for each of the three years in the period ended OctoberDecember 31, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Company’s management. Our responsibility is to express an"financial statements"). In our opinion, on the financial statements based on our audits.present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
We conducted our auditshave also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2018, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesmisstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 1947.
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions, except per share amounts) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | | | | | |
| Regulated electric | $ | 21,177 |
| | $ | 21,221 |
| | $ | 21,379 |
|
| Regulated natural gas | 1,734 |
| | 863 |
| | 536 |
|
| Nonregulated electric and other | 654 |
| | 659 |
| | 456 |
|
| Total operating revenues | 23,565 |
| | 22,743 |
| | 22,371 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 6,350 |
| | 6,625 |
| | 7,355 |
|
| Cost of natural gas | 632 |
| | 265 |
| | 141 |
|
| Operation, maintenance and other | 5,788 |
| | 6,085 |
| | 5,539 |
|
| Depreciation and amortization | 3,527 |
| | 3,294 |
| | 3,053 |
|
| Property and other taxes | 1,233 |
| | 1,142 |
| | 1,129 |
|
| Impairment charges | 282 |
| | 18 |
| | 106 |
|
| Total operating expenses | 17,812 |
| | 17,429 |
| | 17,323 |
|
| Gains on Sales of Other Assets and Other, net | 28 |
| | 27 |
| | 30 |
|
| Operating Income | 5,781 |
| | 5,341 |
| | 5,078 |
|
| Other Income and Expenses | | | | | |
| Equity in earnings (losses) of unconsolidated affiliates | 119 |
| | (15 | ) | | 69 |
|
| Other income and expenses, net | 352 |
| | 324 |
| | 290 |
|
| Total other income and expenses | 471 |
| | 309 |
| | 359 |
|
| Interest Expense | 1,986 |
| | 1,916 |
| | 1,527 |
|
| Income From Continuing Operations Before Income Taxes | 4,266 |
| | 3,734 |
| | 3,910 |
|
| Income Tax Expense From Continuing Operations | 1,196 |
| | 1,156 |
| | 1,256 |
|
| Income From Continuing Operations | 3,070 |
| | 2,578 |
| | 2,654 |
|
| (Loss) Income From Discontinued Operations, net of tax | (6 | ) | | (408 | ) | | 177 |
|
| Net Income | 3,064 |
| | 2,170 |
| | 2,831 |
|
| Less: Net Income Attributable to Noncontrolling Interests | 5 |
| | 18 |
| | 15 |
|
| Net Income Attributable to Duke Energy Corporation | $ | 3,059 |
| | $ | 2,152 |
| | $ | 2,816 |
|
| | | | | | |
Earnings Per Share – Basic and Diluted | | | | | |
| Income from continuing operations attributable to Duke Energy Corporation common stockholders | | | | | |
| Basic | $ | 4.37 |
| | $ | 3.71 |
| | $ | 3.80 |
|
| Diluted | $ | 4.37 |
| | $ | 3.71 |
| | $ | 3.80 |
|
| (Loss) Income from discontinued operations attributable to Duke Energy Corporation common stockholders |
| | | | |
| Basic | $ | (0.01 | ) | | $ | (0.60 | ) | | $ | 0.25 |
|
| Diluted | $ | (0.01 | ) | | $ | (0.60 | ) | | $ | 0.25 |
|
| Net income attributable to Duke Energy Corporation common stockholders |
| | | | |
| Basic | $ | 4.36 |
| | $ | 3.11 |
| | $ | 4.05 |
|
| Diluted | $ | 4.36 |
| | $ | 3.11 |
| | $ | 4.05 |
|
| Weighted average shares outstanding | | | | | |
| Basic | 700 |
| | 691 |
| | 694 |
|
| Diluted | 700 |
| | 691 |
| | 694 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
(in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Net Income | $ | 3,064 |
| | $ | 2,170 |
| | $ | 2,831 |
|
| Other Comprehensive Income (Loss), net of tax | | | | | |
| Foreign currency translation adjustments | — |
| | 694 |
| | (264 | ) |
| Pension and OPEB adjustments | 3 |
| | (11 | ) | | (13 | ) |
| Net unrealized gains on cash flow hedges | 2 |
| | 17 |
| | — |
|
| Reclassification into earnings from cash flow hedges | 8 |
| | 13 |
| | 9 |
|
| Unrealized gains (losses) on available-for-sale securities | 13 |
| | 2 |
| | (6 | ) |
Other Comprehensive Income (Loss), net of tax | 26 |
| | 715 |
| | (274 | ) |
Comprehensive Income | 3,090 |
| | 2,885 |
| | 2,557 |
|
Less: Comprehensive Income Attributable to Noncontrolling Interests | 5 |
| | 20 |
| | 4 |
|
Comprehensive Income Attributable to Duke Energy Corporation | $ | 3,085 |
| | $ | 2,865 |
| | $ | 2,553 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 358 |
| | $ | 392 |
|
| Receivables (net of allowance for doubtful accounts of $14 at 2017 and 2016) | 779 |
| | 751 |
|
| Receivables of VIEs (net of allowance for doubtful accounts of $54 at 2017 and 2016) | 1,995 |
| | 1,893 |
|
| Inventory | 3,250 |
|
| 3,522 |
|
| Regulatory assets (includes $51 at 2017 and $50 at 2016 related to VIEs) | 1,437 |
| | 1,023 |
|
| Other | 634 |
| | 458 |
|
| Total current assets | 8,453 |
| | 8,039 |
|
| Property, Plant and Equipment | | | |
| Cost | 127,507 |
| | 121,397 |
|
| Accumulated depreciation and amortization | (41,537 | ) | | (39,406 | ) |
| Generation facilities to be retired, net | 421 |
| | 529 |
|
| Net property, plant and equipment | 86,391 |
| | 82,520 |
|
| Other Noncurrent Assets | | | |
| Goodwill | 19,396 |
| | 19,425 |
|
| Regulatory assets (includes $1,091 at 2017 and $1,142 at 2016 related to VIEs) | 12,442 |
| | 12,878 |
|
| Nuclear decommissioning trust funds | 7,097 |
| | 6,205 |
|
| Investments in equity method unconsolidated affiliates | 1,175 |
| | 925 |
|
| Other | 2,960 |
| | 2,769 |
|
| Total other noncurrent assets | 43,070 |
| | 42,202 |
|
| Total Assets | $ | 137,914 |
| | $ | 132,761 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 3,043 |
| | $ | 2,994 |
|
| Notes payable and commercial paper | 2,163 |
| | 2,487 |
|
| Taxes accrued | 551 |
| | 384 |
|
| Interest accrued | 525 |
| | 503 |
|
| Current maturities of long-term debt (includes $225 at 2017 and $260 at 2016 related to VIEs) | 3,244 |
| | 2,319 |
|
| Asset retirement obligations | 689 |
| | 411 |
|
| Regulatory liabilities | 402 |
| | 409 |
|
| Other | 1,865 |
| | 2,044 |
|
| Total current liabilities | 12,482 |
| | 11,551 |
|
| Long-Term Debt (includes $4,306 at 2017 and $3,587 at 2016 related to VIEs) | 49,035 |
| | 45,576 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 6,621 |
| | 14,155 |
|
| Asset retirement obligations | 9,486 |
| | 10,200 |
|
| Regulatory liabilities | 15,330 |
| | 6,881 |
|
| Accrued pension and other post-retirement benefit costs | 1,103 |
| | 1,111 |
|
| Investment tax credits | 539 |
| | 493 |
|
| Other | 1,581 |
| | 1,753 |
|
| Total other noncurrent liabilities | 34,660 |
| | 34,593 |
|
| Commitments and Contingencies |
|
| |
|
|
| Equity | | | |
| Common stock, $0.001 par value, 2 billion shares authorized; 700 million shares outstanding at 2017 and 2016 | 1 |
| | 1 |
|
| Additional paid-in capital | 38,792 |
| | 38,741 |
|
| Retained earnings | 3,013 |
| | 2,384 |
|
| Accumulated other comprehensive loss | (67 | ) | | (93 | ) |
| Total Duke Energy Corporation stockholders' equity | 41,739 |
| | 41,033 |
|
| Noncontrolling interests | (2 | ) | | 8 |
|
| Total equity | 41,737 |
| | 41,041 |
|
| Total Liabilities and Equity | $ | 137,914 |
| | $ | 132,761 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 3,064 |
| | $ | 2,170 |
| | $ | 2,831 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion (including amortization of nuclear fuel) | 4,046 |
| | 3,880 |
| | 3,613 |
|
| Equity component of AFUDC | (237 | ) | | (200 | ) | | (164 | ) |
| (Gains) Losses on sales of other assets | (33 | ) | | 477 |
| | (48 | ) |
| Impairment charges | 282 |
| | 212 |
| | 153 |
|
| Deferred income taxes | 1,433 |
| | 900 |
| | 1,244 |
|
| Equity in (earnings) losses of unconsolidated affiliates | (119 | ) | | 15 |
| | (69 | ) |
| Accrued pension and other post-retirement benefit costs | 8 |
| | 21 |
| | 71 |
|
| Contributions to qualified pension plans | (19 | ) | | (155 | ) | | (302 | ) |
| Payments for asset retirement obligations | (571 | ) | | (608 | ) | | (346 | ) |
| (Increase) decrease in | | | | | |
| Net realized and unrealized mark-to-market and hedging transactions | 18 |
| | 34 |
| | (29 | ) |
| Receivables | (83 | ) | | (372 | ) | | 383 |
|
| Inventory | 268 |
| | 272 |
| | (237 | ) |
| Other current assets | (388 | ) | | (220 | ) | | (65 | ) |
| Increase (decrease) in | | | | | |
| Accounts payable | (204 | ) | | 296 |
| | (6 | ) |
| Taxes accrued | 149 |
| | 236 |
| | (38 | ) |
| Other current liabilities | (482 | ) | | 182 |
| | 168 |
|
| Other assets | (438 | ) | | (186 | ) | | (216 | ) |
| Other liabilities | (60 | ) | | (137 | ) | | (243 | ) |
| Net cash provided by operating activities | 6,634 |
|
| 6,817 |
|
| 6,700 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (8,052 | ) | | (7,901 | ) | | (6,766 | ) |
| Contributions to equity method investments | (414 | ) | | (307 | ) | | (263 | ) |
| Acquisitions, net of cash acquired | (13 | ) | | (4,778 | ) | | (1,334 | ) |
| Return of investment capital | 281 |
| | 1 |
| | 3 |
|
| Purchases of available-for-sale securities | (4,071 | ) | | (5,153 | ) | | (4,037 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 4,098 |
| | 5,236 |
| | 4,040 |
|
| Proceeds from the sales of discontinued operations and other assets, net of cash divested | — |
| | 1,418 |
| | 2,968 |
|
| Change in restricted cash | (10 | ) | | (4 | ) | | 191 |
|
| Other | (269 | ) | | (45 | ) | | (79 | ) |
| Net cash used in investing activities | (8,450 | ) |
| (11,533 | ) |
| (5,277 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the: | | | | | |
| Issuance of long-term debt | 6,909 |
| | 9,238 |
| | 2,955 |
|
| Issuance of common stock | — |
| | 731 |
| | 17 |
|
| Payments for the redemption of long-term debt | (2,316 | ) | | (1,923 | ) | | (3,029 | ) |
| Proceeds from the issuance of short-term debt with original maturities greater than 90 days | 319 |
| | 2,081 |
| | 379 |
|
| Payments for the redemption of short-term debt with original maturities greater than 90 days | (272 | ) | | (2,166 | ) | | (931 | ) |
| Notes payable and commercial paper | (409 | ) | | (1,362 | ) | | 1,797 |
|
| Dividends paid | (2,450 | ) | | (2,332 | ) | | (2,254 | ) |
| Repurchase of common shares | — |
| | — |
| | (1,500 | ) |
| Other | 1 |
| | (16 | ) | | (36 | ) |
| Net cash provided by (used in) financing activities | 1,782 |
|
| 4,251 |
|
| (2,602 | ) |
| Changes in cash and cash equivalents included in assets held for sale | — |
| | 474 |
| | 1,099 |
|
| Net (decrease) increase in cash and cash equivalents | (34 | ) |
| 9 |
|
| (80 | ) |
| Cash and cash equivalents at beginning of period | 392 |
| | 383 |
| | 463 |
|
| Cash and cash equivalents at end of period | $ | 358 |
|
| $ | 392 |
|
| $ | 383 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 1,963 |
| | $ | 1,794 |
| | $ | 1,607 |
|
| Cash paid for income taxes | 4 |
| | 229 |
| | 170 |
|
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 1,032 |
| | 1,000 |
| | 771 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Duke Energy Corporation Stockholders' Accumulated Other Comprehensive Loss | | | | | | |
| | | | | | | | | | | | | | Net Unrealized |
| | | | Total |
| | | | |
| | | | | | | | | | Foreign |
| | Net |
| | Gains (Losses) |
| | | | Duke Energy |
| | | | |
| | Common |
| | | | Additional |
| | | | Currency |
| | Losses on |
| | on Available- |
| | Pension and |
| | Corporation |
| | | | |
| | Stock |
| | Common |
| | Paid-in |
| | Retained |
| | Translation |
| | Cash Flow |
| | for-Sale- |
| | OPEB |
| | Stockholders' |
| | Noncontrolling |
| | Total |
|
| (in millions) | Shares |
| | Stock |
| | Capital |
| | Earnings |
| | Adjustments |
| | Hedges |
| | Securities |
| | Adjustments |
| | Equity |
| | Interests |
| | Equity |
|
| Balance at December 31, 2014 | 707 |
| | $ | 1 |
| | $ | 39,405 |
| | $ | 2,012 |
| | $ | (439 | ) | | $ | (59 | ) | | $ | 3 |
| | $ | (48 | ) | | $ | 40,875 |
| | $ | 24 |
| | $ | 40,899 |
|
| Net income | — |
| | — |
| | — |
| | 2,816 |
| | — |
| | — |
| | — |
| | — |
| | 2,816 |
| | 15 |
| | 2,831 |
|
| Other comprehensive (loss) income | — |
| | — |
| | — |
| | — |
| | (253 | ) | | 9 |
| | (6 | ) | | (13 | ) | | (263 | ) | | (11 | ) | | (274 | ) |
| Common stock issuances, including dividend reinvestment and employee benefits | 1 |
| | — |
| | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 63 |
| | — |
| | 63 |
|
| Stock repurchase | (20 | ) | | — |
| | (1,500 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,500 | ) | | — |
| | (1,500 | ) |
| Common stock dividends | — |
| | — |
| | — |
| | (2,254 | ) | | — |
| | — |
| | — |
| | — |
| | (2,254 | ) | | — |
| | (2,254 | ) |
| Distributions to noncontrolling interest in subsidiaries | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (9 | ) | | (9 | ) |
Other(a) | — |
| | — |
| | — |
| | (10 | ) | | — |
| | — |
| | — |
| | — |
| | (10 | ) | | 25 |
| | 15 |
|
| Balance at December 31, 2015 | 688 |
|
| $ | 1 |
|
| $ | 37,968 |
|
| $ | 2,564 |
|
| $ | (692 | ) |
| $ | (50 | ) |
| $ | (3 | ) |
| $ | (61 | ) |
| $ | 39,727 |
|
| $ | 44 |
|
| $ | 39,771 |
|
| Net income | — |
| | — |
| | — |
| | 2,152 |
| | — |
| | — |
| | — |
| | — |
| | 2,152 |
| | 18 |
| | 2,170 |
|
Other comprehensive (loss) income(b) | — |
| | — |
| | — |
| | — |
| | 692 |
| | 30 |
| | 2 |
| | (11 | ) | | 713 |
| | 2 |
| | 715 |
|
| Common stock issuances, including dividend reinvestment and employee benefits | 12 |
| | — |
| | 773 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 773 |
| | — |
| | 773 |
|
| Common stock dividends | — |
| | — |
| | — |
| | (2,332 | ) | | — |
| | — |
| | — |
| | — |
| | (2,332 | ) | | — |
| | (2,332 | ) |
| Distributions to noncontrolling interest in subsidiaries | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) | | (6 | ) |
Other(c) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (50 | ) | | (50 | ) |
| Balance at December 31, 2016 | 700 |
|
| $ | 1 |
|
| $ | 38,741 |
|
| $ | 2,384 |
|
| $ | — |
|
| $ | (20 | ) |
| $ | (1 | ) |
| $ | (72 | ) |
| $ | 41,033 |
|
| $ | 8 |
|
| $ | 41,041 |
|
| Net income | — |
| | — |
| | — |
| | 3,059 |
| | — |
| | — |
| | — |
| | — |
| | 3,059 |
| | 5 |
| | 3,064 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | 13 |
| | 3 |
| | 26 |
| | — |
| | 26 |
|
| Common stock issuances, including dividend reinvestment and employee benefits | — |
| | — |
| | 51 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 51 |
| | — |
| | 51 |
|
| Common stock dividends | — |
| | — |
| | — |
| | (2,450 | ) | | — |
| | — |
| | — |
| | — |
| | (2,450 | ) | | — |
| | (2,450 | ) |
| Distributions to noncontrolling interests in subsidiaries | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (2 | ) |
Other(d) | — |
| | — |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | (13 | ) | | 7 |
|
| Balance at December 31, 2017 | 700 |
| | $ | 1 |
| | $ | 38,792 |
| | $ | 3,013 |
| | $ | — |
| | $ | (10 | ) | | $ | 12 |
| | $ | (69 | ) | | $ | 41,739 |
| | $ | (2 | ) | | $ | 41,737 |
|
| |
| (a) | Noncontrolling Interests amount is primarily related to the acquisitions of a majority interest in a provider of energy management systems and services for commercial customers and a solar company. |
| |
| (b) | Foreign Currency Translation Adjustments amount includes $620 million of cumulative adjustment realized as a result of the sale of the Latin American generation business. See Note 2 to the Consolidated Financial Statements. |
| |
| (c) | Noncontrolling Interests amount is primarily related to the sale of the Latin American generation business. See Note 2 to the Consolidated Financial Statements. |
| |
| (d) | Retained Earnings relates to a cumulative-effect adjustment due to implementation of a new accounting standard related to stock-based compensation and the associated income taxes. See Note 1 to the Consolidated Financial Statements for additional information. Noncontrolling Interests relates to the purchase of remaining interest in REC Solar. |
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Duke Energy Carolinas, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Duke Energy Carolinas, LLC and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, such consolidatedthe financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gasthe Company Inc.as of December 31, 2017 and subsidiaries at October 31, 2014 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended OctoberDecember 31, 2014,2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We have also audited,are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 1947.
DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 7,302 |
| | $ | 7,322 |
| | $ | 7,229 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 1,822 |
|
| 1,797 |
| | 1,881 |
|
| Operation, maintenance and other | 1,961 |
|
| 2,106 |
| | 2,066 |
|
| Depreciation and amortization | 1,090 |
|
| 1,075 |
| | 1,051 |
|
| Property and other taxes | 281 |
|
| 276 |
| | 269 |
|
| Impairment charges | — |
|
| 1 |
| | 1 |
|
| Total operating expenses | 5,154 |
| | 5,255 |
| | 5,268 |
|
| Gain (Loss) on Sales of Other Assets and Other, net | 1 |
| | (5 | ) | | (1 | ) |
| Operating Income | 2,149 |
| | 2,062 |
| | 1,960 |
|
| Other Income and Expenses, net | 139 |
| | 162 |
| | 160 |
|
| Interest Expense | 422 |
| | 424 |
| | 412 |
|
| Income Before Income Taxes | 1,866 |
| | 1,800 |
| | 1,708 |
|
| Income Tax Expense | 652 |
| | 634 |
| | 627 |
|
| Net Income | $ | 1,214 |
| | $ | 1,166 |
| | $ | 1,081 |
|
| Other Comprehensive Income, net of tax | | | | | |
| Reclassification into earnings from cash flow hedges | 2 |
| | 2 |
| | 1 |
|
| Unrealized gains on available-for-sale securities | — |
| | — |
| | 1 |
|
| Other Comprehensive Income, net of tax | 2 |
| | 2 |
| | 2 |
|
| Comprehensive Income | $ | 1,216 |
| | $ | 1,168 |
| | $ | 1,083 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED BALANCE SHEETS |
| | | | | | | | |
| | | December 31, |
| (in millions) | | 2017 |
| | 2016 |
|
| ASSETS | | | | |
| Current Assets | | | | |
| Cash and cash equivalents | | $ | 16 |
| | $ | 14 |
|
| Receivables (net of allowance for doubtful accounts of $2 at 2017 and 2016) | | 200 |
| | 160 |
|
| Receivables of VIEs (net of allowance for doubtful accounts of $7 at 2017 and 2016) | | 640 |
| | 645 |
|
| Receivables from affiliated companies | | 95 |
| | 163 |
|
| Notes receivable from affiliated companies | | — |
| | 66 |
|
| Inventory | | 971 |
|
| 1,055 |
|
| Regulatory assets | | 299 |
| | 238 |
|
| Other | | 19 |
| | 37 |
|
| Total current assets | | 2,240 |
| | 2,378 |
|
| Property, Plant and Equipment | | | | |
| Cost | | 42,939 |
| | 41,127 |
|
| Accumulated depreciation and amortization | | (15,063 | ) | | (14,365 | ) |
| Net property, plant and equipment | | 27,876 |
| | 26,762 |
|
| Other Noncurrent Assets | | | | |
| Regulatory assets | | 2,853 |
| | 3,159 |
|
| Nuclear decommissioning trust funds | | 3,772 |
| | 3,273 |
|
| Other | | 979 |
| | 943 |
|
| Total other noncurrent assets | | 7,604 |
| | 7,375 |
|
| Total Assets | | $ | 37,720 |
| | $ | 36,515 |
|
| LIABILITIES AND EQUITY | | | | |
| Current Liabilities | | | | |
| Accounts payable | | $ | 842 |
| | $ | 833 |
|
| Accounts payable to affiliated companies | | 209 |
| | 247 |
|
| Notes payable to affiliated companies | | 104 |
| | — |
|
| Taxes accrued | | 234 |
| | 143 |
|
| Interest accrued | | 108 |
| | 102 |
|
| Current maturities of long-term debt | | 1,205 |
| | 116 |
|
| Asset retirement obligations | | 337 |
| | 222 |
|
| Regulatory liabilities | | 126 |
| | 161 |
|
| Other | | 486 |
| | 468 |
|
| Total current liabilities | | 3,651 |
| | 2,292 |
|
| Long-Term Debt | | 8,598 |
| | 9,187 |
|
| Long-Term Debt Payable to Affiliated Companies | | 300 |
| | 300 |
|
| Other Noncurrent Liabilities | | | | |
| Deferred income taxes | | 3,413 |
| | 6,544 |
|
| Asset retirement obligations | | 3,273 |
| | 3,673 |
|
| Regulatory liabilities | | 6,231 |
| | 2,840 |
|
| Accrued pension and other post-retirement benefit costs | | 95 |
| | 97 |
|
| Investment tax credits | | 232 |
| | 203 |
|
| Other | | 566 |
| | 607 |
|
| Total other noncurrent liabilities | | 13,810 |
| | 13,964 |
|
| Commitments and Contingencies | |
| |
|
| Equity | | | | |
| Member's equity | | 11,368 |
| | 10,781 |
|
| Accumulated other comprehensive loss | | (7 | ) | | (9 | ) |
| Total equity | | 11,361 |
| | 10,772 |
|
| Total Liabilities and Equity | | $ | 37,720 |
| | $ | 36,515 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 1,214 |
| | $ | 1,166 |
| | $ | 1,081 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization (including amortization of nuclear fuel) | 1,409 |
| | 1,382 |
| | 1,361 |
|
| Equity component of AFUDC | (106 | ) | | (102 | ) | | (96 | ) |
| (Gains) Losses on sales of other assets | (1 | ) | | 5 |
| | 1 |
|
| Impairment charges | — |
| | 1 |
| | 1 |
|
| Deferred income taxes | 410 |
| | 470 |
| | 397 |
|
| Accrued pension and other post-retirement benefit costs | (4 | ) | | 4 |
| | 15 |
|
| Contributions to qualified pension plans | — |
| | (43 | ) | | (91 | ) |
| Payments for asset retirement obligations | (271 | ) | | (287 | ) | | (167 | ) |
| (Increase) decrease in |
| | | | |
| Net realized and unrealized mark-to-market and hedging transactions | 9 |
| | 5 |
| | — |
|
| Receivables | (9 | ) | | (76 | ) | | 42 |
|
| Receivables from affiliated companies | 68 |
| | (56 | ) | | (32 | ) |
| Inventory | 78 |
| | 215 |
| | (157 | ) |
| Other current assets | 7 |
| | 67 |
| | (51 | ) |
| Increase (decrease) in |
| | | | |
| Accounts payable | 23 |
| | (69 | ) | | (4 | ) |
| Accounts payable to affiliated companies | (38 | ) | | 18 |
| | 75 |
|
| Taxes accrued | 86 |
| | 187 |
| | (128 | ) |
| Other current liabilities | (161 | ) | | 63 |
| | 127 |
|
| Other assets | (49 | ) | | 20 |
| | 76 |
|
| Other liabilities | (31 | ) | | 6 |
| | (77 | ) |
| Net cash provided by operating activities | 2,634 |
| | 2,976 |
| | 2,373 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES |
| | | | |
| Capital expenditures | (2,524 | ) | | (2,220 | ) | | (1,933 | ) |
| Purchases of available-for-sale securities | (2,124 | ) | | (2,832 | ) | | (2,555 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 2,128 |
| | 2,832 |
| | 2,555 |
|
| Notes receivable from affiliated companies | 66 |
| | 97 |
| | (13 | ) |
| Other | (109 | ) | | (83 | ) | | (35 | ) |
| Net cash used in investing activities | (2,563 | ) | | (2,206 | ) | | (1,981 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | 569 |
| | 1,587 |
| | 516 |
|
| Payments for the redemption of long-term debt | (116 | ) | | (356 | ) | | (506 | ) |
| Notes payable to affiliated companies | 104 |
| | — |
| | — |
|
| Distributions to parent | (625 | ) | | (2,000 | ) | | (401 | ) |
| Other | (1 | ) | | — |
| | (1 | ) |
| Net cash used in financing activities | (69 | ) | | (769 | ) | | (392 | ) |
| Net increase in cash and cash equivalents | 2 |
| | 1 |
| | — |
|
| Cash and cash equivalents at beginning of period | 14 |
| | 13 |
| | 13 |
|
| Cash and cash equivalents at end of period | $ | 16 |
| | $ | 14 |
| | $ | 13 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 398 |
| | $ | 393 |
| | $ | 389 |
|
| Cash paid for (received from) income taxes | 193 |
| | (60 | ) | | 342 |
|
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 315 |
| | 347 |
| | 239 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY CAROLINAS, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | |
| | | | Accumulated Other | | |
| | | | Comprehensive Loss | | |
| | | | Net Losses |
| | Net Losses |
| | |
| | | | on Cash |
| | Available- |
| | |
| | Member's |
| | Flow |
| | for-Sale |
| | Total |
|
| (in millions) | Equity |
| | Hedges |
| | Securities |
| | Equity |
|
| Balance at December 31, 2014 | $ | 10,937 |
| | $ | (12 | ) | | $ | (1 | ) | | $ | 10,924 |
|
| Net income | 1,081 |
| | — |
| | — |
| | 1,081 |
|
| Other comprehensive income | — |
| | 1 |
| | 1 |
| | 2 |
|
| Distributions to parent | (401 | ) | | — |
| | — |
| | (401 | ) |
| Balance at December 31, 2015 | $ | 11,617 |
| | $ | (11 | ) | | $ | — |
| | $ | 11,606 |
|
| Net income | 1,166 |
| | — |
| | — |
| | 1,166 |
|
| Other comprehensive income | — |
| | 2 |
| | — |
| | 2 |
|
| Distributions to parent | (2,000 | ) | | — |
| | — |
| | (2,000 | ) |
| Other | (2 | ) | | — |
| | — |
| | (2 | ) |
| Balance at December 31, 2016 | $ | 10,781 |
| | $ | (9 | ) | | $ | — |
| | $ | 10,772 |
|
Net income | 1,214 |
| | — |
| | — |
| | 1,214 |
|
Other comprehensive income | — |
| | 2 |
| | — |
| | 2 |
|
Distributions to parent | (625 | ) | | — |
| | — |
| | (625 | ) |
| Other | (2 | ) | | — |
| | — |
| | (2 | ) |
| Balance at December 31, 2017 | $ | 11,368 |
| | $ | (7 | ) | | $ | — |
| | $ | 11,361 |
|
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Progress Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Progress Energy, Inc. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States), (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reportingreporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 1930.
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 9,783 |
| | $ | 9,853 |
| | $ | 10,277 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 3,417 |
| | 3,644 |
| | 4,224 |
|
| Operation, maintenance and other | 2,220 |
| | 2,386 |
| | 2,298 |
|
| Depreciation and amortization | 1,285 |
| | 1,213 |
| | 1,116 |
|
| Property and other taxes | 503 |
| | 487 |
| | 492 |
|
| Impairment charges | 156 |
| | 7 |
| | 12 |
|
| Total operating expenses | 7,581 |
|
| 7,737 |
|
| 8,142 |
|
| Gains on Sales of Other Assets and Other, net | 26 |
| | 25 |
| | 25 |
|
| Operating Income | 2,228 |
|
| 2,141 |
|
| 2,160 |
|
| Other Income and Expenses, net | 128 |
| | 114 |
| | 97 |
|
| Interest Expense | 824 |
| | 689 |
| | 670 |
|
| Income From Continuing Operations Before Income Taxes | 1,532 |
|
| 1,566 |
|
| 1,587 |
|
| Income Tax Expense From Continuing Operations | 264 |
| | 527 |
| | 522 |
|
| Income From Continuing Operations | 1,268 |
|
| 1,039 |
|
| 1,065 |
|
| Income (Loss) From Discontinued Operations, net of tax | — |
| | 2 |
| | (3 | ) |
| Net Income | 1,268 |
|
| 1,041 |
|
| 1,062 |
|
| Less: Net Income Attributable to Noncontrolling Interests | 10 |
| | 10 |
| | 11 |
|
| Net Income Attributable to Parent | $ | 1,258 |
|
| $ | 1,031 |
|
| $ | 1,051 |
|
| | | | | | |
Net Income | $ | 1,268 |
|
| $ | 1,041 |
|
| $ | 1,062 |
|
Other Comprehensive Income (Loss), net of tax | | | | | |
| Pension and OPEB adjustments | 4 |
| | 1 |
| | (10 | ) |
| Net unrealized gain on cash flow hedges | 5 |
| | — |
| | — |
|
| Reclassification into earnings from cash flow hedges | — |
| | 8 |
| | 4 |
|
| Unrealized gains (losses) on available-for-sale securities | 4 |
| | 1 |
| | (1 | ) |
Other Comprehensive Income (Loss), net of tax | 13 |
|
| 10 |
|
| (7 | ) |
Comprehensive Income | 1,281 |
|
| 1,051 |
|
| 1,055 |
|
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 10 |
| | 10 |
| | 11 |
|
| Comprehensive Income Attributable to Parent | $ | 1,271 |
|
| $ | 1,041 |
|
| $ | 1,044 |
|
See Notes to Consolidated Financial Statements
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 40 |
| | $ | 46 |
|
| Receivables (net of allowance for doubtful accounts of $4 at 2017 and $6 at 2016) | 123 |
| | 114 |
|
| Receivables of VIEs (net of allowance for doubtful accounts of $7 at 2017 and 2016) | 780 |
| | 692 |
|
| Receivables from affiliated companies | 31 |
| | 106 |
|
| Notes receivable from affiliated companies | 240 |
| | 80 |
|
| Inventory | 1,592 |
|
| 1,717 |
|
| Regulatory assets (includes $51 at 2017 and $50 at 2016 related to VIEs) | 741 |
| | 401 |
|
| Other | 334 |
| | 148 |
|
| Total current assets | 3,881 |
| | 3,304 |
|
| Property, Plant and Equipment | | | |
| Cost | 47,323 |
| | 44,864 |
|
| Accumulated depreciation and amortization | (15,857 | ) | | (15,212 | ) |
| Generation facilities to be retired, net | 421 |
| | 529 |
|
| Net property, plant and equipment | 31,887 |
| | 30,181 |
|
| Other Noncurrent Assets | | | |
| Goodwill | 3,655 |
| | 3,655 |
|
| Regulatory assets (includes $1,091 at 2017 and $1,142 at 2016 related to VIEs) | 6,010 |
| | 5,722 |
|
| Nuclear decommissioning trust funds | 3,324 |
| | 2,932 |
|
| Other | 931 |
| | 856 |
|
| Total other noncurrent assets | 13,920 |
| | 13,165 |
|
| Total Assets | $ | 49,688 |
| | $ | 46,650 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 1,006 |
| | $ | 1,003 |
|
| Accounts payable to affiliated companies | 251 |
| | 348 |
|
| Notes payable to affiliated companies | 805 |
| | 729 |
|
| Taxes accrued | 101 |
| | 83 |
|
| Interest accrued | 212 |
| | 201 |
|
| Current maturities of long-term debt (includes $53 at 2017 and $62 at 2016 related to VIEs) | 771 |
| | 778 |
|
| Asset retirement obligations | 295 |
| | 189 |
|
| Regulatory liabilities | 213 |
| | 189 |
|
| Other | 729 |
| | 745 |
|
| Total current liabilities | 4,383 |
| | 4,265 |
|
| Long-Term Debt (includes $1,689 at 2017 and $1,741 at 2016 related to VIEs) | 16,916 |
| | 15,590 |
|
| Long-Term Debt Payable to Affiliated Companies | 150 |
| | 1,173 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 3,502 |
| | 5,246 |
|
| Asset retirement obligations | 5,119 |
| | 5,286 |
|
| Regulatory liabilities | 5,306 |
| | 2,395 |
|
| Accrued pension and other post-retirement benefit costs | 545 |
| | 547 |
|
| Other | 302 |
| | 341 |
|
| Total other noncurrent liabilities | 14,774 |
| | 13,815 |
|
| Commitments and Contingencies |
| |
|
| Equity | | | |
| Common stock, $0.01 par value, 100 shares authorized and outstanding at 2017 and 2016 | — |
| | — |
|
| Additional paid-in capital | 9,143 |
| | 8,094 |
|
| Retained earnings | 4,350 |
| | 3,764 |
|
| Accumulated other comprehensive loss | (25 | ) | | (38 | ) |
| Total Progress Energy, Inc. stockholder's equity | 13,468 |
| | 11,820 |
|
| Noncontrolling interests | (3 | ) | | (13 | ) |
| Total equity | 13,465 |
| | 11,807 |
|
| Total Liabilities and Equity | $ | 49,688 |
|
| $ | 46,650 |
|
See Notes to Consolidated Financial Statements
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 1,268 |
| | $ | 1,041 |
| | $ | 1,062 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion (including amortization of nuclear fuel) | 1,516 |
| | 1,435 |
| | 1,312 |
|
| Equity component of AFUDC | (92 | ) | | (76 | ) | | (54 | ) |
| Gains on sales of other assets | (28 | ) | | (34 | ) | | (31 | ) |
| Impairment charges | 156 |
| | 7 |
| | 12 |
|
| Deferred income taxes | 703 |
| | 532 |
| | 714 |
|
| Accrued pension and other post-retirement benefit costs | (28 | ) | | (24 | ) | | (5 | ) |
| Contributions to qualified pension plans | — |
| | (43 | ) | | (83 | ) |
| Payments for asset retirement obligations | (248 | ) | | (270 | ) | | (156 | ) |
| (Increase) decrease in | | | | | |
| Net realized and unrealized mark-to-market and hedging transactions | — |
| | 42 |
| | (6 | ) |
| Receivables | (89 | ) | | 7 |
| | 105 |
|
| Receivables from affiliated companies | 71 |
| | 211 |
| | (316 | ) |
| Inventory | 125 |
| | 35 |
| | (67 | ) |
| Other current assets | (384 | ) | | 3 |
| | 553 |
|
| Increase (decrease) in | | | | | |
| Accounts payable | (260 | ) | | 252 |
| | (193 | ) |
| Accounts payable to affiliated companies | (97 | ) | | 37 |
| | 108 |
|
| Taxes accrued | 17 |
| | 15 |
| | (63 | ) |
| Other current liabilities | (166 | ) | | (42 | ) | | 136 |
|
| Other assets | (301 | ) | | (248 | ) | | (167 | ) |
| Other liabilities | (98 | ) | | (36 | ) | | (112 | ) |
| Net cash provided by operating activities | 2,065 |
|
| 2,844 |
|
| 2,749 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (3,152 | ) | | (3,306 | ) | | (2,698 | ) |
| Asset Acquisitions | — |
| | (10 | ) | | (1,249 | ) |
| Purchases of available-for-sale securities | (1,806 | ) | | (2,143 | ) | | (1,174 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 1,824 |
| | 2,187 |
| | 1,211 |
|
| Proceeds from insurance | 7 |
| | 58 |
| | — |
|
| Proceeds from the sale of nuclear fuel | 20 |
| | 20 |
| | 102 |
|
| Notes receivable from affiliated companies | (160 | ) | | (80 | ) | | 220 |
|
| Change in restricted cash | 5 |
| | (6 | ) | | — |
|
| Other | (86 | ) | | 47 |
| | (34 | ) |
| Net cash used in investing activities | (3,348 | ) | | (3,233 | ) | | (3,622 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | 2,118 |
| | 2,375 |
| | 1,186 |
|
| Payments for the redemption of long-term debt | (813 | ) | | (327 | ) | | (1,553 | ) |
| Notes payable to affiliated companies | 100 |
| | 444 |
| | 623 |
|
| Capital contribution from parent | — |
| | — |
| | 625 |
|
| Dividends to parent | (124 | ) | | (2,098 | ) | | — |
|
| Other | (4 | ) | | (3 | ) | | (6 | ) |
| Net cash provided by financing activities | 1,277 |
|
| 391 |
|
| 875 |
|
| Net (decrease) increase in cash and cash equivalents | (6 | ) |
| 2 |
|
| 2 |
|
| Cash and cash equivalents at beginning of period | 46 |
| | 44 |
| | 42 |
|
| Cash and cash equivalents at end of period | $ | 40 |
| | $ | 46 |
| | $ | 44 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 773 |
| | $ | 673 |
| | $ | 649 |
|
| Cash (received from) paid for income taxes | (146 | ) | | (187 | ) | | (426 | ) |
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 391 |
| | 317 |
| | 329 |
|
| Equitization of certain notes payable to affiliates | 1,047 |
| | — |
| | — |
|
| Dividend to parent related to a legal entity restructuring | 547 |
| | — |
| | — |
|
See Notes to Consolidated Financial Statements
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | |
| | Accumulated Other Comprehensive Loss | | |
| | |
| | |
|
| | | | | | Net |
| | Net Unrealized |
| | | | Total Progress |
| | | | |
| | Additional |
| | | | Losses on |
| | Gains on |
| | Pension and |
| | Energy, Inc. |
| | | | |
| | Paid-in |
| | Retained |
| | Cash Flow |
| | Available-for- |
| | OPEB |
| | Stockholder's |
| | Noncontrolling |
| | Total |
|
| (in millions) | Capital |
| | Earnings |
| | Hedges |
| | Sale Securities |
| | Adjustments |
| | Equity |
| | Interests |
| | Equity |
|
| Balance at December 31, 2014 | $ | 7,467 |
| | $ | 3,782 |
| | $ | (35 | ) | | $ | 1 |
| | $ | (7 | ) | | $ | 11,208 |
| | $ | (32 | ) | | $ | 11,176 |
|
| Net income | — |
| | 1,051 |
| | — |
| | — |
| | — |
| | 1,051 |
| | 11 |
| | 1,062 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 4 |
| | (1 | ) | | (10 | ) | | (7 | ) | | — |
| | (7 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | (4 | ) |
| Capital contribution from parent | 625 |
| | — |
| | — |
| | — |
| | — |
| | 625 |
| | — |
| | 625 |
|
| Other | — |
| | (2 | ) | | — |
| | — |
| | — |
| | (2 | ) | | 3 |
| | 1 |
|
| Balance at December 31, 2015 | $ | 8,092 |
|
| $ | 4,831 |
|
| $ | (31 | ) |
| $ | — |
|
| $ | (17 | ) |
| $ | 12,875 |
|
| $ | (22 | ) |
| $ | 12,853 |
|
| Net income | — |
| | 1,031 |
| | — |
| | — |
| | — |
| | 1,031 |
| | 10 |
| | 1,041 |
|
| Other comprehensive income | — |
| | — |
| | 8 |
| | 1 |
| | 1 |
| | 10 |
| | — |
| | 10 |
|
| Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Dividends to parent | — |
| | (2,098 | ) | | — |
| | — |
| | — |
| | (2,098 | ) | | — |
| | (2,098 | ) |
| Other | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Balance at December 31, 2016 | $ | 8,094 |
|
| $ | 3,764 |
|
| $ | (23 | ) |
| $ | 1 |
|
| $ | (16 | ) |
| $ | 11,820 |
|
| $ | (13 | ) |
| $ | 11,807 |
|
| Net income | — |
| | 1,258 |
| | — |
| | — |
| | — |
| | 1,258 |
| | 10 |
| | 1,268 |
|
| Other comprehensive income | — |
| | — |
| | 5 |
| | 4 |
| | 4 |
| | 13 |
| | — |
| | 13 |
|
Dividends to parent(a) | — |
| | (672 | ) | | — |
| | — |
| | — |
| | (672 | ) | | — |
| | (672 | ) |
| Equitization of certain notes payable to affiliates | 1,047 |
| | — |
| | — |
| | — |
| | — |
| | 1,047 |
| | — |
| | 1,047 |
|
| Other | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Balance at December 31, 2017 | $ | 9,143 |
|
| $ | 4,350 |
|
| $ | (18 | ) |
| $ | 5 |
|
| $ | (12 | ) |
| $ | 13,468 |
|
| $ | (3 | ) |
| $ | 13,465 |
|
(a) Includes a $547 million non-cash dividend related to a legal entity restructuring.
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Duke Energy Progress, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Duke Energy Progress, LLC and subsidiaries (the "Company") as of OctoberDecember 31, 2014,2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the criteria establishedPublic Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in Internal Control—Integrated Framework (1992) issued byaccordance with the Committee of Sponsoring OrganizationsU.S. federal securities laws and the applicable rules and regulations of the TreadwaySecurities and Exchange Commission and the PCAOB.
We conducted our report dated December 23, 2014 expressedaudits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an unqualifiedaudit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2014February 21, 2018
47We have served as the Company's auditor since 1930.
Consolidated Balance Sheets
October 31, 2014 and 2013
PART II
ASSETSDUKE ENERGY PROGRESS, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Utility Plant: | | | | |
| Utility plant in service | | $ | 5,011,497 |
| | $ | 4,421,937 |
|
| Less accumulated depreciation | | 1,166,922 |
| | 1,088,331 |
|
| Utility plant in service, net | | 3,844,575 |
| | 3,333,606 |
|
| Construction work in progress | | 141,693 |
| | 297,717 |
|
| Plant held for future use | | 3,155 |
| | 3,155 |
|
| Total utility plant, net | | 3,989,423 |
| | 3,634,478 |
|
| Other Physical Property, at cost (net of accumulated depreciation of $904 in 2014 and $876 in 2013) | | 355 |
| | 382 |
|
| Current Assets: | | | | |
| Cash and cash equivalents | | 9,643 |
| | 8,063 |
|
| Trade accounts receivable (less allowance for doubtful accounts of $2,152 in 2014 and $1,604 in 2013) | | 65,260 |
| | 79,210 |
|
| Income taxes receivable | | 36,100 |
| | 31,065 |
|
| Other receivables | | 3,361 |
| | 1,988 |
|
| Unbilled utility revenues | | 21,093 |
| | 24,967 |
|
| Inventories: | | | | |
| Gas in storage | | 84,081 |
| | 73,929 |
|
| Materials, supplies and merchandise | | 1,652 |
| | 1,725 |
|
| Gas purchase derivative assets, at fair value | | 4,898 |
| | 1,834 |
|
| Regulatory assets | | 29,088 |
| | 77,204 |
|
| Prepayments | | 39,030 |
| | 35,038 |
|
| Deferred income taxes | | 53,418 |
| | 12,695 |
|
| Other current assets | | 326 |
| | 338 |
|
| Total current assets | | 347,950 |
| | 348,056 |
|
| Noncurrent Assets: | | | | |
| Equity method investments in non-utility activities | | 170,171 |
| | 128,469 |
|
| Goodwill | | 48,852 |
| | 48,852 |
|
| Regulatory assets | | 184,779 |
| | 169,102 |
|
| Marketable securities, at fair value | | 3,727 |
| | 2,995 |
|
| Overfunded postretirement asset | | 33,757 |
| | 28,258 |
|
| Other noncurrent assets | | 5,239 |
| | 8,017 |
|
| Total noncurrent assets | | 446,525 |
| | 385,693 |
|
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 5,129 |
| | $ | 5,277 |
| | $ | 5,290 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 1,609 |
| | 1,830 |
| | 2,029 |
|
| Operation, maintenance and other | 1,389 |
| | 1,504 |
| | 1,452 |
|
| Depreciation and amortization | 725 |
| | 703 |
| | 643 |
|
| Property and other taxes | 156 |
| | 156 |
| | 140 |
|
| Impairment charges | 19 |
| | 1 |
| | 5 |
|
| Total operating expenses | 3,898 |
| | 4,194 |
| | 4,269 |
|
| Gains on Sales of Other Assets and Other, net | 4 |
| | 3 |
| | 3 |
|
| Operating Income | 1,235 |
| | 1,086 |
| | 1,024 |
|
| Other Income and Expenses, net | 65 |
| | 71 |
| | 71 |
|
| Interest Expense | 293 |
| | 257 |
| | 235 |
|
| Income Before Income Taxes | 1,007 |
| | 900 |
| | 860 |
|
| Income Tax Expense | 292 |
| | 301 |
| | 294 |
|
| Net Income and Comprehensive Income | $ | 715 |
| | $ | 599 |
| | $ | 566 |
|
See notes to consolidated financial statements.
Consolidated Balance Sheets
October 31, 2014 and 2013
CAPITALIZATION AND LIABILITIES
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Capitalization: | | | | |
| Stockholders’ equity: | | | | |
| Cumulative preferred stock - no par value - 175 shares authorized | | $ | — |
| | $ | — |
|
| Common stock – no par value – shares authorized: 200,000; shares outstanding: 78,531 in 2014 and 76,099 in 2013 | | 636,835 |
| | 561,644 |
|
| Retained earnings | | 672,004 |
| | 627,236 |
|
| Accumulated other comprehensive loss | | (237 | ) | | (284 | ) |
| Total stockholders’ equity | | 1,308,602 |
| | 1,188,596 |
|
| Long-term debt | | 1,424,430 |
| | 1,174,857 |
|
| Total capitalization | | 2,733,032 |
| | 2,363,453 |
|
| Current Liabilities: | | | | |
| Current maturities of long-term debt | | — |
| | 100,000 |
|
| Short-term debt | | 355,000 |
| | 400,000 |
|
| Trade accounts payable | | 85,299 |
| | 96,281 |
|
| Other accounts payable | | 54,349 |
| | 43,855 |
|
| Accrued interest | | 27,982 |
| | 28,205 |
|
| Customers’ deposits | | 19,994 |
| | 19,831 |
|
| General taxes accrued | | 23,828 |
| | 21,454 |
|
| Regulatory liabilities | | 46,231 |
| | — |
|
| Other current liabilities | | 9,303 |
| | 7,024 |
|
| Total current liabilities | | 621,986 |
| | 716,650 |
|
| Noncurrent Liabilities: | | | | |
| Deferred income taxes | | 809,467 |
| | 681,369 |
|
| Unamortized federal investment tax credits | | 1,193 |
| | 1,402 |
|
| Accumulated provision for postretirement benefits | | 15,471 |
| | 12,042 |
|
| Regulatory liabilities | | 558,598 |
| | 541,897 |
|
| Conditional cost of removal obligations | | 14,647 |
| | 27,016 |
|
| Other noncurrent liabilities | | 29,859 |
| | 24,780 |
|
| Total noncurrent liabilities | | 1,429,235 |
| | 1,288,506 |
|
| Commitments and Contingencies (Note 8) | |
| |
|
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
|
See notes to consolidated financial statements.
Consolidated Statements of Comprehensive Income
For the Years Ended October 31, 2014, 2013 and 2012
|
| | | | | | | | | | | | |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 |
| Operating Revenues | | $ | 1,469,988 |
| | $ | 1,278,229 |
| | $ | 1,122,780 |
|
| Cost of Gas | | 779,780 |
| | 656,739 |
| | 547,334 |
|
| Margin | | 690,208 |
| | 621,490 |
| | 575,446 |
|
| Operating Expenses: | | | | | | |
| Operations and maintenance | | 270,877 |
| | 253,120 |
| | 242,599 |
|
| Depreciation | | 118,996 |
| | 112,207 |
| | 103,192 |
|
| General taxes | | 37,294 |
| | 34,635 |
| | 34,831 |
|
| Utility income taxes | | 83,176 |
| | 77,334 |
| | 69,101 |
|
| Total operating expenses | | 510,343 |
| | 477,296 |
| | 449,723 |
|
| Operating Income | | 179,865 |
| | 144,194 |
| | 125,723 |
|
| Other Income (Expense): | | | | | | |
| Income from equity method investments | | 32,753 |
| | 26,056 |
| | 23,904 |
|
| Non-operating income | | 1,842 |
| | 2,839 |
| | 1,288 |
|
| Non-operating expense | | (4,331 | ) | | (5,122 | ) | | (1,855 | ) |
| Income taxes | | (11,642 | ) | | (8,612 | ) | | (9,116 | ) |
| Total other income (expense) | | 18,622 |
| | 15,161 |
| | 14,221 |
|
| Utility Interest Charges: | | | | | | |
| Interest on long-term debt | | 61,562 |
| | 54,158 |
| | 41,412 |
|
| Allowance for borrowed funds used during construction | | (16,427 | ) | | (30,975 | ) | | (25,211 | ) |
| Other | | 9,551 |
| | 1,755 |
| | 3,896 |
|
| Total utility interest charges | | 54,686 |
| | 24,938 |
| | 20,097 |
|
| Net Income | | 143,801 |
| | 134,417 |
| | 119,847 |
|
| Other Comprehensive Income (Loss), net of tax: | | | | | | |
| Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $225, ($69) and ($530) for the years ended October 31, 2014, 2013 and 2012, respectively | | 355 |
| | (109 | ) | | (826 | ) |
| Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($177), $85 and $621 for the years ended October 31, 2014, 2013 and 2012, respectively | | (284 | ) | | 130 |
| | 973 |
|
| Net current period benefit activities of equity method investments, net of tax of ($16) for the year ended October 31, 2014 | | (24 | ) | | | | |
| Total other comprehensive income | | 47 |
| | 21 |
|
| 147 |
|
| Comprehensive Income | | $ | 143,848 |
| | $ | 134,438 |
|
| $ | 119,994 |
|
| | | | | | | |
| Average Shares of Common Stock: | | | | | | |
| Basic | | 77,883 |
| | 74,884 |
| | 71,977 |
|
| Diluted | | 78,193 |
| | 75,333 |
| | 72,278 |
|
| | | | | | | |
| Earnings Per Share of Common Stock: | | | | | | |
| Basic | | $ | 1.85 |
| | $ | 1.80 |
| | $ | 1.67 |
|
| Diluted | | $ | 1.84 |
| | $ | 1.78 |
| | $ | 1.66 |
|
See notes to consolidated financial statements.
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2014, 2013 and 2012
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Cash Flows from Operating Activities: | | | | | | |
| Net income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
| Adjustments to reconcile net income to net cash provided by | | | | | | |
| operating activities: | | | | | | |
| Depreciation and amortization | | 129,343 |
| | 120,797 |
| | 109,230 |
|
| Allowance for doubtful accounts | | 548 |
| | 25 |
| | 232 |
|
| Impairment loss on investment | | 2,000 |
| | — |
| | — |
|
| Net gain on sale of property | | (817 | ) | | (349 | ) | | — |
|
| Income from equity method investments | | (32,753 | ) | | (26,056 | ) | | (23,904 | ) |
| Distributions of earnings from equity method investments | | 24,843 |
| | 22,139 |
| | 19,590 |
|
| Deferred income taxes, net | | 87,136 |
| | 57,637 |
| | 99,159 |
|
| Changes in assets and liabilities: | | | | | | |
| Gas purchase derivatives, at fair value | | (3,064 | ) | | 1,319 |
| | (381 | ) |
| Receivables | | 16,196 |
| | (23,327 | ) | | 5,403 |
|
| Inventories | | (10,079 | ) | | (2,059 | ) | | 18,897 |
|
| Settlement of legal asset retirement obligations | | (3,575 | ) | | (2,389 | ) | | (2,038 | ) |
| Regulatory assets | | 20,297 |
| | 43,338 |
| | (93,268 | ) |
| Other assets | | (2,829 | ) | | 4,629 |
| | (2,314 | ) |
| Accounts payable | | 18 |
| | 2,381 |
| | 4,283 |
|
| Provision for postretirement benefits, net | | (2,070 | ) | | (53,515 | ) | | 45,507 |
|
| Regulatory liabilities | | 49,468 |
| | 23,429 |
| | (2,990 | ) |
| Other liabilities | | 12,149 |
| | 10,831 |
| | 7,262 |
|
| Net cash provided by operating activities | | 430,612 |
| | 313,247 |
| | 304,515 |
|
| | | | | | | |
| Cash Flows from Investing Activities: | | | | | | |
| Utility capital expenditures | | (460,444 | ) | | (599,999 | ) | | (529,576 | ) |
| Allowance for borrowed funds used during construction | | (16,427 | ) | | (30,975 | ) | | (25,211 | ) |
| Contributions to equity method investments | | (37,642 | ) | | (41,348 | ) | | (3,566 | ) |
| Distributions of capital from equity method investments | | 3,929 |
| | 4,700 |
| | 5,372 |
|
| Proceeds from sale of property | | 1,883 |
| | 1,951 |
| | 1,250 |
|
| Investments in marketable securities | | (454 | ) | | (414 | ) | | (606 | ) |
| Other | | 4,708 |
| | 2,609 |
| | 3,044 |
|
| Net cash used in investing activities | | (504,447 | ) | | (663,476 | ) | | (549,293 | ) |
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2014, 2013 and 2012
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Cash Flows from Financing Activities: | | | | | | |
| Borrowings under credit facility | | — |
| | 10,000 |
| | 350,000 |
|
| Repayments under credit facility | | — |
| | (10,000 | ) | | (681,000 | ) |
| Net (repayments) borrowings - commercial paper | | (45,000 | ) | | 35,000 |
| | 365,000 |
|
| Proceeds from issuance of long-term debt, net of discount | | 249,565 |
| | 299,856 |
| | 300,000 |
|
| Repayment of long-term debt | | (100,000 | ) | | — |
| | — |
|
| Expenses related to issuance of debt | | (2,871 | ) | | (3,250 | ) | | (3,908 | ) |
| Proceeds from issuance of common stock, net of expenses | | 47,290 |
| | 92,271 |
| | — |
|
| Issuance of common stock through dividend reinvestment and | | | | | | |
| employee stock plans | | 25,556 |
| | 24,610 |
| | 22,123 |
|
| Repurchases of common stock | | — |
| | — |
| | (26,528 | ) |
| Dividends paid | | (99,151 | ) | | (92,146 | ) | | (85,693 | ) |
| Other | | 26 |
| | (8 | ) | | (34 | ) |
| Net cash provided by financing activities | | 75,415 |
| | 356,333 |
| | 239,960 |
|
| Net Increase (Decrease) in Cash and Cash Equivalents | | 1,580 |
| | 6,104 |
| | (4,818 | ) |
| Cash and Cash Equivalents at Beginning of Year | | 8,063 |
| | 1,959 |
| | 6,777 |
|
| Cash and Cash Equivalents at End of Year | | $ | 9,643 |
| | $ | 8,063 |
| | $ | 1,959 |
|
| | | | | | | |
| Cash Paid During the Year for: | | | | | | |
| Interest | | $ | 64,276 |
| | $ | 50,275 |
| | $ | 44,571 |
|
| | | | | | | |
| Income Taxes: | | | | | | |
| Income taxes paid | | $ | 10,840 |
| | $ | 5,760 |
| | $ | 4,770 |
|
| Income taxes refunded | | 30 |
| | 169 |
| | 8,437 |
|
| Income taxes, net | | $ | 10,810 |
| | $ | 5,591 |
| | $ | (3,667 | ) |
| | | | | | | |
| Noncash Investing and Financing Activities: | | | | | | |
| Accrued construction expenditures | | $ | 38,869 |
| | $ | 39,389 |
| | $ | 43,643 |
|
See notes to consolidated financial statements.
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2014, 2013 and 2012
|
| | | | | | | | | | | | | | | | |
| In thousands, except per share amounts | | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| Balance, October 31, 2011 | | $ | 446,791 |
| | $ | 550,584 |
| | $ | (452 | ) | | $ | 996,923 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 119,847 |
| | | | 119,847 |
|
| Other comprehensive income | | | | | | 147 |
| | 147 |
|
| Total comprehensive income | | | | | | | | 119,994 |
|
| Common Stock Issued | | 22,198 |
| | | | | | 22,198 |
|
| Common Stock Repurchased | | (26,528 | ) | | | | | | (26,528 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 110 |
| | | | 110 |
|
| Dividends Declared ($1.19 per share) | | | | (85,693 | ) | | | | (85,693 | ) |
| Balance, October 31, 2012 | | 442,461 |
| | 584,848 |
| | (305 | ) | | 1,027,004 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 134,417 |
| | | | 134,417 |
|
| Other comprehensive income | | | |
| | 21 |
| | 21 |
|
| Total comprehensive income | | | | | | | | 134,438 |
|
| Common Stock Issued | | 119,552 |
| | | | | | 119,552 |
|
| Expenses from Issuance of Common Stock | | (369 | ) | | | | | | (369 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 117 |
| | | | 117 |
|
| Dividends Declared ($1.23 per share) | | | | (92,146 | ) | | | | (92,146 | ) |
| Balance, October 31, 2013 | | 561,644 |
| | 627,236 |
| | (284 | ) | | 1,188,596 |
|
| | | | | | | | | |
| Comprehensive Income: | | | | | | | | |
| Net income | | | | 143,801 |
| | | | 143,801 |
|
| Other comprehensive income | | | | | | 47 |
| | 47 |
|
| Total comprehensive income | | | | | | | | 143,848 |
|
| Common Stock Issued | | 75,203 |
| | | | | | 75,203 |
|
| Expenses from Issuance of Common Stock | | (12 | ) | | | | | | (12 | ) |
| Tax Benefit from Dividends Paid on ESOP Shares | | | | 118 |
| | | | 118 |
|
| Dividends Declared ($1.27 per share) | | | | (99,151 | ) | | | | (99,151 | ) |
| Balance, October 31, 2014 | | $ | 636,835 |
| | $ | 672,004 |
| | $ | (237 | ) | | $ | 1,308,602 |
|
The components of accumulated other comprehensive income (loss) (OCIL) as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Hedging activities of equity method investments | | $ | (213 | ) | | $ | (284 | ) |
| Benefit activities of equity method investments | | (24 | ) | | |
See notes to consolidated financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
PART II
DUKE ENERGY PROGRESS, LLC
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 20 |
| | $ | 11 |
|
| Receivables (net of allowance for doubtful accounts of $1 at 2017 and $4 at 2016) | 56 |
| | 51 |
|
| Receivables of VIEs (net of allowance for doubtful accounts of $5 at 2017 and 2016) | 459 |
| | 404 |
|
| Receivables from affiliated companies | 3 |
| | 5 |
|
| Notes receivable from affiliated companies | — |
| | 165 |
|
| Inventory | 1,017 |
|
| 1,076 |
|
| Regulatory assets | 352 |
| | 188 |
|
| Other | 97 |
| | 57 |
|
| Total current assets | 2,004 |
| | 1,957 |
|
| Property, Plant and Equipment | | | |
| Cost | 29,583 |
| | 28,419 |
|
| Accumulated depreciation and amortization | (10,903 | ) | | (10,561 | ) |
| Generation facilities to be retired, net | 421 |
| | 529 |
|
| Net property, plant and equipment | 19,101 |
| | 18,387 |
|
| Other Noncurrent Assets | | | |
| Regulatory assets | 3,507 |
| | 3,243 |
|
| Nuclear decommissioning trust funds | 2,588 |
| | 2,217 |
|
| Other | 599 |
| | 525 |
|
| Total other noncurrent assets | 6,694 |
| | 5,985 |
|
| Total Assets | $ | 27,799 |
| | $ | 26,329 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 402 |
| | $ | 589 |
|
| Accounts payable to affiliated companies | 179 |
| | 227 |
|
| Notes payable to affiliated companies | 240 |
| | — |
|
| Taxes accrued | 64 |
| | 104 |
|
| Interest accrued | 102 |
| | 102 |
|
| Current maturities of long-term debt | 3 |
| | 452 |
|
| Asset retirement obligations | 295 |
| | 189 |
|
| Regulatory liabilities | 139 |
| | 158 |
|
| Other | 376 |
| | 365 |
|
| Total current liabilities | 1,800 |
| | 2,186 |
|
| Long-Term Debt | 7,204 |
| | 6,409 |
|
| Long-Term Debt Payable to Affiliated Companies | 150 |
| | 150 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 1,883 |
| | 3,323 |
|
| Asset retirement obligations | 4,378 |
| | 4,508 |
|
| Regulatory liabilities | 3,999 |
| | 1,946 |
|
| Accrued pension and other post-retirement benefit costs | 248 |
| | 252 |
|
| Investment tax credits | 143 |
| | 146 |
|
| Other | 45 |
| | 51 |
|
| Total other noncurrent liabilities | 10,696 |
| | 10,226 |
|
| Commitments and Contingencies | | | |
| Equity | | | |
| Member's Equity | 7,949 |
| | 7,358 |
|
| Total Liabilities and Equity | $ | 27,799 |
| | $ | 26,329 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY PROGRESS, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 715 |
| | $ | 599 |
| | $ | 566 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion (including amortization of nuclear fuel) | 936 |
| | 907 |
| | 821 |
|
| Equity component of AFUDC | (47 | ) | | (50 | ) | | (47 | ) |
| Gains on sales of other assets | (5 | ) | | (6 | ) | | (7 | ) |
| Impairment charges | 19 |
| | 1 |
| | 5 |
|
| Deferred income taxes | 384 |
| | 384 |
| | 354 |
|
| Accrued pension and other post-retirement benefit costs | (20 | ) | | (32 | ) | | (14 | ) |
| Contributions to qualified pension plans | — |
| | (24 | ) | | (42 | ) |
| Payments for asset retirement obligations | (192 | ) | | (212 | ) | | (109 | ) |
| (Increase) decrease in | | | | | |
| Net realized and unrealized mark-to-market and hedging transactions | (4 | ) | | 4 |
| | (3 | ) |
| Receivables | (58 | ) | | (17 | ) | | 43 |
|
| Receivables from affiliated companies | 2 |
| | 11 |
| | (6 | ) |
| Inventory | 59 |
| | 12 |
| | (50 | ) |
| Other current assets | (75 | ) | | 84 |
| | 185 |
|
| Increase (decrease) in | | | | | |
| Accounts payable | (230 | ) | | 181 |
| | (65 | ) |
| Accounts payable to affiliated companies | (48 | ) | | 37 |
| | 70 |
|
| Taxes accrued | (39 | ) | | 90 |
| | (34 | ) |
| Other current liabilities | (131 | ) | | 114 |
| | 76 |
|
| Other assets | (53 | ) | | (163 | ) | | (83 | ) |
| Other liabilities | (18 | ) | | 12 |
| | (66 | ) |
| Net cash provided by operating activities | 1,195 |
| | 1,932 |
| | 1,594 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (1,715 | ) | | (1,733 | ) | | (1,669 | ) |
| Asset acquisition | — |
| | — |
| | (1,249 | ) |
| Purchases of available-for-sale securities | (1,249 | ) | | (1,658 | ) | | (727 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 1,207 |
| | 1,615 |
| | 672 |
|
| Proceeds from insurance | 4 |
| — |
| — |
| | — |
|
| Notes receivable from affiliated companies | 165 |
| | (165 | ) | | 237 |
|
| Other | (55 | ) | | 26 |
| | (30 | ) |
| Net cash used in investing activities | (1,643 | ) | | (1,915 | ) | | (2,766 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | 812 |
| | 505 |
| | 1,186 |
|
| Payments for the redemption of long-term debt | (470 | ) | | (15 | ) | | (991 | ) |
| Notes payable to affiliated companies | 240 |
| | (209 | ) | | 359 |
|
| Capital contribution from parent | — |
| | — |
| | 626 |
|
| Distributions to parent | (124 | ) | | (300 | ) | | — |
|
| Other | (1 | ) | | (2 | ) | | (2 | ) |
| Net cash provided by (used in) financing activities | 457 |
| | (21 | ) | | 1,178 |
|
| Net increase (decrease) in cash and cash equivalents | 9 |
| | (4 | ) | | 6 |
|
| Cash and cash equivalents at beginning of period | 11 |
| | 15 |
| | 9 |
|
| Cash and cash equivalents at end of period | $ | 20 |
| | $ | 11 |
| | $ | 15 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 291 |
| | $ | 248 |
| | $ | 218 |
|
| Cash paid for (received from) income taxes | 59 |
| | (287 | ) | | (197 | ) |
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 191 |
| | 147 |
| | 143 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY PROGRESS, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | |
| | Common |
| | Retained |
| | Member's |
| | Total |
|
| (in millions) | Stock |
| | Earnings |
| | Equity |
| | Equity |
|
| Balance at December 31, 2014 | $ | 2,159 |
| | $ | 3,708 |
| | $ | — |
| | $ | 5,867 |
|
| Net income | — |
| | 355 |
| | 211 |
| | 566 |
|
| Transfer to Member's Equity | (2,159 | ) | | (4,063 | ) | | 6,222 |
| | — |
|
| Capital contribution from parent | — |
| | — |
| | 626 |
| | 626 |
|
| Balance at December 31, 2015 | $ | — |
| | $ | — |
| | $ | 7,059 |
| | $ | 7,059 |
|
| Net income | — |
| | — |
| | 599 |
| | 599 |
|
| Distribution to parent | — |
| | — |
| | (300 | ) | | (300 | ) |
| Balance at December 31, 2016 | $ | — |
| | $ | — |
| | $ | 7,358 |
| | $ | 7,358 |
|
| Net income | — |
| | — |
| | 715 |
| | 715 |
|
| Distribution to parent | — |
| | — |
| | (124 | ) | | (124 | ) |
| Balance at December 31, 2017 | $ | — |
| | $ | — |
|
| $ | 7,949 |
| | $ | 7,949 |
|
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Duke Energy Florida, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Duke Energy Florida, LLC and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 2001.
DUKE ENERGY FLORIDA, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 4,646 |
| | $ | 4,568 |
| | $ | 4,977 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 1,808 |
| | 1,814 |
| | 2,195 |
|
| Operation, maintenance and other | 818 |
| | 865 |
| | 835 |
|
| Depreciation and amortization | 560 |
| | 509 |
| | 473 |
|
| Property and other taxes | 347 |
| | 333 |
| | 352 |
|
| Impairment charges | 138 |
| | 6 |
| | 7 |
|
| Total operating expenses | 3,671 |
| | 3,527 |
| | 3,862 |
|
| Gains on Sales of Other Assets and Other, net | 1 |
| | — |
| | — |
|
| Operating Income | 976 |
| | 1,041 |
| | 1,115 |
|
| Other Income and Expenses, net | 61 |
| | 44 |
| | 24 |
|
| Interest Expense | 279 |
| | 212 |
| | 198 |
|
| Income Before Income Taxes | 758 |
| | 873 |
| | 941 |
|
| Income Tax Expense | 46 |
| | 322 |
| | 342 |
|
| Net Income | $ | 712 |
| | $ | 551 |
| | $ | 599 |
|
| Other Comprehensive Income, net of tax | | | | | |
| Unrealized gains on available-for-sale securities | 3 |
| | 1 |
| | — |
|
| Other Comprehensive Income, net of tax | 3 |
| | 1 |
| | — |
|
| Comprehensive Income | $ | 715 |
| | $ | 552 |
| | $ | 599 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY FLORIDA, LLC
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 13 |
| | $ | 16 |
|
| Receivables (net of allowance for doubtful accounts of $3 at 2017 and $2 at 2016) | 65 |
| | 61 |
|
| Receivables of VIEs (net of allowance for doubtful accounts of $2 at 2017 and 2016) | 321 |
| | 288 |
|
| Receivables from affiliated companies | 2 |
| | 5 |
|
| Notes receivable from affiliated companies | 313 |
| | — |
|
| Inventory | 574 |
|
| 641 |
|
| Regulatory assets (includes $51 at 2017 and $50 at 2016 related to VIEs) | 389 |
| | 213 |
|
| Other (includes $40 at 2017 and $53 at 2016 related to VIEs) | 86 |
| | 125 |
|
| Total current assets | 1,763 |
| | 1,349 |
|
| Property, Plant and Equipment | | | |
| Cost | 17,730 |
| | 16,434 |
|
| Accumulated depreciation and amortization | (4,947 | ) | | (4,644 | ) |
| Net property, plant and equipment | 12,783 |
| | 11,790 |
|
| Other Noncurrent Assets | | | |
| Regulatory assets (includes $1,091 at 2017 and $1,142 at 2016 related to VIEs) | 2,503 |
| | 2,480 |
|
| Nuclear decommissioning trust funds | 736 |
| | 715 |
|
| Other | 284 |
| | 278 |
|
| Total other noncurrent assets | 3,523 |
| | 3,473 |
|
| Total Assets | $ | 18,069 |
| | $ | 16,612 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 602 |
| | $ | 413 |
|
| Accounts payable to affiliated companies | 74 |
| | 125 |
|
| Notes payable to affiliated companies | — |
| | 297 |
|
| Taxes accrued | 34 |
| | 33 |
|
| Interest accrued | 56 |
| | 49 |
|
| Current maturities of long-term debt (includes $53 at 2017 and $62 at 2016 related to VIEs) | 768 |
| | 326 |
|
| Regulatory liabilities | 74 |
| | 31 |
|
| Other | 334 |
| | 352 |
|
| Total current liabilities | 1,942 |
| | 1,626 |
|
| Long-Term Debt (includes $1,389 at 2017 and $1,442 at 2016 related to VIEs) | 6,327 |
| | 5,799 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 1,761 |
| | 2,694 |
|
| Asset retirement obligations | 742 |
| | 778 |
|
| Regulatory liabilities | 1,307 |
| | 448 |
|
| Accrued pension and other post-retirement benefit costs | 264 |
| | 262 |
|
| Other | 108 |
| | 105 |
|
| Total other noncurrent liabilities | 4,182 |
| | 4,287 |
|
| Commitments and Contingencies | | | |
| Equity | | | |
| Member's equity | 5,614 |
| | 4,899 |
|
| Accumulated other comprehensive income | 4 |
| | 1 |
|
| Total equity | 5,618 |
| | 4,900 |
|
| Total Liabilities and Equity | $ | 18,069 |
| | $ | 16,612 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY FLORIDA, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 712 |
| | $ | 551 |
| | $ | 599 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 570 |
| | 516 |
| | 480 |
|
| Equity component of AFUDC | (45 | ) | | (26 | ) | | (7 | ) |
| Gains on sales of other assets | (1 | ) | | — |
| | — |
|
| Impairment charges | 138 |
| | 6 |
| | 7 |
|
| Deferred income taxes | 245 |
| | 224 |
| | 348 |
|
| Accrued pension and other post-retirement benefit costs | (13 | ) | | 2 |
| | 5 |
|
| Contributions to qualified pension plans | — |
| | (20 | ) | | (40 | ) |
| Payments for asset retirement obligations | (56 | ) | | (58 | ) | | (47 | ) |
| (Increase) decrease in | | | | | |
| Net realized and unrealized mark-to-market and hedging transactions | 5 |
| | 38 |
| | (3 | ) |
| Receivables | (38 | ) | | 23 |
| | 61 |
|
| Receivables from affiliated companies | — |
| | 21 |
| | (44 | ) |
| Inventory | 66 |
| | 23 |
| | (17 | ) |
| Other current assets | (125 | ) | | (133 | ) | | 116 |
|
| Increase (decrease) in | | | | | |
| Accounts payable | (32 | ) | | 71 |
| | (127 | ) |
| Accounts payable to affiliated companies | (51 | ) | | 9 |
| | 46 |
|
| Taxes accrued | 1 |
| | (117 | ) | | 67 |
|
| Other current liabilities | (37 | ) | | (149 | ) | | 57 |
|
| Other assets | (229 | ) | | (84 | ) | | (84 | ) |
| Other liabilities | (82 | ) | | (53 | ) | | (44 | ) |
| Net cash provided by operating activities | 1,028 |
| | 844 |
| | 1,373 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (1,437 | ) | | (1,583 | ) | | (1,029 | ) |
| Purchases of available-for-sale securities | (557 | ) | | (485 | ) | | (447 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 617 |
| | 572 |
| | 538 |
|
| Proceeds from insurance | 4 |
| | 58 |
| | — |
|
| Proceeds from the sale of nuclear fuel | 20 |
| | 20 |
| | 102 |
|
| Notes receivable from affiliated companies | (313 | ) | | — |
| | — |
|
| Change in restricted cash | — |
| | (6 | ) | | — |
|
| Other | (31 | ) | | 21 |
| | (3 | ) |
| Net cash used in investing activities | (1,697 | ) | | (1,403 | ) | | (839 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | 1,306 |
| | 1,870 |
| | — |
|
| Payments for the redemption of long-term debt | (342 | ) | | (12 | ) | | (562 | ) |
| Notes payable to affiliated companies | (297 | ) | | (516 | ) | | 729 |
|
| Dividends to parent | — |
| | — |
| | (350 | ) |
| Distribution to parent | — |
| | (775 | ) | | (350 | ) |
| Other | (1 | ) | | — |
| | (1 | ) |
| Net cash provided by (used in) financing activities | 666 |
| | 567 |
| | (534 | ) |
| Net (decrease) increase in cash and cash equivalents | (3 | ) | | 8 |
| | — |
|
| Cash and cash equivalents at beginning of period | 16 |
| | 8 |
| | 8 |
|
| Cash and cash equivalents at end of period | $ | 13 |
| | $ | 16 |
| | $ | 8 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 274 |
| | $ | 208 |
| | $ | 205 |
|
| Cash (received from) paid for income taxes | (197 | ) | | 216 |
| | (229 | ) |
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 199 |
| | 170 |
| | 186 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY FLORIDA, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | Accumulated | |
| | | | | | | | Other | |
| | | | | | | | Comprehensive | |
| | | | | | | | Income | |
| | | | | | | | Net Unrealized |
| | |
| | | | | | | | Gains on |
| | |
| | Common |
| | Retained |
| | Member's |
| | Available-for- |
| | Total |
|
| (in millions) | Stock |
| | Earnings |
| | Equity |
| | Sale Securities |
| | Equity |
|
| Balance at December 31, 2014 | $ | 1,762 |
| | $ | 3,460 |
| | $ | — |
| | $ | — |
| | $ | 5,222 |
|
| Net income | — |
| | 351 |
| | 248 |
| | — |
| | 599 |
|
| Transfer to Member's Equity | (1,762 | ) | | (3,461 | ) | | 5,223 |
| | — |
| | — |
|
| Dividends to parent | — |
| | (350 | ) | | — |
| | — |
| | (350 | ) |
| Distribution to parent | — |
| | — |
| | (350 | ) | | — |
| | (350 | ) |
| Balance at December 31, 2015 | $ | — |
| | $ | — |
| | $ | 5,121 |
| | $ | — |
| | $ | 5,121 |
|
| Net income | — |
| | — |
| | 551 |
| | — |
| | 551 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Distribution to parent | — |
| | — |
| | (775 | ) | | — |
| | (775 | ) |
| Other | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Balance at December 31, 2016 | $ | — |
| | $ | — |
| | $ | 4,899 |
| | $ | 1 |
| | $ | 4,900 |
|
| Net income | — |
| | — |
| | 712 |
| | — |
| | 712 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
| Other | — |
| | — |
| | 3 |
| | — |
| | 3 |
|
| Balance at December 31, 2017 | $ | — |
| | $ | — |
| | $ | 5,614 |
| | $ | 4 |
| | $ | 5,618 |
|
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Duke Energy Ohio, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Duke Energy Ohio, Inc. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 2002.
DUKE ENERGY OHIO, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | | | | | |
| Regulated electric | $ | 1,373 |
| | $ | 1,410 |
| | $ | 1,331 |
|
| Nonregulated electric and other | 42 |
| | 31 |
| | 33 |
|
| Regulated natural gas | 508 |
| | 503 |
| | 541 |
|
| Total operating revenues | 1,923 |
| | 1,944 |
| | 1,905 |
|
Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power – regulated | 369 |
| | 442 |
| | 446 |
|
| Fuel used in electric generation and purchased power – nonregulated | 58 |
| | 51 |
| | 47 |
|
| Cost of natural gas | 107 |
| | 103 |
| | 141 |
|
| Operation, maintenance and other | 524 |
| | 512 |
| | 495 |
|
| Depreciation and amortization | 261 |
| | 233 |
| | 227 |
|
| Property and other taxes | 278 |
| | 258 |
| | 254 |
|
| Impairment charges | 1 |
| | — |
| | — |
|
| Total operating expenses | 1,598 |
| | 1,599 |
| | 1,610 |
|
| Gains on Sales of Other Assets and Other, net | 1 |
| | 2 |
| | 8 |
|
| Operating Income | 326 |
| | 347 |
| | 303 |
|
| Other Income and Expenses, net | 17 |
| | 9 |
| | 6 |
|
| Interest Expense | 91 |
| | 86 |
| | 79 |
|
| Income From Continuing Operations Before Income Taxes | 252 |
| | 270 |
| | 230 |
|
| Income Tax Expense From Continuing Operations | 59 |
| | 78 |
| | 81 |
|
| Income From Continuing Operations | 193 |
| | 192 |
| | 149 |
|
| (Loss) Income From Discontinued Operations, net of tax | (1 | ) | | 36 |
| | 23 |
|
| Net Income and Comprehensive Income | $ | 192 |
| | $ | 228 |
| | $ | 172 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY OHIO, INC.
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 12 |
| | $ | 13 |
|
| Receivables (net of allowance for doubtful accounts of $3 at 2017 and $2 at 2016) | 68 |
| | 71 |
|
| Receivables from affiliated companies | 133 |
| | 129 |
|
| Notes receivable from affiliated companies | 14 |
| | 94 |
|
| Inventory | 133 |
|
| 137 |
|
| Regulatory assets | 49 |
| | 37 |
|
| Other | 39 |
| | 37 |
|
| Total current assets | 448 |
| | 518 |
|
| Property, Plant and Equipment | | | |
| Cost | 8,732 |
| | 8,126 |
|
| Accumulated depreciation and amortization | (2,691 | ) | | (2,579 | ) |
| Net property, plant and equipment | 6,041 |
| | 5,547 |
|
| Other Noncurrent Assets | | | |
| Goodwill | 920 |
| | 920 |
|
| Regulatory assets | 445 |
| | 520 |
|
| Other | 21 |
| | 23 |
|
| Total other noncurrent assets | 1,386 |
| | 1,463 |
|
| Total Assets | $ | 7,875 |
| | $ | 7,528 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 313 |
| | $ | 282 |
|
| Accounts payable to affiliated companies | 62 |
| | 63 |
|
| Notes payable to affiliated companies | 29 |
| | 16 |
|
| Taxes accrued | 190 |
| | 178 |
|
| Interest accrued | 21 |
| | 19 |
|
| Current maturities of long-term debt | 3 |
| | 1 |
|
| Asset retirement obligations | 3 |
| | — |
|
| Regulatory liabilities | 36 |
| | 21 |
|
| Other | 71 |
| | 91 |
|
| Total current liabilities | 728 |
| | 671 |
|
| Long-Term Debt | 2,039 |
| | 1,858 |
|
| Long-Term Debt Payable to Affiliated Companies | 25 |
| | 25 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 781 |
| | 1,443 |
|
| Asset retirement obligations | 81 |
| | 77 |
|
| Regulatory liabilities | 891 |
| | 236 |
|
| Accrued pension and other post-retirement benefit costs | 59 |
| | 56 |
|
| Other | 108 |
| | 166 |
|
| Total other noncurrent liabilities | 1,920 |
| | 1,978 |
|
| Commitments and Contingencies | | | |
| Equity | | | |
| Common stock, $8.50 par value, 120 million shares authorized; 90 million shares outstanding at 2017 and 2016 | 762 |
| | 762 |
|
| Additional paid-in capital | 2,670 |
| | 2,695 |
|
| Accumulated deficit | (269 | ) | | (461 | ) |
| Total equity | 3,163 |
| | 2,996 |
|
| Total Liabilities and Equity | $ | 7,875 |
| | $ | 7,528 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY OHIO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 192 |
| | $ | 228 |
| | $ | 172 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation, amortization and accretion | 265 |
| | 237 |
| | 230 |
|
| Equity component of AFUDC | (11 | ) | | (6 | ) | | (3 | ) |
| Gains on sales of other assets | (1 | ) | | (2 | ) | | (8 | ) |
| Impairment charges | 1 |
| | — |
| | 40 |
|
| Deferred income taxes | 90 |
| | 55 |
| | 206 |
|
| Accrued pension and other post-retirement benefit costs | 2 |
| | 6 |
| | 9 |
|
| Contributions to qualified pension plans | (4 | ) | | (5 | ) | | (8 | ) |
| Payments for asset retirement obligations | (7 | ) | | (5 | ) | | (4 | ) |
| (Increase) decrease in | | | | | |
| Net realized and unrealized mark-to-market and hedging transactions | — |
| | (2 | ) | | (10 | ) |
| Receivables | 2 |
| | (4 | ) | | 23 |
|
| Receivables from affiliated companies | (4 | ) | | (36 | ) | | 23 |
|
| Inventory | 6 |
| | (32 | ) | | — |
|
| Other current assets | (22 | ) | | 79 |
| | — |
|
| Increase (decrease) in | | | | | |
| Accounts payable | 12 |
| | 19 |
| | (1 | ) |
| Accounts payable to affiliated companies | (1 | ) | | 10 |
| | (21 | ) |
| Taxes accrued | 11 |
| | 3 |
| | (21 | ) |
| Other current liabilities | (19 | ) | | (54 | ) | | 88 |
|
| Other assets | (28 | ) | | (35 | ) | | 25 |
|
| Other liabilities | (5 | ) | | (31 | ) | | (73 | ) |
| Net cash provided by operating activities | 479 |
| | 425 |
| | 667 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (686 | ) | | (476 | ) | | (399 | ) |
| Notes receivable from affiliated companies | 80 |
| | (94 | ) | | 145 |
|
| Other | (41 | ) | | (30 | ) | | (15 | ) |
| Net cash used in investing activities | (647 | ) | | (600 | ) | | (269 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | 182 |
| | 341 |
| | — |
|
| Payments for the redemption of long-term debt | (2 | ) | | (53 | ) | | (157 | ) |
| Notes payable to affiliated companies | 13 |
| | (87 | ) | | (95 | ) |
| Dividends to parent | (25 | ) | | (25 | ) | | (150 | ) |
| Other | (1 | ) | | (2 | ) | | (2 | ) |
| Net cash provided by (used in) financing activities | 167 |
| | 174 |
| | (404 | ) |
| Net decrease in cash and cash equivalents | (1 | ) | | (1 | ) | | (6 | ) |
| Cash and cash equivalents at beginning of period | 13 |
| | 14 |
| | 20 |
|
| Cash and cash equivalents at end of period | $ | 12 |
| | $ | 13 |
| | $ | 14 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 85 |
| | $ | 81 |
| | $ | 76 |
|
| Cash (received from) paid for income taxes | (8 | ) | | (46 | ) | | 410 |
|
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 82 |
| | 83 |
| | 20 |
|
| Distribution of membership interest of Duke Energy SAM, LLC to parent | — |
| | — |
| | 1,912 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY OHIO, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | Additional |
| | | | |
| | Common |
| | Paid-in |
| | Accumulated |
| | Total |
|
| (in millions) | Stock |
| | Capital |
| | Deficit |
| | Equity |
|
| Balance at December 31, 2014 | $ | 762 |
| | $ | 4,782 |
| | $ | (870 | ) | | $ | 4,674 |
|
| Net income | — |
| | — |
| | 172 |
| | 172 |
|
| Dividends to parent | — |
| | (150 | ) | | — |
| | (150 | ) |
| Distribution of membership interest of Duke Energy SAM, LLC to parent | — |
| | (1,912 | ) | | — |
| | (1,912 | ) |
| Balance at December 31, 2015 | $ | 762 |
| | $ | 2,720 |
| | $ | (698 | ) | | $ | 2,784 |
|
| Net income | — |
| | — |
| | 228 |
| | 228 |
|
| Contribution from parent | — |
| | — |
| | 9 |
| | 9 |
|
| Dividends to parent | — |
| | (25 | ) | | — |
| | (25 | ) |
| Balance at December 31, 2016 | $ | 762 |
|
| $ | 2,695 |
|
| $ | (461 | ) |
| $ | 2,996 |
|
| Net income | — |
| | — |
| | 192 |
| | 192 |
|
| Dividends to parent | — |
| | (25 | ) | | — |
| | (25 | ) |
| Balance at December 31, 2017 | $ | 762 |
| | $ | 2,670 |
| | $ | (269 | ) | | $ | 3,163 |
|
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Duke Energy Indiana, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Duke Energy Indiana, LLC and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 2002.
DUKE ENERGY INDIANA, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 3,047 |
| | $ | 2,958 |
| | $ | 2,890 |
|
| Operating Expenses | | | | | |
| Fuel used in electric generation and purchased power | 966 |
|
| 909 |
| | 982 |
|
| Operation, maintenance and other | 733 |
|
| 723 |
| | 682 |
|
| Depreciation and amortization | 458 |
|
| 496 |
| | 434 |
|
| Property and other taxes | 76 |
|
| 58 |
| | 61 |
|
| Impairment charges | 18 |
|
| 8 |
| | 88 |
|
| Total operating expenses | 2,251 |
| | 2,194 |
| | 2,247 |
|
| Gains on Sales of Other Assets and Other, net | — |
| | 1 |
| | 1 |
|
| Operating Income | 796 |
| | 765 |
| | 644 |
|
| Other Income and Expenses, net | 37 |
| | 22 |
| | 11 |
|
| Interest Expense | 178 |
| | 181 |
| | 176 |
|
| Income Before Income Taxes | 655 |
|
| 606 |
|
| 479 |
|
| Income Tax Expense | 301 |
| | 225 |
| | 163 |
|
| Net Income | $ | 354 |
|
| $ | 381 |
|
| $ | 316 |
|
| Other Comprehensive Loss, net of tax | | | | | |
| Reclassification into earnings from cash flow hedges | — |
| | (1 | ) | | (2 | ) |
| Comprehensive Income | $ | 354 |
|
| $ | 380 |
|
| $ | 314 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY INDIANA, LLC
CONSOLIDATED BALANCE SHEETS |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 9 |
| | $ | 17 |
|
| Receivables (net of allowance for doubtful accounts of $2 at 2017 and $1 at 2016) | 57 |
| | 105 |
|
| Receivables from affiliated companies | 125 |
| | 114 |
|
| Notes receivable from affiliated companies | — |
| | 86 |
|
| Inventory | 450 |
|
| 504 |
|
| Regulatory assets | 165 |
| | 149 |
|
| Other | 30 |
| | 45 |
|
| Total current assets | 836 |
| | 1,020 |
|
| Property, Plant and Equipment | | | |
| Cost | 14,948 |
| | 14,241 |
|
| Accumulated depreciation and amortization | (4,662 | ) | | (4,317 | ) |
| Net property, plant and equipment | 10,286 |
| | 9,924 |
|
| Other Noncurrent Assets | | |
|
| Regulatory assets | 978 |
| | 1,073 |
|
| Other | 189 |
| | 147 |
|
| Total other noncurrent assets | 1,167 |
| | 1,220 |
|
| Total Assets | $ | 12,289 |
| | $ | 12,164 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 196 |
| | $ | 263 |
|
| Accounts payable to affiliated companies | 78 |
| | 74 |
|
| Notes payable to affiliated companies | 161 |
| | — |
|
| Taxes accrued | 95 |
| | 31 |
|
| Interest accrued | 57 |
| | 61 |
|
| Current maturities of long-term debt | 3 |
| | 3 |
|
| Asset retirement obligations | 54 |
| | — |
|
| Regulatory liabilities | 24 |
| | 40 |
|
| Other | 104 |
| | 93 |
|
| Total current liabilities | 772 |
| | 565 |
|
| Long-Term Debt | 3,630 |
| | 3,633 |
|
| Long-Term Debt Payable to Affiliated Companies | 150 |
| | 150 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 925 |
| | 1,900 |
|
| Asset retirement obligations | 727 |
| | 866 |
|
| Regulatory liabilities | 1,723 |
| | 748 |
|
| Accrued pension and other post-retirement benefit costs | 76 |
| | 71 |
|
| Investment tax credits | 147 |
| | 137 |
|
| Other | 18 |
| | 27 |
|
| Total other noncurrent liabilities | 3,616 |
| | 3,749 |
|
| Commitments and Contingencies | | | |
| Equity | | | |
| Member's Equity | 4,121 |
| | 4,067 |
|
| Total Liabilities and Equity | $ | 12,289 |
| | $ | 12,164 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY INDIANA, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | |
| Net income | $ | 354 |
| | $ | 381 |
| | $ | 316 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 462 |
| | 499 |
| | 439 |
|
| Equity component of AFUDC | (28 | ) | | (16 | ) | | (11 | ) |
| Gains on sales of other assets | — |
| | — |
| | (1 | ) |
| Impairment charges | 18 |
| | 8 |
| | 88 |
|
| Deferred income taxes | 152 |
| | 213 |
| | 262 |
|
| Accrued pension and other post-retirement benefit costs | 2 |
| | 8 |
| | 13 |
|
| Contributions to qualified pension plans | — |
| | (9 | ) | | (19 | ) |
| Payments for asset retirement obligations | (45 | ) | | (46 | ) | | (19 | ) |
| (Increase) decrease in | | | | | |
| Receivables | 59 |
| | (2 | ) | | (7 | ) |
| Receivables from affiliated companies | (11 | ) | | (43 | ) | | 44 |
|
| Inventory | 54 |
| | 66 |
| | (21 | ) |
| Other current assets | 28 |
| | (67 | ) | | 90 |
|
| Increase (decrease) in | | | | | |
| Accounts payable | (86 | ) | | 8 |
| | 33 |
|
| Accounts payable to affiliated companies | 4 |
| | (9 | ) | | 25 |
|
| Taxes accrued | 64 |
| | (4 | ) | | 35 |
|
| Other current liabilities | (10 | ) | | (81 | ) | | 26 |
|
| Other assets | (28 | ) | | (27 | ) | | (82 | ) |
| Other liabilities | (20 | ) | | (8 | ) | | (35 | ) |
| Net cash provided by operating activities | 969 |
| | 871 |
| | 1,176 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | |
| Capital expenditures | (840 | ) | | (755 | ) | | (690 | ) |
| Purchases of available-for-sale securities | (20 | ) | | (14 | ) | | (9 | ) |
| Proceeds from sales and maturities of available-for-sale securities | 7 |
| | 11 |
| | 11 |
|
| Proceeds from the sales of other assets | — |
| | — |
| | 17 |
|
| Notes receivable from affiliated companies | 86 |
| | (3 | ) | | (83 | ) |
| Other | (65 | ) | | 32 |
| | (17 | ) |
| Net cash used in investing activities | (832 | ) | | (729 | ) | | (771 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | |
| Proceeds from the issuance of long-term debt | — |
| | 494 |
| | — |
|
| Payments for the redemption of long-term debt | (5 | ) | | (478 | ) | | (5 | ) |
| Notes payable to affiliated companies | 161 |
| | — |
| | (71 | ) |
| Dividends to parent | — |
| | — |
| | (326 | ) |
| Distributions to parent | (300 | ) | | (149 | ) | | — |
|
| Other | (1 | ) | | (1 | ) | | — |
|
| Net cash used in financing activities | (145 | ) | | (134 | ) | | (402 | ) |
| Net (decrease) increase in cash and cash equivalents | (8 | ) | | 8 |
| | 3 |
|
| Cash and cash equivalents at beginning of period | 17 |
| | 9 |
| | 6 |
|
| Cash and cash equivalents at end of period | $ | 9 |
| | $ | 17 |
| | $ | 9 |
|
| Supplemental Disclosures: | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 179 |
| | $ | 171 |
| | $ | 175 |
|
| Cash paid for (received from) income taxes | 117 |
| | (7 | ) | | (253 | ) |
| Significant non-cash transactions: | | | | | |
| Accrued capital expenditures | 125 |
| | 99 |
| | 64 |
|
See Notes to Consolidated Financial Statements
DUKE ENERGY INDIANA, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | | | | | Other | | |
| | | | | | | | | | Comprehensive | | |
| | | | | | | | | | Income | | |
| | | | Additional |
| | | | | | Net Gains on |
| | |
| | Common |
| | Paid-in |
| | Retained |
| | Member's |
| | Cash Flow |
| | Total |
|
| (in millions) | Stock |
| | Capital |
| | Earnings |
| | Equity |
| | Hedges |
| | Equity |
|
| Balance at December 31, 2014 | $ | 1 |
| | $ | 1,384 |
| | $ | 2,460 |
| | $ | — |
| | $ | 3 |
| | $ | 3,848 |
|
| Net income | — |
| | — |
| | 316 |
| | — |
| | — |
| | 316 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (2 | ) |
| Dividends to parent | — |
| | — |
| | (326 | ) | | — |
| | — |
| | (326 | ) |
| Balance at December 31, 2015 | $ | 1 |
|
| $ | 1,384 |
|
| $ | 2,450 |
|
| $ | — |
| | $ | 1 |
|
| $ | 3,836 |
|
| Net income | — |
| | — |
| | — |
| | 381 |
| | — |
| | 381 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Distributions to parent | — |
| | — |
| | — |
| | (149 | ) | | — |
| | (149 | ) |
| Transfer to Member's Equity | (1 | ) | | (1,384 | ) | | (2,450 | ) | | 3,835 |
| | — |
| | — |
|
| Balance at December 31, 2016 | $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 4,067 |
| | $ | — |
|
| $ | 4,067 |
|
| Net income | — |
| | — |
| | — |
| | 354 |
| | — |
| | 354 |
|
| Distributions to parent | — |
| | — |
| | — |
| | (300 | ) | | — |
| | (300 | ) |
| Balance at December 31, 2017 | $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 4,121 |
| | $ | — |
|
| $ | 4,121 |
|
See Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Piedmont Natural Gas Company, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations and comprehensive income, changes in equity, and cash flows, for each of the three years in the periods ended December 31, 2017, October 31, 2016, October 31, 2015 and for the 2 months ended December 31, 2016 and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the periods ended December 31, 2017, October 31, 2016, October 31, 2015 and for the 2 months ended December 31, 2016, in conformity with the accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Emphasis of Matter
As discussed in Note 1 to the financial statements, effective for fiscal year 2016, the Company changed its fiscal year end from October 31 to December 31. This resulted in a 2-month transition period beginning November 1, 2016 through December 31, 2016.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
February 21, 2018
We have served as the Company's auditor since 1951.
PIEDMONT NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME |
| | | | | | | | | | | | | | | |
| | Year Ended | | Two Months Ended | | Years Ended October 31, |
| (in millions) | December 31, 2017 |
| | December 31, 2016 | | 2016 |
| | 2015 |
|
| Operating Revenues | | | | | | | |
| Regulated natural gas | $ | 1,319 |
| | $ | 320 |
| | $ | 1,139 |
| | $ | 1,372 |
|
| Nonregulated natural gas and other | 9 |
| | 2 |
| | 10 |
| | 11 |
|
| Total operating revenues | 1,328 |
| | 322 |
| | 1,149 |
| | 1,383 |
|
| Operating Expenses | | | | | | | |
| Cost of natural gas | 524 |
| | 144 |
| | 391 |
| | 644 |
|
| Operation, maintenance and other | 315 |
| | 52 |
| | 353 |
| | 305 |
|
| Depreciation and amortization | 148 |
| | 23 |
| | 137 |
| | 129 |
|
| Property and other taxes | 48 |
| | 7 |
| | 43 |
| | 42 |
|
| Impairment charges | 7 |
| | — |
| | — |
| | — |
|
| Total operating expenses | 1,042 |
| | 226 |
|
| 924 |
|
| 1,120 |
|
| Operating Income | 286 |
| | 96 |
|
| 225 |
|
| 263 |
|
| Equity in (losses) earnings of unconsolidated affiliates | (6 | ) | | 2 |
| | 29 |
| | 34 |
|
| Gain on sale of unconsolidated affiliates | — |
| | — |
| | 133 |
| | — |
|
| Other income and expense, net | — |
| | — |
| | (1 | ) | | (1 | ) |
| Total other income and expenses | (6 | ) | | 2 |
|
| 161 |
|
| 33 |
|
| Interest Expense | 79 |
| | 12 |
| | 69 |
| | 69 |
|
| Income Before Income Taxes | 201 |
| | 86 |
|
| 317 |
|
| 227 |
|
| Income Tax Expense | 62 |
| | 32 |
| | 124 |
| | 90 |
|
| Net Income | $ | 139 |
| | $ | 54 |
|
| $ | 193 |
|
| $ | 137 |
|
| Other Comprehensive Income (Loss), net of tax | | | | | | | |
| Unrealized loss from hedging activities of equity method investments | — |
| | — |
| | (3 | ) | | (2 | ) |
| Reclassification into earnings from hedging activities of equity method investments | — |
| | — |
| | 4 |
| | 1 |
|
| Other Comprehensive Income (Loss), net of tax | — |
| | — |
| | 1 |
| | (1 | ) |
| Comprehensive Income | $ | 139 |
| | $ | 54 |
| | $ | 194 |
| | $ | 136 |
|
See Notes to Consolidated Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC.
CONSOLIDATED BALANCE SHEETS
|
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 19 |
| | $ | 25 |
|
| Receivables (net of allowance for doubtful accounts of $2 at 2017 and $3 at 2016) | 275 |
| | 232 |
|
| Receivables from affiliated companies | 7 |
| | 7 |
|
| Inventory | 66 |
| | 66 |
|
| Regulatory assets | 95 |
| | 124 |
|
| Other | 52 |
| | 21 |
|
| Total current assets | 514 |
| | 475 |
|
| Property, Plant and Equipment | | | |
| Cost | 6,725 |
| | 6,174 |
|
| Accumulated depreciation and amortization | (1,479 | ) | | (1,360 | ) |
| Net property, plant and equipment | 5,246 |
| | 4,814 |
|
| Other Noncurrent Assets | | | |
| Goodwill | 49 |
| | 49 |
|
| Regulatory assets | 283 |
| | 373 |
|
| Investments in equity method unconsolidated affiliates | 61 |
| | 212 |
|
| Other | 65 |
| | 21 |
|
| Total other noncurrent assets | 458 |
| | 655 |
|
| Total Assets | $ | 6,218 |
| | $ | 5,944 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
| Accounts payable | $ | 125 |
| | $ | 155 |
|
| Accounts payable to affiliated companies | 13 |
| | 8 |
|
| Notes payable and commercial paper | — |
| | 330 |
|
| Notes payable to affiliated companies | 364 |
| | — |
|
| Taxes accrued | 19 |
| | 67 |
|
| Interest accrued | 31 |
| | 33 |
|
| Current maturities of long-term debt | 250 |
| | 35 |
|
| Regulatory liabilities | 3 |
| | — |
|
| Other | 69 |
| | 102 |
|
| Total current liabilities | 874 |
| | 730 |
|
| Long-Term Debt | 1,787 |
| | 1,786 |
|
| Other Noncurrent Liabilities | | | |
| Deferred income taxes | 564 |
| | 931 |
|
| Asset retirement obligations | 15 |
| | 14 |
|
| Regulatory liabilities | 1,141 |
| | 608 |
|
| Accrued pension and other post-retirement benefit costs | 5 |
| | 14 |
|
| Other | 170 |
| | 189 |
|
| Total other noncurrent liabilities | 1,895 |
| | 1,756 |
|
| Commitments and Contingencies | | | |
| Equity | | | |
| Common stock, no par value: 100 shares authorized and outstanding at 2017 and 2016 | 860 |
| | 860 |
|
| Retained earnings | 802 |
| | 812 |
|
| Total equity | 1,662 |
| | 1,672 |
|
| Total Liabilities and Equity | $ | 6,218 |
| | $ | 5,944 |
|
See Notes to Consolidated Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | | | | | | | |
| | Year Ended | | Two Months Ended | | Years Ended October 31, |
| (in millions) | December 31, 2017 |
| | December 31, 2016 |
| | 2016 |
| | 2015 |
|
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net income | $ | 139 |
| | $ | 54 |
| | $ | 193 |
| | $ | 137 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | |
| Depreciation and amortization | 151 |
| | 25 |
| | 148 |
| | 140 |
|
| Gains on sales of other assets | — |
| | — |
| | (133 | ) | | — |
|
| Impairment charges | 7 |
| | — |
| | — |
| | — |
|
| Deferred income taxes | 154 |
| | 26 |
| | 74 |
| | 73 |
|
| Equity in losses (earnings) from unconsolidated affiliates | 6 |
| | (2 | ) | | (29 | ) | | (34 | ) |
| Accrued pension and other post-retirement benefit costs | 23 |
| | 5 |
| | 3 |
| | 8 |
|
| Contributions to qualified pension plans | (11 | ) | | (10 | ) | | (14 | ) | | (13 | ) |
| Payments for asset retirement obligations | — |
| | (1 | ) | | (6 | ) | | (6 | ) |
| (Increase) decrease in | | | | | | | |
| Receivables | (40 | ) | | (157 | ) | | 12 |
| | 3 |
|
| Receivables from affiliated companies | — |
| | — |
| | (7 | ) | | — |
|
| Inventory | — |
| | (11 | ) | | 14 |
| | 16 |
|
| Other current assets | (20 | ) | | 8 |
| | (98 | ) | | 46 |
|
| Increase (decrease) in | | | | | | | |
| Accounts payable | (13 | ) | | 35 |
| | 6 |
| | (5 | ) |
| Accounts payable to affiliated companies | 5 |
| | 4 |
| | 6 |
| | — |
|
| Taxes accrued | (48 | ) | | (2 | ) | | 38 |
| | 4 |
|
| Other current liabilities | (9 | ) | | 2 |
| | 28 |
| | (21 | ) |
| Other assets | 7 |
| | (7 | ) | | (107 | ) | | (5 | ) |
| Other liabilities | (2 | ) | | 5 |
| | 180 |
| | 29 |
|
| Net cash provided by (used in) operating activities | 349 |
| | (26 | ) | | 308 |
| | 372 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
| Capital expenditures | (585 | ) | | (113 | ) | | (522 | ) | | (444 | ) |
| Contributions to equity method investments | (12 | ) | | (12 | ) | | (47 | ) | | (30 | ) |
| Proceeds from the sales of other assets | — |
| | — |
| | 175 |
| | — |
|
| Other | (6 | ) | | 1 |
| | 21 |
| | (5 | ) |
| Net cash used in investing activities | (603 | ) | | (124 | ) | | (373 | ) | | (479 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
| Proceeds from the: | | | | | | | |
| Issuance of long-term debt | 250 |
| | — |
| | 295 |
| | 148 |
|
| Issuance of common stock | — |
| | — |
| | 122 |
| | 81 |
|
| Payments for the redemption of long-term debt | (35 | ) | | — |
| | (40 | ) | | — |
|
| Notes payable and commercial paper | (330 | ) | | 185 |
| | (195 | ) | | (15 | ) |
| Notes payable to affiliated companies | 364 |
| | — |
| | — |
| | — |
|
| Dividends to parent | — |
| | (27 | ) | | — |
| | — |
|
| Dividends paid | — |
| | — |
| | (114 | ) | | (103 | ) |
| Other | (1 | ) | | — |
| | — |
| | — |
|
| Net cash provided by financing activities | 248 |
| | 158 |
| | 68 |
| | 111 |
|
| Net (decrease) increase in cash and cash equivalents | (6 | ) | | 8 |
| | 3 |
| | 4 |
|
| Cash and cash equivalents at beginning of period | 25 |
| | 17 |
| | 14 |
| | 10 |
|
| Cash and cash equivalents at end of period | $ | 19 |
| | $ | 25 |
| | $ | 17 |
| | $ | 14 |
|
| Supplemental Disclosures: | | | | | | | |
| Cash paid for interest, net of amount capitalized | $ | 78 |
| | $ | 11 |
| | $ | 81 |
| | $ | 72 |
|
| Cash (received from) paid for income taxes | (12 | ) | | — |
| | (25 | ) | | 3 |
|
| Significant non-cash transactions: | | | | | | | |
| Accrued capital expenditures | 34 |
| | 48 |
| | 63 |
| | 59 |
|
| Transfer of ownership interest of certain equity method investees to parent | 149 |
| | — |
| | — |
| | — |
|
See Notes to Consolidated Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| | | | | | | | | | | | | | | |
| | | | | | Accumulated | | |
| | | | | | Other | | |
| | | | | | Comprehensive | | |
| | | | | | Income (Loss) | | |
| | | | | | Net Loss on |
| | |
| | | | | | Hedging Activities |
| | |
| | Common |
| | Retained |
| | of Unconsolidated |
| | Total |
|
| (in millions) | Stock |
| | Earnings |
| | Affiliates |
| | Equity |
|
| Balance at October 31, 2014 | $ | 637 |
| | $ | 672 |
| | $ | — |
| | $ | 1,309 |
|
| Net income | — |
| | 137 |
| | — |
| | 137 |
|
| Other comprehensive loss | — |
| | — |
| | (1 | ) | | (1 | ) |
| Common stock issuances, including dividend reinvestment and employee benefits | 85 |
| | — |
| | — |
| | 85 |
|
| Expenses from issuance of common stock | (1 | ) | | — |
| | — |
| | (1 | ) |
| Common stock dividends | — |
| | (103 | ) | | — |
| | (103 | ) |
| Balance at October 31, 2015 | $ | 721 |
| | $ | 706 |
| | $ | (1 | ) | | $ | 1,426 |
|
| Net income | — |
| | 193 |
| | — |
| | 193 |
|
| Other comprehensive income | — |
| | — |
| | 1 |
| | 1 |
|
| Common stock issuances, including dividend reinvestment and employee benefits | 139 |
| | — |
| | — |
| | 139 |
|
| Common stock dividends | — |
| | (114 | ) | | — |
| | (114 | ) |
| Balance at October 31, 2016 | $ | 860 |
| | $ | 785 |
| | $ | — |
| | $ | 1,645 |
|
| Net income | — |
| | 54 |
| | — |
| | 54 |
|
| Dividends to parent | — |
| | (27 | ) | | — |
| | (27 | ) |
| Balance at December 31, 2016 | $ | 860 |
| | $ | 812 |
| | $ | — |
| | $ | 1,672 |
|
Net income | — |
| | 139 |
| | — |
| | 139 |
|
| Transfer of ownership interest of certain equity method investees to parent | — |
| | (149 | ) | | — |
| | (149 | ) |
| Balance at December 31, 2017 | $ | 860 |
| | $ | 802 |
| | $ | — |
| | $ | 1,662 |
|
See Notes to Consolidated Financial Statements
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements
For the Years Ended December 31, 2017, 2016 and 2015
Index to Combined Notes To Consolidated Financial Statements
The notes to the consolidated financial statements are a combined presentation. The following table indicates the registrants to which the notes apply. |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Applicable Notes |
| Registrant | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | 21 | 22 | 23 | 24 | 25 |
| Duke Energy Corporation | • | • | • | • | • | • | • | • | • | • | • | • | | • | • | • | • | • | • | • | • | • | • | • | • |
| Duke Energy Carolinas, LLC | • | | • | • | • | • | | • | • | • | • | | • | • | • | • | • | | • | • | • | • | • | • | • |
| Progress Energy, Inc. | • | | • | • | • | • | • | | • | • | • | | • | • | • | • | • | | • | • | • | • | • | • | • |
| Duke Energy Progress, LLC | • | | • | • | • | • | | | • | • | • | | • | • | • | • | • | | • | • | • | • | • | • | • |
| Duke Energy Florida, LLC | • | | • | • | • | • | | | • | • | • | | • | • | • | • | • | | • | • | • | • | • | • | • |
| Duke Energy Ohio, Inc. | • | • | • | • | • | • | | • | • | • | • | | • | • | | • | • | | • | • | • | • | • | • | • |
| Duke Energy Indiana, LLC | • | | • | • | • | • | | • | • | • | • | | • | • | • | • | • | | • | • | • | • | • | • | • |
| Piedmont Natural Gas Company, Inc. | • | • | • | • | • | • | | | • | • | • | • | • | • | • | • | • | | • | • | • | • | • | • | • |
Tables within the notes may not sum across due to (i) Progress Energy's consolidation of Duke Energy Progress, Duke Energy Florida and other subsidiaries that are not registrants and (ii) subsidiaries that are not registrants but included in the consolidated Duke Energy balances.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Basis of Consolidation
Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is an energy company headquartered in Charlotte, North Carolina, subject to regulation by the Federal Energy Regulatory Commission (FERC). Duke Energy operates in the United States (U.S.) primarily through its direct and indirect subsidiaries. Certain Duke Energy subsidiaries are also subsidiary registrants, including Duke Energy Carolinas, LLC (Duke Energy Carolinas); Progress Energy, Inc. (Progress Energy); Duke Energy Progress, LLC (Duke Energy Progress); Duke Energy Florida, LLC (Duke Energy Florida); Duke Energy Ohio, Inc. (Duke Energy Ohio); Duke Energy Indiana, LLC (Duke Energy Indiana) and Piedmont Natural Gas Company, Inc. (Piedmont). When discussing Duke Energy’s consolidated financial information, it necessarily includes the results of its seven separate subsidiary registrants (collectively referred to as the Subsidiary Registrants), which along with Duke Energy, are collectively referred to as the Duke Energy Registrants.
In October 2016, Duke Energy completed the acquisition of Piedmont. Duke Energy's consolidated financial statements include Piedmont's results of operations and cash flows activity subsequent to the acquisition date. Effective November 1, 2016, Piedmont's fiscal year-end was changed from October 31 to December 31, the year-end of Duke Energy. A transition report was filed on Form 10-Q (Form 10-QT) as of December 31, 2016, for the transition period from November 1, 2016, to December 31, 2016. See Note 2 for additional information regarding the acquisition.
In December 2016, Duke Energy completed an exit of the Latin American market to focus on its domestic regulated business, which was further bolstered by the acquisition of Piedmont. The sale of the International Energy business segment, excluding an equity method investment in National Methanol Company (NMC), was completed through two transactions including a sale of assets in Brazil to China Three Gorges (Luxembourg) Energy S.à.r.l. (CTG) and a sale of Duke Energy's remaining Latin American assets in Peru, Chile, Ecuador, Guatemala, El Salvador and Argentina to ISQ Enerlam Aggregator, L.P. and Enerlam (UK) Holding Ltd. (I Squared) (collectively, the International Disposal Group). See Note 2 for additional information on the sale of International Energy.
The information in these combined notes relates to each of the Duke Energy Registrants as noted in the Index to Combined Notes to Consolidated Financial Statements. However, none of the Subsidiary Registrants make any representation as to information related solely to Duke Energy or the Subsidiary Registrants of Duke Energy other than itself.
These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of the Duke Energy Registrants and subsidiaries where the respective Duke Energy Registrants have control. These Consolidated Financial Statements also reflect the Duke Energy Registrants’ proportionate share of certain jointly owned generation and transmission facilities. Substantially all of the Subsidiary Registrants' operations qualify for regulatory accounting.
Duke Energy Carolinas is ana regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Carolinas is subject to the regulatory provisions of the North Carolina Utilities Commission (NCUC), Public Service Commission of South Carolina (PSCSC), U.S. Nuclear Regulatory Commission (NRC) and FERC.
Progress Energy is a public utility holding company headquartered in Raleigh, North Carolina, subject to regulation by FERC. Progress Energy conducts operations through its wholly owned subsidiaries, Duke Energy Progress and Duke Energy Florida.
Duke Energy Progress is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Duke Energy Progress is subject to the regulatory provisions of the NCUC, PSCSC, NRC and FERC.
Duke Energy Florida is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. Duke Energy Florida is subject to the regulatory provisions of the Florida Public Service Commission (FPSC), NRC and FERC.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy Ohio is a regulated public utility primarily engaged in the transmission and distribution of electricity in portions of Ohio and Kentucky, the generation and sale of electricity in portions of Kentucky and the transportation and sale of natural gas in portions of Ohio and Kentucky. Duke Energy Ohio conducts competitive auctions for retail electricity supply in Ohio whereby the energy services companyprice is recovered from retail customers and recorded in Operating Revenues on the Consolidated Statements of Operations and Comprehensive Income. Operations in Kentucky are conducted through its wholly owned subsidiary, Duke Energy Kentucky, Inc. (Duke Energy Kentucky). References herein to Duke Energy Ohio collectively include Duke Energy Ohio and its subsidiaries, unless otherwise noted. Duke Energy Ohio is subject to the regulatory provisions of the Public Utilities Commission of Ohio (PUCO), Kentucky Public Service Commission (KPSC) and FERC. On April 2, 2015, Duke Energy completed the sale of its nonregulated Midwest generation business, which sold power into wholesale energy markets, to a subsidiary of Dynegy Inc. (Dynegy). For further information about the sale of the Midwest Generation business, refer to Note 2. Substantially all of Duke Energy Ohio's operations that remain after the sale qualify for regulatory accounting.
Duke Energy Indiana is a regulated public utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Indiana. Duke Energy Indiana is subject to the regulatory provisions of the Indiana Utility Regulatory Commission (IURC) and FERC.
Piedmont is a regulated public utility primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2is subject to the consolidated financial statements.regulatory provisions of the NCUC, PSCSC, Tennessee Public Utility Commission (TPUC) and FERC.
Certain prior year amounts have been reclassified to conform to the current year presentation.
Other Current Assets and Liabilities
The consolidated financial statements reflectfollowing table provides a description of amounts included in Other within Current Assets or Current Liabilities that exceed 5 percent of total Current Assets or Current Liabilities on the accounts of Piedmont and its wholly-owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in theDuke Energy Registrants' Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in eacheither December 31, 2017, or 2016. |
| | | | | | | | | |
| | | | December 31, |
| (in millions) | Location | | 2017 |
| | 2016 |
|
| Duke Energy | | | | | |
| Accrued compensation | Current Liabilities | | $ | 757 |
| | $ | 765 |
|
| Duke Energy Carolinas | | | | | |
| Accrued compensation | Current Liabilities | | $ | 252 |
| | $ | 248 |
|
| Customer deposits | Current Liabilities | | 121 |
| | 155 |
|
| Progress Energy | | | |
| | |
|
| Income taxes receivable | Current Assets | | $ | 278 |
| | $ | 19 |
|
| Customer deposits | Current Liabilities | | 338 |
| | 363 |
|
| Duke Energy Progress | | | |
| | |
|
| Customer deposits | Current Liabilities | | $ | 129 |
| | $ | 141 |
|
| Accrued compensation | Current Liabilities | | 132 |
| | 135 |
|
| Duke Energy Florida | | | |
| | |
|
| Customer deposits | Current Liabilities | | $ | 208 |
| | $ | 222 |
|
| Duke Energy Ohio | | | |
| | |
|
| Income taxes receivable | Current Assets | | $ | 36 |
| | $ | 16 |
|
| Customer deposits | Current Liabilities | | 46 |
| | 62 |
|
| Duke Energy Indiana | | | |
| | |
|
| Customer deposits | Current Liabilities | | $ | 45 |
| | $ | 44 |
|
| Piedmont | | | | | |
| Income taxes receivable | Current Assets | | $ | 43 |
| | $ | 9 |
|
Discontinued Operations
The results of operations of the joint ventures less any distributions received from the joint venture,International Disposal Group as well as Duke Energy Ohio's nonregulated Midwest Generation business and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in theDuke Energy Retail Sales, LLC (collectively, Midwest Generation Disposal Group) have been classified as Discontinued Operations on Duke Energy's Consolidated Statements of Comprehensive Income. Revenues and expensesOperations. Duke Energy has elected to present cash flows of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” indiscontinued operations combined with cash flows of continuing operations. Unless otherwise noted, the Consolidated Statements of Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on salesnotes to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For further information on equity method investments and related party transactions, see Note 12 to thethese consolidated financial statements.statements exclude amounts related to discontinued operations for all periods presented. See Note 2 for additional information.
We monitor significant events occurring after129
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Attributable to Controlling Interests
For the balance sheet dateyear ended December 31, 2017, the Loss From Discontinued Operations, net of tax on Duke Energy's Consolidated Statement of Operations is entirely attributable to controlling interest. The following table presents Net Income Attributable to Duke Energy Corporation for continuing operations and prior todiscontinued operations for the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.years ended December 31, 2016, and 2015. |
| | | | | | |
| | Year ended December 31, |
| (in millions) | 2016 | 2015 |
| Income from Continuing Operations | $ | 2,578 |
| $ | 2,654 |
|
| Income from Continuing Operations Attributable to Noncontrolling Interests | 7 |
| 9 |
|
| Income from Continuing Operations Attributable to Duke Energy Corporation | $ | 2,571 |
| $ | 2,645 |
|
| (Loss) Income From Discontinued Operations, net of tax | $ | (408 | ) | $ | 177 |
|
| Income from Discontinued Operations Attributable to Noncontrolling Interests, net of tax | 11 |
| 6 |
|
| (Loss) Income From Discontinued Operations Attributable to Duke Energy Corporation, net of tax | $ | (419 | ) | $ | 171 |
|
| Net Income | $ | 2,170 |
| $ | 2,831 |
|
| Net Income Attributable to Noncontrolling Interests | 18 |
| 15 |
|
| Net Income Attributable to Duke Energy Corporation | $ | 2,152 |
| $ | 2,816 |
|
Significant Accounting Policies
Use of Estimates
The consolidatedIn preparing financial statements of Piedmont have been prepared in conformity withthat conform to generally accepted accounting principles (GAAP) in the United States of America (GAAP) and underU.S., the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, weDuke Energy Registrants must make certain estimates and assumptions regarding reported amounts of assets, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities, as of the date of the consolidated financial statements and the reported amounts of revenues and expenses duringand the reporting period.disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.those estimates.
Regulatory Accounting
Segment Reporting
Our segments are based on the componentsThe majority of the Company for which we produce separate financial information internally that is used regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance (O&M) expenses and operating income. We evaluate the performance of the regulated non-utility activities segment and the unregulated non-utility activities segment based on earnings from and our cash flows in the ventures.
Beginning with the fourth quarter of 2014, we have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. The regulated utility segment is the gas distribution business, where
we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the utility. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included. See Note 14 to the consolidated financial statements for further discussion of segments.
Rate-Regulated Basis of Accounting
Our utilityDuke Energy Registrants’ operations are subject to price regulation with respect to rates, service area, accountingfor the sale of electricity and various other mattersnatural gas by state utility commissions or FERC. When prices are set on the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effectbasis of specific costs of the mannerregulated operations and an effective franchise is in which independent third-party regulators establish rates. In applying these regulations, we capitalize certainplace such that sufficient natural gas or electric services can be sold to recover those costs, and benefits asthe Duke Energy Registrants apply regulatory assets and liabilities, respectively, in orderaccounting. Regulatory accounting changes the timing of the recognition of costs or revenues relative to provide for recovery from or refund to utility customers in future periods. Generally,a company that does not apply regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.
Our regulatory assets are recoverable through either base rates or rate riders specifically authorized byaccounting. As a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of theresult, regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI). Our utility operations continue to recover their costs through cost-based rates established byare recognized on the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.
Consolidated Balance Sheets. Regulatory assets and liabilities are amortized consistent with the treatment of the related cost in the Consolidated Balance Sheetsratemaking process. See Note 4 for further information.
Regulatory accounting rules also require recognition of a disallowance (also called "impairment") loss if it becomes probable that part of the cost of a plant under construction (or a recently completed plant or an abandoned plant) will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made. These disallowances can require judgments on allowed future rate recovery.
When it becomes probable that regulated generation, transmission or distribution assets will be abandoned, the cost of the asset is removed from plant in service. The value that may be retained as a regulatory asset on the balance sheet for the abandoned property is dependent upon amounts that may be recovered through regulated rates, including any return. As such, an impairment charge could be partially or fully offset by the establishment of October 31, 2014a regulatory asset if rate recovery is probable. The impairment for a disallowance of costs for regulated plants under construction, recently completed or abandoned is based on discounted cash flows.
Regulated Fuel and 2013 arePurchased Gas Adjustment Clauses
The Duke Energy Registrants utilize cost-tracking mechanisms, commonly referred to as follows.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Regulatory Assets: | | | | |
| Current: | | | | |
| Unamortized debt expense | | $ | 1,490 |
| | $ | 1,274 |
|
| Amounts due from customers | | 16,108 |
| | 66,321 |
|
| Environmental costs | | 1,568 |
| | 1,480 |
|
| Deferred operations and maintenance expenses | | 916 |
| | 739 |
|
| Deferred pipeline integrity expenses | | 3,470 |
| | 3,149 |
|
| Deferred pension and other retirement benefits costs | | 2,769 |
| | 2,768 |
|
| Robeson liquefied natural gas (LNG) development costs | | 917 |
| | 382 |
|
| Other | | 1,850 |
| | 1,091 |
|
| Total current | | 29,088 |
| | 77,204 |
|
| | | | | |
| Noncurrent: | | | | |
| Unamortized debt expense | | 15,402 |
| | 14,149 |
|
| Environmental costs | | 6,470 |
| | 7,936 |
|
| Deferred operations and maintenance expenses | | 4,721 |
| | 5,637 |
|
| Deferred pipeline integrity expenses | | 24,694 |
| | 16,300 |
|
| Deferred pension and other retirement benefits costs | | 18,799 |
| | 17,968 |
|
| Amounts not yet recognized as a component of pension and other retirement benefit costs | | 94,265 |
| | 80,604 |
|
| Regulatory cost of removal asset | | 18,275 |
| | 22,974 |
|
| Robeson LNG development costs | | 509 |
| | 1,426 |
|
| Other | | 1,644 |
| | 2,108 |
|
| Total noncurrent | | 184,779 |
| | 169,102 |
|
| Total | | $ | 213,867 |
| | $ | 246,306 |
|
|
| | | | | | | | |
| Regulatory Liabilities: | | | | |
| Current: | | | | |
| Amounts due to customers | | $ | 46,231 |
| | $ | — |
|
| | | | | |
| Noncurrent: | | | | |
| Regulatory cost of removal obligations | | 506,574 |
| | 493,111 |
|
| Deferred income taxes | | 51,930 |
| | 48,647 |
|
| Amounts not yet recognized as a component of pension and other retirement costs | | 94 |
| | 139 |
|
| Total noncurrent | | 558,598 |
| | 541,897 |
|
| Total | | $ | 604,829 |
| | $ | 541,897 |
|
As of October 31, 2014, we have $18.3 million of asset retirement obligations (AROs) and $98.1 million of other regulatory assets on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension fundingfuel adjustment clauses or purchased gas adjustment clauses (PGA). These clauses allow for our Tennessee jurisdiction. Thethe recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA)fuel and fuel-related costs, portions of purchased power, natural gas costs and hedging costs through surcharges on a deferred cash basis.
Utility Plant and Depreciation
Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, wherecustomer rates. The difference between the costs of homogeneous assets are aggregatedincurred and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property thatsurcharge revenues is recorded either as an adjustment to Operating Revenues, Operating Expenses – Fuel used in “Non-operating income” in “Other Income (Expense)” inelectric generation or Operating Expenses – Cost of natural gas on the Consolidated Statements of Comprehensive Income.
The classification of total utility plant, net, for the years ended October 31, 2014 and 2013 is presented below.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Intangible plant | | $ | 3,374 |
| | $ | 3,374 |
|
| Other storage plant | | 180,058 |
| | 171,349 |
|
| Transmission plant | | 1,787,990 |
| | 1,403,829 |
|
| Distribution plant | | 2,623,560 |
| | 2,505,160 |
|
| General plant | | 421,763 |
| | 335,847 |
|
| Asset retirement cost | | 11 |
| | 7,565 |
|
| Contributions in aid of construction | | (5,259 | ) | | (5,187 | ) |
| Total utility plant in service | | 5,011,497 |
| | 4,421,937 |
|
| Less accumulated depreciation | | (1,166,922 | ) | | (1,088,331 | ) |
| Total utility plant in service, net | | 3,844,575 |
| | 3,333,606 |
|
| Construction work in progress | | 141,693 |
| | 297,717 |
|
| Plant held for future use | | 3,155 |
| | 3,155 |
|
| Total utility plant, net | | $ | 3,989,423 |
| | $ | 3,634,478 |
|
Contributions in aid of construction represent nonrefundable donationsOperations, with an off-setting impact on regulatory assets or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.liabilities.
AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2014, 2013 and 2012, all of our AFUDC was attributable to borrowed funds.
AFUDC for the years ended October 31, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 |
| 2013 |
| 2012 |
| AFUDC |
| $ | 16,427 |
|
| $ | 30,975 |
|
| $ | 25,211 |
|
In accordance with utility accounting practice, we classified real estate and development costs associated with a LNG peak storage facility in the eastern part of North Carolina as “Plant held for future use” in the Consolidated Balance Sheets, due to construction being suspended in March 2009. As of 2012, approximately $3.2 million of the “Plant held for future use” related to land costs and approximately $3.5 million related to non-real estate costs. In May 2013, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting rate recovery of the non-real estate costs. Under the settlement of the 2013 North Carolina general rate proceeding approved by the NCUC in December 2013, we agreed to the amortization and collection of $1.2 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 38 months beginning January 1, 2014 through February 2017. Under the settlement of our June 2014 rate stabilization adjustment (RSA) filing with the Public Service Commission of South Carolina (PSCSC) that was approved in October 2014, we agreed to the amortization and collection of $.5 million of non-real estate costs that is recorded as a regulatory asset to be amortized over 12 months beginning November 1, 2014. We recorded cumulative amortization of $1.8 million of non-real
estate costs in fiscal year 2013 that is included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Non-operating expense.” For further information on the 2013 general rate proceeding settlement of these costs for North Carolina or the 2014 RSA filing for South Carolina, see Note 2 to the consolidated financial statements.
We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted-average depreciation rates were 2.54% for 2014, 2.77% for 2013 and 2.94% for 2012.
Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina, March 1, 2012 for Tennessee and January 1, 2014 for North Carolina.
As authorized by our regulatory commissions, the estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we collect and record estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate. Because the estimated removal costs are a non-legal obligation, we account for them as a regulatory liability and present the accumulated removal costs in “Regulatory Liabilities” in “Rate-Regulated Basis of Accounting” in this Note 1. For further discussion of this regulatory liability, see “Asset Retirement Obligations” in this Note 1.
Cash and Cash Equivalents
We consider instruments purchasedAll highly liquid investments with an original maturity at date of purchasematurities of three months or less at the date of acquisition are considered cash equivalents.
Restricted Cash
The Duke Energy Registrants have restricted cash related primarily to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on ourcollateral assets, escrow deposits and variable interest entities (VIEs). Restricted cash balances that would impact the payment of dividends as of October 31, 2014are reflected in Other within Current Assets and 2013.
Trade Accounts Receivable and Allowance for Doubtful Accounts
Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment duein Other within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, basedOther Noncurrent Assets on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the PSCSC and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets. At December 31, 2017, and 2016, Duke Energy had restricted cash totaling $147 million and $137 million, respectively.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Inventory
Inventory is used for operations and is recorded primarily using the average cost method. Inventory related to credit risk when we enter into contracts with third partiesregulated operations is valued at historical cost. Inventory related to buy and sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our policy requires counterparties to have an investment-grade credit ratingnonregulated operations is valued at the timelower of the contract. In situations where counterparties do not have investment gradecost or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of creditmarket. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or parental guaranties. In either circumstance, the policy specifies limits on the contract amountcapitalized to property, plant and duration based on the counterparty’s credit rating and/equipment when installed. Inventory, including excess or credit support. In order to minimize our exposure, we continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.
Our principal business activityobsolete inventory, is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2014 and 2013, our trade accounts receivable consisted of the following.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Gas receivables | | $ | 64,400 |
| | $ | 78,540 |
|
| Non-regulated merchandise and service work receivables | | 3,012 |
| | 2,274 |
|
| Allowance for doubtful accounts | | (2,152 | ) | | (1,604 | ) |
| Trade accounts receivable | | $ | 65,260 |
| | $ | 79,210 |
|
A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Balance at beginning of year | | $ | 1,604 |
| | $ | 1,579 |
| | $ | 1,347 |
|
| Additions charged to uncollectibles expense | | 6,959 |
| | 5,314 |
| | 4,584 |
|
| Accounts written off, net of recoveries | | (6,411 | ) | | (5,289 | ) | | (4,352 | ) |
| Balance at end of year | | $ | 2,152 |
| | $ | 1,604 |
| | $ | 1,579 |
|
Inventories
We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.
We enter into service contracts, or asset management arrangements (AMAs), with counterparties to efficiently manage portions of our gas supply, transportation capacity and storage capacity to serve our customers. These AMAs are structured in compliance with Federal Energy Regulatory Commission (FERC) Order 712. Generally, under an AMA, we receive a fixed monthly payment which is set at inception of the arrangement, and in return, we may assign the gas supply and/or storage inventory and release the transportation capacity and storage capacitywritten-down to the asset managerlower of cost or market value. Once inventory has been written-down, it creates a new cost basis for the term of the agreement. The inventory is assigned at no cost, and the same quantities are required to be returned at the expiration of the agreements. One agreement allows us to call on inventory during the summer months to satisfy operational requirements, if needed. The inventory that is assigned to the asset manager is available for our use during the winter heating season, November through March. We account for these amounts on the Consolidated Balance Sheets as a current asset in the inventories section as “Gas in storage.” From the period of April through October, the inventory that is not availablesubsequently written-up. Provisions for our use is reclassified on the Consolidated Balance Sheets as a current asset in “Prepayments,”inventory write-offs were not material at December 31, 2017, and the2016. The components of inventory that is available for our use remains in “Gas in storage.”
At October 31, 2014 and 2013, such counterparties held natural gas storage assets as recorded in “Prepayments,” with a value of $35 million and $31.5 million, respectively, through such asset management relationships. Under the terms of the agreements, we receive asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The AMAs expire at various times through March 31, 2017. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.
Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.
Fair Value Measurements
We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair valuepresented in the
Consolidated Balance Sheets are cashtables below. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Materials and supplies | $ | 2,293 |
| | $ | 744 |
| | $ | 1,118 |
| | $ | 774 |
| | $ | 343 |
| | $ | 82 |
| | $ | 309 |
| | $ | 2 |
|
| Coal | 603 |
| | 192 |
| | 255 |
| | 139 |
| | 116 |
| | 17 |
| | 139 |
| | — |
|
| Natural gas, oil and other | 354 |
| | 35 |
| | 219 |
| | 104 |
| | 115 |
| | 34 |
| | 2 |
| | 64 |
|
| Total inventory | $ | 3,250 |
| | $ | 971 |
| | $ | 1,592 |
| | $ | 1,017 |
| | $ | 574 |
| | $ | 133 |
| | $ | 450 |
| | $ | 66 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Materials and supplies | $ | 2,374 |
| | $ | 767 |
| | $ | 1,167 |
| | $ | 813 |
| | $ | 354 |
| | $ | 84 |
| | $ | 312 |
| | $ | 1 |
|
| Coal | 774 |
| | 251 |
| | 314 |
| | 148 |
| | 166 |
| | 19 |
| | 190 |
| | — |
|
| Natural gas, oil and other | 374 |
| | 37 |
| | 236 |
| | 115 |
| | 121 |
| | 34 |
| | 2 |
| | 65 |
|
| Total inventory | $ | 3,522 |
| | $ | 1,055 |
| | $ | 1,717 |
| | $ | 1,076 |
| | $ | 641 |
| | $ | 137 |
| | $ | 504 |
| | $ | 66 |
|
Investments in Debt and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plansEquity Securities
The Duke Energy Registrants classify investments into two categories – trading and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety, in the following fair value hierarchy levels as set forth in the fair value guidance.
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.
Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, common trust funds, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.
Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.
In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans’ investments, “near term” is the ability to redeem an investment in no more than 180 days.
Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.
For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.
Goodwill, Equity Method Investments and Long-Lived Assets
Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.
Our annual goodwill impairment assessment was performed as of October 31, 2014, and we determined that there was no impairment to the carrying value of our goodwill. No impairment was recognized during the years ended October 31, 2014, 2013 and 2012. The fair value of our regulated utility reporting unit substantially exceeds the carrying value, including goodwill.
We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. In April 2014, we recorded a $2 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Non-operating expense" in the Consolidated Statements of Comprehensive Income. There were no events or circumstances during the years ended October 31, 2013 and 2012 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.
Marketable Securities
We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.
We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securitiesavailable-for-sale. Both categories are recorded at fair value on the Consolidated Balance Sheets with anySheets. Realized and unrealized gains orand losses recognized currentlyon trading securities are included in earnings. We do not intend to engage in active tradingFor certain investments of regulated operations, such as substantially all of the Nuclear Decommissioning Trust Funds (NDTF), realized and unrealized gains and losses (including any other-than-temporary impairments (OTTIs)) on available-for-sale securities are recorded as a regulatory asset or liability. Otherwise, unrealized gains and losses are included in Accumulated Other Comprehensive Income (AOCI), unless other-than-temporarily impaired. OTTIs for equity securities and participants in the deferred compensation plans may redirect their deemed investments at any time. We have matched the currentcredit loss portion of debt securities of nonregulated operations are included in earnings. Investments in debt and equity securities are classified as either current or noncurrent based on management’s intent and ability to sell these securities, taking into consideration current market liquidity. See Note 15 for further information.
Goodwill and Intangible Assets
Goodwill
Effective with Piedmont's change in fiscal year end to December 31, as discussed above, Piedmont changed the deferred compensation liabilitydate of its annual impairment testing of goodwill from October 31 to August 31 to align with the current assetother Duke Energy Registrants.
Duke Energy, Progress Energy, Duke Energy Ohio and noncurrent deferred compensation liability withPiedmont perform annual goodwill impairment tests as of August 31 each year at the noncurrent asset;reporting unit level, which is determined to be an operating segment or one level below. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update these tests between annual tests if events or circumstances occur that would more likely than not reduce the current portion has beenfair value of a reporting unit below its carrying value.
Intangible Assets
Intangible assets are included in “Other current assets”Other in “Current Assets” inOther Noncurrent Assets on the Consolidated Balance Sheets.
The money market investments Generally, intangible assets are amortized using an amortization method that reflects the pattern in which the trusts approximate fair value due to the short period of time to maturity. The fair valueseconomic benefits of the equity securitiesintangible asset are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2014 and 2013 is as follows.
|
| | | | | | | | | | | | | | | | |
| | | 2014 | | 2013 |
| In thousands | | Cost | | Fair Value | | Cost | | Fair Value |
| Current trading securities: | | | | | | | | |
| Money markets | | $ | 22 |
| | $ | 22 |
| | $ | — |
| | $ | — |
|
| Mutual funds | | 106 |
| | 192 |
| | 134 |
| | 199 |
|
| Total current trading securities | | 128 |
| | 214 |
| | 134 |
| | 199 |
|
| Noncurrent trading securities: | | | | | | | | |
| Money markets | | 447 |
| | 447 |
| | 380 |
| | 380 |
|
| Mutual funds | | 2,598 |
| | 3,280 |
| | 1,995 |
| | 2,615 |
|
| Total noncurrent trading securities | | 3,045 |
| | 3,727 |
| | 2,375 |
| | 2,995 |
|
| Total trading securities | | $ | 3,173 |
| | $ | 3,941 |
| | $ | 2,509 |
| | $ | 3,194 |
|
Unamortized Debt Expense
Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expenseconsumed or on a straight-line basis which approximates the effective interest method, over the life of the related debt with lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is five years.
Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debtif that pattern is not simultaneous, we defer the gain or loss resulting from the reacquisitionreadily determinable. Amortization of the debtintangibles is reflected in Depreciation and amortize it over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.
Issuances and Repurchases of Common Stock
As discussed in Note 6 to the consolidated financial statements, from time to time we may repurchase sharesamortization on the open market and such shares are then canceled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders’ Equity. Shares withheldOperations. Intangible assets are subject to impairment testing and if impaired, the carrying value is accordingly reduced.
Emission allowances permit the holder of the allowance to emit certain gaseous byproducts of fossil fuel combustion, including sulfur dioxide (SO2) and nitrogen oxide (NOX). Allowances are issued by usthe U.S. Environmental Protection Agency (EPA) at zero cost and may also be bought and sold via third-party transactions. Allowances allocated to satisfy tax withholding obligations relatedor acquired by the Duke Energy Registrants are held primarily for consumption. Carrying amounts for emission allowances are based on the cost to acquire the allowances or, in the case of a business combination, on the fair value assigned in the allocation of the purchase price of the acquired business. Emission allowances are expensed to Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Renewable energy certificates are used to measure compliance with renewable energy standards and are held primarily for consumption. See Note 11 for further information.
Long-Lived Asset Impairments
The Duke Energy Registrants evaluate long-lived assets, excluding goodwill, for impairment when circumstances indicate the carrying value of those assets may not be recoverable. An impairment exists when a long-lived asset’s carrying value exceeds the estimated undiscounted cash flows expected to result from the use and eventual disposition of the asset. The estimated cash flows may be based on alternative expected outcomes that are probability weighted. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the carrying value of the asset is written-down to its then-current estimated fair value and an impairment charge is recognized.
The Duke Energy Registrants assess fair value of long-lived assets using various methods, including recent comparable third-party sales, internally developed discounted cash flow analysis and analysis from outside advisors. Triggering events to reassess cash flows may include, but are not limited to, significant changes in commodity prices, the condition of an asset or management’s interest in selling the asset.
Property, Plant and Equipment
Property, plant and equipment are stated at the lower of depreciated historical cost net of any disallowances or fair value, if impaired. The Duke Energy Registrants capitalize all construction-related direct labor and material costs, as well as indirect construction costs such as general engineering, taxes and financing costs. See “Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized” for information on capitalized financing costs. Costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of the asset, are expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the composite straight-line method. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. The composite weighted average depreciation rates, excluding nuclear fuel, are included in the table that follows. |
| | | | | | | | |
| | Years Ended December 31, |
| | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | 2.8 | % | | 2.8 | % | | 2.9 | % |
| Duke Energy Carolinas | 2.8 | % | | 2.8 | % | | 2.8 | % |
| Progress Energy | 2.6 | % | | 2.7 | % | | 2.6 | % |
| Duke Energy Progress | 2.6 | % | | 2.6 | % | | 2.6 | % |
| Duke Energy Florida | 2.8 | % | | 2.8 | % | | 2.7 | % |
| Duke Energy Ohio | 2.8 | % | | 2.6 | % | | 2.7 | % |
| Duke Energy Indiana | 3.0 | % | | 3.1 | % | | 3.0 | % |
Piedmont(a) | 2.3 | % | | | | |
| |
| (a) | Piedmont's weighted average depreciation rate was 2.4 percent, 2.4 percent, and 2.5 percent for the annualized two months ended December 31, 2016 and for the years ended October 31, 2016 and 2015, respectively. |
In general, when the Duke Energy Registrants retire regulated property, plant and equipment, the original cost plus the cost of retirement, less salvage value, is charged to accumulated depreciation. However, when it becomes probable the asset will be retired substantially in advance of its original expected useful life or is abandoned, the cost of the asset and the corresponding accumulated depreciation is recognized as a separate asset. If the asset is still in operation, the net amount is classified as Generation facilities to be retired, net on the Consolidated Balance Sheets. If the asset is no longer operating, the net amount is classified in Regulatory assets on the Consolidated Balance Sheets if deemed recoverable (see discussion of long-lived asset impairments above). When it becomes probable an asset will be abandoned, the cost of the asset and accumulated depreciation is reclassified to Regulatory assets on the Consolidated Balance Sheets for amounts recoverable in rates. The carrying value of the asset is based on historical cost if the Duke Energy Registrants are allowed to recover the remaining net book value and a return equal to at least the incremental borrowing rate. If not, an impairment is recognized to the vestingextent the net book value of shares awarded under the Incentive Compensation Plan have been immaterialasset exceeds the present value of future revenues discounted at the incremental borrowing rate.
When the Duke Energy Registrants sell entire regulated operating units, or retire or sell nonregulated properties, the original cost and accumulated depreciation and amortization balances are removed from Property, Plant and Equipment on the Consolidated Balance Sheets. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
See Note 10 for further information.
Nuclear Fuel
Nuclear fuel is classified as Property, Plant and Equipment on the Consolidated Balance Sheets, except for Duke Energy Florida. Nuclear fuel amounts at Duke Energy Florida were reclassified to date.Regulatory assets pursuant to the Revised and Restated Stipulation and Settlement Agreement approved in November 2013 among Duke Energy Florida, the Florida Office of Public Counsel (Florida OPC) and other customer advocates (the 2013 Settlement).
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Nuclear fuel in the front-end fuel processing phase is considered work in progress and not amortized until placed in service. Amortization of nuclear fuel is included within Fuel used in electric generation and purchased power on the Consolidated Statements of Operations. Amortization is recorded using the units-of-production method.
Allowance for Funds Used During Construction and Interest Capitalized
For regulated operations, the debt and equity costs of financing the construction of property, plant and equipment are reflected as AFUDC and capitalized as a component of the cost of property, plant and equipment. AFUDC equity is reported on the Consolidated Statements of Operations as non-cash income in Other income and expenses, net. AFUDC debt is reported as a non-cash offset to Interest Expense. After construction is completed, the Duke Energy Registrants are permitted to recover these costs through their inclusion in rate base and the corresponding subsequent depreciation or amortization of those regulated assets.
AFUDC equity, a permanent difference for income taxes, reduces the effective tax rate (ETR) when capitalized and increases the ETR when depreciated or amortized. See Note 22 for additional information.
For nonregulated operations, interest is capitalized during the construction phase with an offsetting non-cash credit to Interest Expense on the Consolidated Statements of Operations.
Asset Retirement Obligations
The accounting guidanceAsset retirement obligations (AROs) are recognized for AROs addresses the financial accounting and reporting for AROslegal obligations associated with the retirement of long-lived assets that result fromproperty, plant and equipment. Substantially all AROs are related to regulated operations. When recording an ARO, the acquisition, construction, development and operationpresent value of the assets. The accounting guidance requires the recognition of the fair value of aprojected liability for AROsis recognized in the period in which the liabilityit is incurred, if a reasonable estimate of fair value can be made. We haveThe liability is accreted over time. For operating plants, the present value of the liability is added to the cost of the associated asset and depreciated over the remaining life of the asset. For retired plants, the present value of the liability is recorded as a regulatory asset unless determined not to be recoverable.
The present value of the initial obligation and subsequent updates are based on discounted cash flows, which include estimates regarding timing of future cash flows, selection of discount rates and cost escalation rates, among other factors. These estimates are subject to change. Depreciation expense is adjusted prospectively for any changes to the carrying amount of the associated asset. The Duke Energy Registrants receive amounts to fund the cost of the ARO for regulated operations through a combination of regulated revenues and earnings on the NDTF. As a result, amounts recovered in regulated revenues, earnings on the NDTF, accretion expense and depreciation of the associated asset are netted and deferred as a regulatory asset or liability.
Obligations for nuclear decommissioning are based on site-specific cost studies. Duke Energy Carolinas and Duke Energy Progress assume prompt dismantlement of the nuclear facilities after operations are ceased. Duke Energy Florida assumes Crystal River Unit 3 Nuclear Plant (Crystal River Unit 3) will be placed into a safe storage configuration until eventual dismantlement is completed by 2074. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida also assume that conditional AROs existspent fuel will be stored on-site until such time that it can be transferred to a yet to be built U.S. Department of Energy (DOE) facility.
Obligations for our underground mainsclosure of ash basins are based upon discounted cash flows of estimated costs for site-specific plans, if known, or probability weightings of the potential closure methods if the closure plans are under development and services.multiple closure options are being considered and evaluated on a site-by-site basis. See Note 9 for additional information.
Revenue Recognition and Unbilled Revenue
Revenues on sales of electricity and natural gas are recognized when service is provided or the product is delivered. Unbilled revenues are recognized by applying customer billing rates to the estimated volumes of energy or natural gas delivered but not yet billed. Unbilled revenues can vary significantly from period to period as a result of seasonality, weather, customer usage patterns, customer mix, average price in effect for customer classes, timing of rendering customer bills and meter reading schedules, and the impact of weather normalization or margin decoupling mechanisms.
Unbilled revenues are included within Receivables and Receivables of VIEs on the Consolidated Balance Sheets as shown in the following table. |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| Duke Energy | $ | 944 |
| | $ | 831 |
|
| Duke Energy Carolinas | 342 |
| | 313 |
|
| Progress Energy | 228 |
| | 161 |
|
| Duke Energy Progress | 143 |
| | 102 |
|
| Duke Energy Florida | 85 |
| | 59 |
|
| Duke Energy Ohio | 4 |
| | 2 |
|
| Duke Energy Indiana | 21 |
| | 32 |
|
| Piedmont | 86 |
| | 77 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Additionally, Duke Energy Ohio and Duke Energy Indiana sell, on a revolving basis, nearly all of removal thattheir retail accounts receivable, including receivables for unbilled revenues, to an affiliate, Cinergy Receivables Company LLC (CRC) and account for the transfers of receivables as sales. Accordingly, the receivables sold are non-legal obligations as defined bynot reflected on the accounting guidance. The costsConsolidated Balance Sheets of removalDuke Energy Ohio and Duke Energy Indiana. See Note 17 for further information. These receivables for unbilled revenues are a component of our depreciation ratesshown in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accountedtable below. |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| Duke Energy Ohio | $ | 104 |
| | $ | 97 |
|
| Duke Energy Indiana | 132 |
| | 123 |
|
Allowance for these non-legal AROs in “Regulatory Liabilities” asDoubtful Accounts
Allowances for doubtful accounts are presented in “Rate-Regulated Basisthe following table. |
| | | | | | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Allowance for Doubtful Accounts | | | | | |
| Duke Energy | $ | 14 |
| | $ | 14 |
| | $ | 12 |
|
| Duke Energy Carolinas | 2 |
| | 2 |
| | 3 |
|
| Progress Energy | 4 |
| | 6 |
| | 6 |
|
| Duke Energy Progress | 1 |
| | 4 |
| | 4 |
|
| Duke Energy Florida | 3 |
| | 2 |
| | 2 |
|
| Duke Energy Ohio | 3 |
| | 2 |
| | 2 |
|
| Duke Energy Indiana | 2 |
| | 1 |
| | 1 |
|
Piedmont(a) | 2 |
| | 3 |
| | |
Allowance for Doubtful Accounts – VIEs | | | | | |
| Duke Energy | $ | 54 |
| | $ | 54 |
| | $ | 53 |
|
| Duke Energy Carolinas | 7 |
| | 7 |
| | 7 |
|
| Progress Energy | 7 |
| | 7 |
| | 8 |
|
| Duke Energy Progress | 5 |
| | 5 |
| | 5 |
|
| Duke Energy Florida | 2 |
| | 2 |
| | 3 |
|
(a) Piedmont's allowance for doubtful accounts was $2 million as of Accounting”October 31, 2016, and 2015.
Derivatives and Hedging
Derivative and non-derivative instruments may be used in this Note 1. Inconnection with commodity price and interest rate activities, including swaps, futures, forwards and options. All derivative instruments, except those that qualify for the rate setting process,normal purchase/normal sale (NPNS) exception, are recorded on the liability for non-legal costsConsolidated Balance Sheets at fair value. Qualifying derivative instruments may be designated as either cash flow hedges or fair value hedges. Other derivative instruments (undesignated contracts) either have not been designated or do not qualify as hedges. The effective portion of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return. For further discussion of these costs of removal as a component of depreciation, see “Utility Plant and Depreciation”change in this Note 1.
We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred ifcash flow hedges is recorded in AOCI. The effective portion of the liability can be reasonably estimated. The NCUC,change in the PSCSCfair value of a fair value hedge is offset in net income by changes in the hedged item. For activity subject to regulatory accounting, gains and the TRA have approved placing these ARO costslosses on derivative contracts are reflected as regulatory assets or liabilities and not as other comprehensive income or current period income. As a result, changes in deferred accounts to preserve the regulatory treatmentfair value of these costs; therefore, accretionderivatives have no immediate earnings impact.
Formal documentation, including transaction type and risk management strategy, is maintained for all contracts accounted for as a hedge. At inception and at least every three months thereafter, the hedge contract is assessed to see if it is highly effective in offsetting changes in cash flows or fair values of hedged items.
See Note 14 for further information.
Captive Insurance Reserves
Duke Energy has captive insurance subsidiaries that provide coverage, on an indemnity basis, to the Subsidiary Registrants as well as certain third parties, on a limited basis, for financial losses, primarily related to property, workers’ compensation and general liability. Liabilities include provisions for estimated losses incurred but not reflectedyet reported (IBNR), as well as estimated provisions for known claims. IBNR reserve estimates are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from experience.
Duke Energy, through its captive insurance entities, also has reinsurance coverage with third parties for certain losses above a per occurrence and/or aggregate retention. Receivables for reinsurance coverage are recognized when realization is deemed probable.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Unamortized Debt Premium, Discount and Expense
Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the term of the debt issue. The gain or loss on extinguishment associated with refinancing higher-cost debt obligations in the regulated operations is amortized. Amortization expense is recorded as Interest Expense in the Consolidated Statements of Comprehensive IncomeOperations and is reflected as Depreciation, amortization and accretion within Net cash provided by operating activities on the regulatory treatment provides for deferralConsolidated Statements of Cash Flows.
Premiums, discounts and expenses are presented as an adjustment to the carrying value of the accretion asdebt amount and included in Long-Term Debt on the Consolidated Balance Sheets presented.
Loss Contingencies and Environmental Liabilities
Contingent losses are recorded when it is probable a regulatory asset withloss has occurred and can be reasonably estimated. When a corresponding deferralrange of the accretionprobable loss exists and no amount within the range is a better estimate than any other amount, the minimum amount in the range is recorded. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Environmental liabilities are recorded on an undiscounted basis when environmental remediation or other liabilities become probable and can be reasonably estimated. Environmental expenditures related to past operations that do not generate current or future revenues are expensed. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Certain environmental expenditures receive regulatory accounting treatment and are recorded as regulatory assets.
See Notes 4 and 5 for further information.
Pension and Other Post-Retirement Benefit Plans
Duke Energy maintains qualified, non-qualified and other post-retirement benefit plans. Eligible employees of the Subsidiary Registrants participate in the respective qualified, non-qualified and other post-retirement benefit plans and the Subsidiary Registrants are allocated their proportionate share of benefit costs. See Note 21 for further information, including significant accounting policies associated with these plans.
Severance and Special Termination Benefits
Duke Energy has severance plans under which, in general, the longer a regulatory liability. AROs are capitalized concurrently by increasingterminated employee worked prior to termination the carryinggreater the amount of severance benefits. A liability for involuntary severance is recorded once an involuntary severance plan is committed to by management if involuntary severances are probable and can be reasonably estimated. For involuntary severance benefits incremental to its ongoing severance plan benefits, the fair value of the obligation is expensed at the communication date if there are no future service requirements or over the required future service period. From time to time, Duke Energy offers special termination benefits under voluntary severance programs. Special termination benefits are recorded immediately upon employee acceptance absent a significant retention period. Otherwise, the cost is recorded over the remaining service period. Employee acceptance of voluntary severance benefits is determined by management based on the facts and circumstances of the benefits being offered. See Note 19 for further information.
Guarantees
If necessary, liabilities are recognized at the time of issuance or material modification of a guarantee for the estimated fair value of the obligation it assumes. Fair value is estimated using a probability-weighted approach. The obligation is reduced over the term of the guarantee or related asset by the same amountcontract in a systematic and rational method as the regulatory liability. In periodsrisk is reduced. Any additional contingent loss for guarantee contracts subsequent to the initial measurement, any changes in the liability resulting from the passagerecognition of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 4.40% to 5.15% with a weighted average of 5.09% for the twelve months ended October 31, 2014. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. We have recorded a liability on our distributionis accounted for and transmission mainsrecognized at the time a loss is probable and services.can be reasonably estimated. See Note 7 for further information.
Stock-Based Compensation
Stock-based compensation represents costs related to stock-based awards granted to employees and Duke Energy Board of Directors (Board of Directors) members. Duke Energy recognizes stock-based compensation based upon the estimated fair value of awards, net of estimated forfeitures at the date of issuance. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. Compensation cost of removal obligations recorded in the Consolidated Balance Sheetsis recognized as of October 31, 2014 and 2013 are presented below.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Regulatory non-legal AROs | | $ | 506,574 |
| | $ | 493,111 |
|
| Conditional AROs | | 14,647 |
| | 27,016 |
|
| Total cost of removal obligations | | $ | 521,221 |
| | $ | 520,127 |
|
A reconciliation of the changes in conditional AROs for the year ended October 31, 2014 and 2013 is presented below.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Beginning of period | | $ | 27,016 |
| | $ | 28,629 |
|
| Liabilities incurred during the period | | 2,108 |
| | 2,052 |
|
| Liabilities settled during the period | | (3,576 | ) | | (2,389 | ) |
| Accretion | | 1,548 |
| | 1,641 |
|
| Adjustment to estimated cash flows | | (12,449 | ) | | (2,917 | ) |
| End of period | | $ | 14,647 |
| | $ | 27,016 |
|
Revenue Recognition
We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gasexpense or capitalized as a component of rates may be adjusted periodically under PGA provisions. In North Carolina,property, plant and equipment. See Note 20 for further information.
Income Taxes
Duke Energy and its subsidiaries file a margin decoupling mechanism providesconsolidated federal income tax return and other state and foreign jurisdictional returns. The Subsidiary Registrants are parties to a tax-sharing agreement with Duke Energy. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. Deferred income taxes have been provided for temporary differences between GAAP and tax bases of assets and liabilities because the recovery of our approved margin from residential and commercial customers on an annual basis independent of weather and consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margindifferences create taxable or to recover any under-collection of margin. In South Carolina, a RSA tariff mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March, and in Tennessee, the months of April and October. The WNA mechanisms are designed to partially offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from those used to establish the WNA factors. In all states, the gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanism.
We have integrity management riders (IMRs) in our tariffs in North Carolina, effective February 1, 2014, and in Tennessee effective January 1, 2014, related to our ongoing system integrity programs. These IMRs provide for rate adjustments to allow us to recover and earn on those investments without the necessity of filing general rate cases. The North Carolina IMR was approved in December 2013 in the settlement of our 2013 general rate case. Under the North Carolina IMR tariff, we will make annual filings by November 30 of each year for costs closed to plant through October with revised rates effective the following February 1. The Tennessee IMR tariff was approved in December 2013 with the settlement of our August 2013 IMR filing. Under the Tennessee IMR, we will file to adjust rates to be effective each January 1 based on capital expenditures related to mandated safety and integrity programs that were incurred by the previous October 31. For further discussion of the IMRs, see Note 2 to the consolidated financial statements.
Revenues are recognized monthly on the accrual basis, which includes estimatedtax-deductible amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable.
Secondary market revenuesfuture periods. Investment tax credits (ITCs) associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted
in a lump sumregulated operations are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1.
Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized onas a monthly basis based on principal, rate and term.
Cost of Gas and Deferred Purchased Gas Adjustments
We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers, such that no operating margin is recognized related to these costs, are deferred and included in “Amounts due from customers” in “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” as presented in “Rate-Regulated Basis of Accounting” in this Note 1. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.
Taxes
We have two categoriesreduction of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.
Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.
Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the propertyrelated properties.
Accumulated deferred income taxes are valued using the enacted tax rate expected to apply to taxable income in the periods in which the credits relate.deferred tax asset or liability is expected to be settled or realized. In the event of a change in tax rates, deferred tax assets and liabilities are remeasured as of the enactment date of the new rate. To the extent that the change in the value of the deferred tax represents an obligation to customers, the impact of the remeasurement is deferred to a regulatory liability. Remaining impacts are recorded in income from continuing operations. Other impacts of the Tax Act have been recorded on a provisional basis, see Note 22, “Income Taxes,” for additional information. If Duke Energy's estimate of the tax effect of reversing temporary differences is not reflective of actual outcomes, is modified to reflect new developments or interpretations of the tax law, revised to incorporate new accounting principles, or changes in the expected timing or manner of the reversal then Duke Energy's results of operations could be impacted.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Tax-related interest and penalties if any, related to uncertain tax positions as operating expensesare recorded in Interest Expense and Other Income and Expenses, net in the Consolidated Statements of Comprehensive Income. This is consistent withOperations.
See Note 22 for further information.
Accounting for Renewable Energy Tax Credits
When Duke Energy receives ITCs on wind or solar facilities, it reduces the recognitionbasis of these items in prior reporting periods.
Excise taxes, sales taxes and franchises fees separately stated on customer bills arethe property recorded on a net basis as liabilities payablethe Consolidated Balance Sheets by the amount of the ITC and, therefore, the ITC benefit is ultimately recognized in the statement of operations through reduced depreciation expense. Additionally, certain tax credits and government grants result in an initial tax depreciable base in excess of the book carrying value by an amount equal to one half of the applicable jurisdictions. All other taxes other than income taxesITC. Deferred tax benefits are recorded as general taxes. Generala reduction to income tax expense in the period that the basis difference is created.
Excise Taxes
Certain excise taxes consist of propertylevied by state or local governments are required to be paid even if not collected from the customer. These taxes payrollare recognized on a gross basis. Otherwise, the taxes Tennesseeare accounted for net. Excise taxes accounted for on a gross receipt taxes, franchise taxes, tax on company usebasis within both Operating Revenues and Property and other miscellaneous taxes.
taxes in the Consolidated Statements of
Cash FlowsOperations were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | $ | 376 |
| | $ | 362 |
| | $ | 396 |
|
| Duke Energy Carolinas | 36 |
| | 31 |
| | 31 |
|
| Progress Energy | 220 |
| | 213 |
| | 229 |
|
| Duke Energy Progress | 19 |
| | 18 |
| | 16 |
|
| Duke Energy Florida | 201 |
| | 195 |
| | 213 |
|
| Duke Energy Ohio | 98 |
| | 100 |
| | 102 |
|
| Duke Energy Indiana | 20 |
| | 17 |
| | 34 |
|
Piedmont(a) | 2 |
| | | | |
| |
| (a) | Piedmont's excise taxes were immaterial for the two months ended December 31, 2016, and $2 million for the years ended October 31, 2016, and 2015. |
Dividend Restrictions and Unappropriated Retained Earnings
With respectDuke Energy does not have any legal, regulatory or other restrictions on paying common stock dividends to cash overdrafts, book overdrafts are included within operatingshareholders. However, as further described in Note 4, due to conditions established by regulators in conjunction with merger transaction approvals, Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Indiana and Piedmont have restrictions on paying dividends or otherwise advancing funds to Duke Energy. At December 31, 2017, and 2016, an insignificant amount of Duke Energy’s consolidated Retained earnings balance represents undistributed earnings of equity method investments.
New Accounting Standards
The new accounting standards adopted for 2017 and 2016 had no material impact on the presentation or results of operations, cash flows while any bank overdrafts are included with financing cash flows.or financial position of the Duke Energy Registrants. The following accounting standards were adopted by the Duke Energy Registrants during 2017.
Recently Issued Accounting Guidance
Stock-Based Compensation and Income Taxes.In July 2013, thefirst quarter 2017, Duke Energy adopted Financial Accounting Standards Board (FASB) issuedguidance, which revised the accounting for stock-based compensation and the associated income taxes. The adopted guidance changed certain aspects of accounting for stock-based payment awards to employees including the accounting for income taxes and classification on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist.the Consolidated Statements of Cash Flows. The primary impact to Duke Energy as a result of implementing this guidance was a cumulative-effect adjustment to retained earnings for tax benefits not previously recognized and additional income tax expense for the 12 months ended December 31, 2017. See the Duke Energy Consolidated Statements of Changes in Equity for further information.
Goodwill Impairment. In January 2017, the FASB issued inrevised guidance for the subsequent measurement of goodwill. Under the guidance, a company will recognize an effortimpairment to eliminate diversity in practice resultinggoodwill for the amount by which a reporting unit's carrying value exceeds the reporting unit's fair value, not to exceed the amount of goodwill allocated to that reporting unit. Duke Energy early adopted this guidance for the 2017 annual goodwill impairment test.
The following new accounting standards have been issued, but have not yet been adopted by the Duke Energy Registrants, as of December 31, 2017.
Revenue from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013,Contracts with early adoption permitted. The adoption of this disclosure guidance will have no impact on our financial position, results of operations or cash flows.
Customers. In May 2014, the FASB and the International Accounting Standards Board issued convergedrevised accounting guidance on thefor revenue recognition of revenue from contracts with customers. Under the new standard, entities willThe core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods andor services to customers in amountsan amount that reflectreflects the paymentconsideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update also require disclosure requirements will provideof sufficient information aboutto allow users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy has identified material revenue streams, which served as the basis for accounting analysis and documentation of the impact of this guidance on revenue recognition. The accounting analysis included reviewing representative contracts and tariffs for each material revenue stream. Most of Duke Energy’s revenue will be in scope of the new guidance. The majority of our sales, including energy provided to residential customers, are from tariff offerings that provide natural gas or electricity without a defined contractual term ("at-will"). For such arrangements, revenue from contracts with customers will be equivalent to the electricity or natural gas supplied and billed in that period (including estimated billings). As such, there will not be a significant shift in the timing or pattern of revenue recognition for such sales.
Also included in the accounting analysis was the evaluation of certain long-term revenue streams including electric wholesale contracts and renewables power purchase agreements (PPAs). For such arrangements, Duke Energy does not expect material changes to the pattern of revenue recognition on the registrants. In addition, Duke Energy has monitored the activities of the power and utilities industry revenue recognition task force including draft accounting positions released in October 2017 and the impact, if any, on Duke Energy’s specific contracts and conclusions. Potential revisions to processes, policies and controls, primarily related to evaluating supplemental disclosures required as a result of adopting this guidance, will be evaluated and implemented as necessary. Some revenue arrangements, such as alternative revenue programs and certain PPAs accounted for as leases, are excluded from the scope of the new revenue recognition guidance and, therefore, will be accounted for and evaluated for separate presentation and disclosure under other relevant accounting guidance.
Duke Energy intends to use the modified retrospective method of adoption effective January 1, 2018. Under the modified retrospective method of adoption, prior year reported results are not restated and a cumulative-effect adjustment, if applicable, is recorded to retained earnings at January 1, 2018, as if the standard had always been in effect. In addition, disclosures, if applicable, include a comparison to what would have been reported for 2018 under the previous revenue recognition rules to assist financial statement users in understanding how revenue recognition has changed as a result of this standard and to facilitate comparability with prior year reported results, which are not restated under the modified retrospective approach as described above. Duke Energy will utilize certain practical expedients including applying this guidance to open contracts at the date of adoption and recognizing revenues for certain contracts under the invoice practical expedient, which allows revenue recognition to be consistent with invoiced amounts (including estimated billings) provided certain criteria are met, including consideration of whether the invoiced amounts reasonably represent the value provided to customers. While the adoption of this guidance is not expected to have a material impact on either the timing or amount of revenues recognized in Duke Energy's financial statements, Duke Energy anticipates additional disclosures around the nature, amount, timing and uncertainty of our revenues and cash flows arising from contracts with customers. Duke Energy continues to evaluate what information will be most useful for users of the financial statements, including information already provided in disclosures outside of the financial statement footnotes. These additional disclosures are expected to include the disaggregation of revenues by customer class.
Financial Instruments Classification and Measurement. In January 2016, the FASB issued revised accounting guidance for the classification and measurement of financial instruments. Changes in the fair value of all equity securities will be required to be recorded in net income. Current GAAP allows some changes in fair value for available-for-sale equity securities to be recorded in AOCI. Additional disclosures will be required to present separately the financial assets and financial liabilities by measurement category and form of financial asset. An entity's equity investments that are accounted for under the equity method of accounting are not included within the scope of the new guidance.
For Duke Energy, the revised accounting guidance is effective for interim and annual periods beginning afterJanuary 1, 2018, by recording a cumulative effect adjustment to retained earnings as of January 1, 2018. This guidance is expected to have minimal impact on the Duke Energy Registrant's Consolidated Statements of Operations and Comprehensive Income as changes in the fair value of most of the Duke Energy Registrants' available-for-sale equity securities are deferred as regulatory assets or liabilities pursuant to accounting guidance for regulated operations.
Leases. In February 2016, the FASB issued revised accounting guidance for leases. The core principle of this guidance is that a lessee should recognize the assets and liabilities that arise from leases on the balance sheet.
For Duke Energy, this guidance is effective for interim and annual periods beginning January 1, 2019. The guidance is applied using a modified retrospective approach. Upon adoption, Duke Energy expects to elect the practical expedients, which would require no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases. Additionally, we expect to adopt the optional transition practical expedient allowing the entity not to reassess the accounting for land easements that currently exist at the adoption of the lease standard on January 1, 2019. Duke Energy is currently evaluating the financial statement impact of adopting this standard and is continuing to monitor industry implementation issues, including easements, pole attachments and renewable PPAs. Other than an expected increase in assets and liabilities, the ultimate impact of the new standard has not yet been determined. Significant system enhancements, including additional processes and controls, will be required to facilitate the identification, tracking and reporting of potential leases based upon requirements of the new lease standard. Duke Energy has begun the implementation of a third-party software tool to help with the adoption and ongoing accounting under the new standard.
Statement of Cash Flows. In November 2016, the FASB issued revised accounting guidance to reduce diversity in practice for the presentation and classification of restricted cash on the statement of cash flows. Under the updated guidance, restricted cash and restricted cash equivalents will be included within beginning-of-period and end-of-period cash and cash equivalents on the statement of cash flows.
For Duke Energy, this guidance is effective for the interim and annual periods beginning January 1, 2018. The guidance will be applied using a retrospective transition method to each period presented. Upon adoption by Duke Energy, the revised guidance will result in a change to the amount of cash and cash equivalents and restricted cash explained when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. Prior to adoption, the Duke Energy Registrants reflect changes in restricted cash within Cash Flows from Investing Activities and within Cash Flows from Operating Activities on the Consolidated Statement of Cash Flows. As a result of this change, our Cash and cash equivalents balance on the Consolidated Statement of Cash Flows as of December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018.31, 2017 will change by $147 million.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Retirement Benefits. In March 2017, the FASB issued revised accounting utility subgroup has identified five issues (scopeguidance for cost-of-service-tariff sales, contract modifications, variable consideration, multiple element arrangementsthe presentation of net periodic costs related to benefit plans. Current GAAP permits the aggregation of all the components of net periodic costs on the Consolidated Statement of Operations and salesdoes not require the disclosure of real estate) that are not clearthe location of net periodic costs on the Consolidated Statement of Operations. Under the amended guidance, the service cost component of net periodic costs must be included within Operating Income within the standardsame line as other compensation expenses. All other components of net periodic costs must be outside of Operating Income. In addition, the updated guidance permits only the service cost component of net periodic costs to be capitalized to Inventory or Property, Plant and require revenue implementation guidance.Equipment. This represents a change from current GAAP, which permits all components of net periodic costs to be capitalized. These amendments should be applied retrospectively for the presentation of the various components of net periodic costs and prospectively for the change in eligible costs to be capitalized. The revenue implementation guideguidance allows for a practical expedient that permits a company to use amounts disclosed in prior-period financial statements as the estimation basis for applying the retrospective presentation requirements.
For Duke Energy, this guidance is effective for interim and annual periods beginning January 1, 2018. Duke Energy currently presents the total non-capitalized net periodic costs within Operation, maintenance and other on the Consolidated Statement of Operations. The adoption of this guidance will result in a retrospective change to reclassify the presentation of the non-service cost (benefit) components of net periodic costs to Other income and expenses. Duke Energy intends to utilize the practical expedient for retrospective presentation. The change in net periodic costs eligible for capitalization is applicable prospectively. Since Duke Energy’s service cost component is expected to be publishedgreater than the total net periodic costs, the change will result in increased capitalization of net periodic costs, higher Operation, maintenance and other and higher Other income and expenses. The resulting impact to Duke Energy is expected to be an immaterial increase in Net Income resulting from the limitation of eligible capitalization of net periodic costs to the service cost component, which is larger than the total net periodic costs.
2. ACQUISITIONS AND DISPOSITIONS
ACQUISITIONS
The Duke Energy Registrants consolidate assets and liabilities from acquisitions as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.
2016 Acquisition of Piedmont Natural Gas
On October 3, 2016, Duke Energy acquired all outstanding common stock of Piedmont for a total cash purchase price of $5.0 billion and assumed Piedmont's existing long-term debt, which had a fair value of approximately $2.0 billion at the time of the acquisition. The acquisition provides a foundation for Duke Energy to establish a broader, long-term strategic natural gas infrastructure platform to complement its existing natural gas pipeline investments and regulated natural gas business in the Midwest. In connection with the closing of the acquisition, Piedmont became a wholly owned subsidiary of Duke Energy.
Purchase Price Allocation
The purchase price allocation of the Piedmont acquisition is as follows: |
| | | |
| (in millions) | |
| Current assets | $ | 497 |
|
| Property, plant and equipment, net | 4,714 |
|
| Goodwill | 3,353 |
|
| Other long-term assets | 804 |
|
| Total assets | 9,368 |
|
| Current liabilities, including current maturities of long-term debt | 576 |
|
| Long-term liabilities | 1,790 |
|
| Long-term debt | 2,002 |
|
| Total liabilities | 4,368 |
|
| Total purchase price | $ | 5,000 |
|
The fair value of Piedmont's assets and liabilities was determined based on significant estimates and assumptions that are judgmental in nature, including the amount and timing of projected future cash flows, discount rates reflecting risk inherent in the future cash flows and market prices of long-term debt.
The majority of Piedmont’s operations are subject to the rate-setting authority of the NCUC, the PSCSC and the TPUC and are accounted for pursuant to accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for Piedmont’s regulated operations provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. Thus, the fair value of Piedmont's assets and liabilities subject to these rate-setting provisions approximates the pre-acquisition carrying values and does not reflect any net valuation adjustments.
The significant assets and liabilities for which valuation adjustments were reflected within the purchase price allocation include the acquired equity method investments and long-term debt. The difference between the fair value and the pre-merger carrying values of long-term debt for regulated operations was recorded as a regulatory asset.
The excess of the purchase price over the fair value of Piedmont's assets and liabilities on the acquisition date was recorded as goodwill. The goodwill reflects the value paid by Duke Energy primarily for establishing a broader, long-term strategic natural gas infrastructure growth platform, an improved risk profile and expected synergies resulting from the combined entities.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Under Securities and Exchange Commission (SEC) regulations, Duke Energy elected not to apply push down accounting to the stand-alone Piedmont financial statements.
Accounting Charges Related to the Acquisition
Duke Energy incurred pretax non-recurring transaction and integration costs associated with the acquisition of $103 million, $439 million and $9 million for the years ended December 31, 2017, 2016 and 2015, respectively. Amounts recorded on the Consolidated Statements of Operations in 2017 were primarily system integration costs of $71 million related to combining the various operational and financial systems of Duke Energy and Piedmont, including a one-time software impairment resulting from planned accounting system and process integration. A $7 million charge was recorded within Impairment Charges, with the remaining $64 million recorded within Operation, maintenance and other.
Amounts recorded in 2016 include:
Interest expense of $234 million related to the acquisition financing, including realized losses on forward-starting interest rate swaps of $190 million. See Note 14 for additional information on the swaps.
Charges of $104 million related to commitments made in conjunction with the transaction, including charitable contributions and a one-time bill credit to Piedmont customers. $10 million was recorded as a reduction in Operating Revenues, with the remaining $94 million recorded within Operation, maintenance and other.
Other transaction and integration costs of $101 million recorded to Operation, maintenance and other, including professional fees and severance.
The majority of transition and integration activities are expected to be completed by the end of 2018.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the combined results of operations of Duke Energy and Piedmont as if the merger had occurred as of January 1, 2015. The pro forma financial information does not include potential cost savings, intercompany revenues, Piedmont’s earnings from a certain equity method investment sold immediately prior to the standard becoming effective in 2017; however, no datemerger or non-recurring transaction and integration costs incurred by Duke Energy and Piedmont. The after-tax non-recurring transaction and integration costs incurred by Duke Energy and Piedmont were $279 million and $19 million for the years ended December 31, 2016, and 2015, respectively.
This information has been set.
We are currently evaluatingpresented for illustrative purposes only and is not necessarily indicative of the
effect on our financial position,consolidated results of operations
that would have been achieved or the future consolidated results of operations of Duke Energy. |
| | | | | | |
| | Years Ended December 31, |
| (in millions) | 2016 | 2015 |
| Operating Revenues | $ | 23,504 |
| $ | 23,570 |
|
| Net Income Attributable to Duke Energy Corporation | 2,442 |
| 2,877 |
|
Piedmont's Earnings
Piedmont's revenues and net income included in Duke Energy's Consolidated Statements of Operations for the year ended December 31, 2016, were $367 million and $20 million, respectively. Piedmont's revenues and net income for the year ended December 31, 2016, include the impact of non-recurring transaction costs of $10 million and $46 million, respectively.
Acquisition Related Financings and Other Matters
Duke Energy financed the Piedmont acquisition with a combination of debt and equity issuances and other cash flows. sources, including:
$3.75 billion of long-term debt issued in August 2016.
$750 million borrowed under the $1.5 billion short-term loan facility in September 2016, which was repaid in December 2016.
10.6 million shares of common stock issued in October 2016 for net cash proceeds of approximately $723 million.
The evaluation includes identifying revenues streams by like contracts to allow for ease of implementation once$4.9 billion senior unsecured bridge financing facility (Bridge Facility) with Barclays Capital, Inc. (Barclays) was terminated following the utility sub-group has issued the revenue implementation guide.
In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and disclosure requirements for a reporting entity that has an interest in an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.
In August 2014, the FASB issued accounting guidance on determining when and how reporting entities must disclose going concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date of issuance of the entity's financial statements. An entity must provide certain disclosures if there is a "substantial doubt aboutlong-term debt. For additional information related to the entity's ability to continue as a going concern."debt and equity issuances, see Notes 6 and 18, respectively. For additional information regarding Duke Energy's and Piedmont's joint investment in Atlantic Coast Pipeline, LLC (ACP), see Note 4.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DISPOSITIONS
For the year ended December 31, 2017, the Loss from Discontinued Operations, net of tax, was immaterial. The standard is effectivefollowing table summarizes the (Loss) Income from Discontinued Operations, net of tax recorded on Duke Energy's Consolidated Statements of Operations for annual periods ending afterthe years ended December 15,31, 2016, and interim periods thereafter; early adoption is permitted.2015: |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2016 |
| | 2015 |
|
| International Energy Disposal Group | $ | (534 | ) | | $ | 157 |
|
| Midwest Generation Disposal Group | 36 |
| | 33 |
|
Other(a) | 90 |
| | (13 | ) |
| (Loss) Income from Discontinued Operations, net of tax | $ | (408 | ) | | $ | 177 |
|
| |
| (a) | Relates to previously sold businesses not related to the Disposal Groups. The amount for 2016 represents an income tax benefit resulting from immaterial out of period deferred tax liability adjustments. The amount for 2015 includes indemnifications provided for certain legal, tax and environmental matters and foreign currency translation adjustments. |
2016 Sale of International Energy
In February 2016, Duke Energy announced it had initiated a process to divest its International Energy businesses, excluding the equity method investment in NMC (the International Disposal Group), and in October 2016, announced it had entered into two separate purchase and sale agreements to execute the divestiture. Both sales closed in December of 2016, resulting in available cash proceeds of $1.9 billion, excluding transaction costs. Proceeds were primarily used to reduce Duke Energy holding company (the parent) debt. Existing favorable tax attributes result in no immediate U.S. federal-level cash tax impacts. Details of each transaction are as follows:
On December 20, 2016, Duke Energy closed on the sale of its ownership interests in businesses in Argentina, Chile, Ecuador, El Salvador, Guatemala and Peru to I Squared Capital. The adoptionassets sold included approximately 2,230 MW of this assessment will have no impacthydroelectric and natural gas generation capacity, transmission infrastructure and natural gas processing facilities. I Squared Capital purchased the businesses for an enterprise value of $1.2 billion.
On December 29, 2016, Duke Energy closed on our financial position,the sale of its Brazilian business, which included approximately 2,090 MW of hydroelectric generation capacity, to CTG for an enterprise value of $1.2 billion. With the closing of the CTG deal, Duke Energy finalized its exit from the Latin American market.
Assets Held For Sale and Discontinued Operations
As a result of the transactions, the International Disposal Group was classified as held for sale and as discontinued operations in the fourth quarter of 2016. Interest expense directly associated with the International Disposal Group was allocated to discontinued operations. No interest from corporate level debt was allocated to discontinued operations.
The following table presents the results of operations or cash flows.the International Disposal Group for the years ended December 31, 2016, and 2015, which are included in (Loss) Income from Discontinued Operations, net of tax in Duke Energy's Consolidated Statements of Operations. |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2016 |
| | 2015 |
|
| Operating Revenues | $ | 988 |
| | $ | 1,088 |
|
| Fuel used in electric generation and purchased power | 227 |
| | 306 |
|
| Cost of natural gas | 43 |
| | 53 |
|
| Operation, maintenance and other | 341 |
| | 334 |
|
Depreciation and amortization(a) | 62 |
| | 92 |
|
| Property and other taxes | 15 |
| | 7 |
|
Impairment charges (b) | 194 |
| | 13 |
|
| (Loss) Gains on Sales of Other Assets and Other, net | (3 | ) | | 6 |
|
| Other Income and Expenses, net | 58 |
| | 23 |
|
| Interest Expense | 82 |
| | 85 |
|
Pretax loss on disposal(c) | (514 | ) | | — |
|
(Loss) Income before income taxes(d) | (435 | ) |
| 227 |
|
Income tax expense(e)(f) | 99 |
| | 70 |
|
| (Loss) Income from discontinued operations of the International Disposal Group | $ | (534 | ) |
| $ | 157 |
|
Reclassifications and Changes in Presentation140
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | Upon meeting the criteria for assets held for sale, beginning in the fourth quarter of 2016 depreciation expense was ceased. |
| |
| (b) | In conjunction with the advancements of marketing efforts during 2016, Duke Energy performed recoverability tests of the long-lived asset groups of International Energy. As a result, Duke Energy determined the carrying value of certain assets in Central America was not fully recoverable and recorded a pretax impairment charge of $194 million. The charge represents the excess of carrying value over the estimated fair value of the assets, which was based on a Level 3 Fair Value measurement that was primarily determined from the income approach using discounted cash flows but also considered market information obtained in 2016. |
| |
| (c) | The pretax loss on disposal includes the recognition of cumulative foreign currency translation losses of $620 million as of the disposal date. See the Consolidated Statements of Changes in Equity for additional information. |
| |
| (d) | Pretax (Loss) Income attributable to Duke Energy Corporation was $(445) million and $221 million for the years ended December 31, 2016 and 2015, respectively. |
| |
| (e) | 2016 amount includes $126 million of income tax expense on the disposal, which primarily reflects in-country taxes incurred as a result of the sale. The after-tax loss on disposal was $640 million. |
| |
| (f) | 2016 amount includes an income tax benefit of $95 million. See Note 22, "Income Taxes," for additional information. |
Reclassifications have been madeDuke Energy has elected not to certain prior year financial statements to conform with the current year presentation. Within “Cash Flows From Operating Activities” inseparately disclose discontinued operations on the Consolidated Statements of Cash Flows, we have changed the presentation ofFlows. The following table summarizes Duke Energy's cash flows from discontinued operations related to the International Disposal Group. |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2016 |
| | 2015 |
|
| Cash flows provided by (used in): | | | |
| Operating activities | $ | 204 |
| | $ | 248 |
|
| Investing activities | (434 | ) | | 177 |
|
Other Sale Related Matters
During 2017, Duke Energy provided certain transition services to CTG and I Squared Capital. Cash flows related to providing the transition services were not material as of December 31, 2017. All transition services related to the International Disposal Group ended in 2017. Additionally, Duke Energy will reimburse CTG and I Squared Capital for all tax obligations arising from the period preceding consummation on the transactions, totaling approximately $78 million. Duke Energy has not recorded any other liabilities, contingent liabilities or indemnifications related to the International Disposal Group.
2015 Midwest Generation Exit
Duke Energy, through indirect subsidiaries, completed the sale of the Midwest Generation Disposal Group to a subsidiary of Dynegy on April 2, 2015, for approximately $2.8 billion in cash. The nonregulated Midwest generation business included generation facilities with approximately 5,900 MW of owned capacity located in Ohio, Pennsylvania and Illinois. On April 1, 2015, prior to the sale, Duke Energy Ohio distributed its indirect ownership interest in the nonregulated Midwest generation business to a subsidiary of Duke Energy Corporation.
Duke Energy utilized a revolving credit agreement (RCA) to support the operations of the nonregulated Midwest generation business. Duke Energy Ohio had a power purchase agreement with the Midwest Generation Disposal Group for a portion of its standard service offer (SSO) supply requirement. The agreement and the SSO expired in May 2015.
The results of operations of the Midwest Generation Disposal Group prior to the date of sale are classified as discontinued operations in the accompanying Consolidated Statements of Operations. Interest expense associated with the RCA was allocated to discontinued operations. No other interest expense related to corporate level debt was allocated to discontinued operations. Certain immaterial costs that were eliminated as a result of the sale remained in continuing operations. The following table summarizes the Midwest Generation Disposal Group activity recorded within discontinued operations. |
| | | | | | | | | | | | | | | |
| | Duke Energy | | Duke Energy Ohio |
| | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | 2016 |
| | 2015 |
| | 2016 |
| | 2015 |
|
| Operating Revenues | $ | — |
| | $ | 543 |
| | $ | — |
| | $ | 412 |
|
Pretax Loss on disposal(a) | — |
| | (45 | ) | | — |
| | (52 | ) |
| | | | | | | | |
Income (loss) before income taxes(b) | $ | — |
| | $ | 59 |
| | $ | — |
| | $ | 44 |
|
Income tax (benefit) expense(c) | (36 | ) | | 26 |
| | (36 | ) | | 21 |
|
| Income (loss) from discontinued operations | $ | 36 |
| | $ | 33 |
| | $ | 36 |
| | $ | 23 |
|
| |
| (a) | The Loss on disposal includes impairments recorded to adjust the carrying amount of the assets to the estimated fair value of the business, based on the selling price to Dynegy less cost to sell. |
| |
| (b) | 2015 amounts include the impact of an $81 million charge for the settlement agreement reached in a lawsuit related to the Midwest Generation Disposal Group. Refer to Note 5 for further information about the lawsuit. |
| |
| (c) | 2016 amounts result from immaterial out of period deferred tax liability adjustments. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
3. BUSINESS SEGMENTS
Operating segments are determined based on information used by the chief operating decision-maker in deciding how to allocate resources and evaluate the performance of the business. Duke Energy evaluates segment performance based on segment income. Segment income is defined as income from continuing operations net of income attributable to noncontrolling interests. Segment income, as discussed below, includes intercompany revenues and expenses that are eliminated on the Consolidated Financial Statements. Certain governance costs are allocated to each segment. In addition, direct interest expense and income taxes are included in segment income.
Products and services are sold between affiliate companies and reportable segments of Duke Energy at cost. Segment assets as presented in the tables that follow exclude all intercompany assets.
Duke Energy
Duke Energy's segment structure includes the following segments: Electric Utilities and Infrastructure, Gas Utilities and Infrastructure and Commercial Renewables.
The Electric Utilities and Infrastructure segment includes Duke Energy's regulated electric utilities in the Carolinas, Florida and the Midwest. The regulated electric utilities conduct operations through the Subsidiary Registrants that are substantially all regulated and, accordingly, qualify for regulatory accounting treatment. Electric Utilities and Infrastructure also includes Duke Energy's commercial electric transmission infrastructure investments.
The Gas Utilities and Infrastructure segment includes Piedmont, Duke Energy's natural gas local distribution companies in Ohio and Kentucky, and Duke Energy's natural gas storage and midstream pipeline investments. Gas Utilities and Infrastructure's operations are substantially all regulated and, accordingly, qualify for regulatory accounting treatment.
The Commercial Renewables segment is primarily comprised of nonregulated utility scale wind and solar generation assets located throughout the U.S.
The remainder of Duke Energy’s operations is presented as Other, which is primarily comprised of corporate interest expense, unallocated corporate costs, contributions to the Duke Energy Foundation and the operations of Duke Energy’s wholly owned captive insurance subsidiary, Bison Insurance Company Limited (Bison). Other also includes Duke Energy's interest in NMC. See Note 12 for additional information on the investment in NMC.
Business segment information is presented in the following tables. Segment assets presented exclude intercompany assets. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Electric |
| | Gas |
| | | | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Commercial |
| | Reportable |
| | | | | | |
| (in millions) | Infrastructure |
| | Infrastructure |
| | Renewables |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Unaffiliated Revenues | $ | 21,300 |
| | $ | 1,743 |
| | $ | 460 |
| | $ | 23,503 |
| | $ | 62 |
| | $ | — |
| | $ | 23,565 |
|
| Intersegment Revenues | 31 |
| | 93 |
| | — |
| | 124 |
| | 76 |
| | (200 | ) | | — |
|
| Total Revenues | $ | 21,331 |
| | $ | 1,836 |
| | $ | 460 |
| | $ | 23,627 |
| | $ | 138 |
| | $ | (200 | ) | | $ | 23,565 |
|
| Interest Expense | $ | 1,240 |
| | $ | 105 |
| | $ | 87 |
| | $ | 1,432 |
| | $ | 574 |
| | $ | (20 | ) | | $ | 1,986 |
|
| Depreciation and amortization | 3,010 |
| | 231 |
| | 155 |
| | 3,396 |
| | 131 |
| | — |
| | 3,527 |
|
| Equity in earnings (losses) of unconsolidated affiliates | 5 |
| | 62 |
| | (5 | ) | | 62 |
| | 57 |
| | — |
| | 119 |
|
Income tax expense (benefit)(a) | 1,355 |
| | 116 |
| | (628 | ) | | 843 |
| | 353 |
| | — |
| | 1,196 |
|
Segment income (loss)(b)(c)(d) | 3,210 |
| | 319 |
| | 441 |
| | 3,970 |
| | (905 | ) | | — |
| | 3,065 |
|
| Add back noncontrolling interest component | |
| | |
| | |
| | |
| | |
| | |
| | 5 |
|
| Loss from discontinued operations, net of tax | |
| | |
| | |
| | |
| | |
| | |
| | (6 | ) |
| Net income | |
| | |
| | |
| | |
| | |
| | |
| | $ | 3,064 |
|
| Capital investments expenditures and acquisitions | $ | 7,024 |
| | $ | 907 |
| | $ | 92 |
| | $ | 8,023 |
| | $ | 175 |
| | $ | — |
| | $ | 8,198 |
|
| Segment assets | 119,423 |
| | 11,462 |
| | 4,156 |
| | 135,041 |
| | 2,685 |
| | 188 |
| | 137,914 |
|
| |
| (a) | All segments include impacts of the Tax Cuts and Jobs Act (the Tax Act). Electric Utilities and Infrastructure includes a $231 million benefit, Gas Utilities and Infrastructure includes a $26 million benefit, Commercial Renewables includes a $442 million benefit and Other includes charges of $597 million. |
| |
| (b) | Electric Utilities and Infrastructure includes after-tax regulatory settlement charges of $98 million. See Note 4 for additional information. |
| |
| (c) | Commercial Renewables includes after-tax impairment charges of $74 million related to certain wind projects and the Energy Management Solutions reporting unit. See Notes 10 and 11 for additional information. |
| |
| (d) | Other includes $64 million of after-tax costs to achieve the Piedmont merger. See Note 2 for additional information. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Electric |
| | Gas |
| | | | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Commercial |
| | Reportable |
| | | | | | |
| (in millions) | Infrastructure |
| | Infrastructure |
| | Renewables |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Unaffiliated Revenues | $ | 21,336 |
| | $ | 875 |
| | $ | 484 |
| | $ | 22,695 |
| | $ | 48 |
| | $ | — |
| | $ | 22,743 |
|
| Intersegment Revenues | 30 |
| | 26 |
| | — |
| | 56 |
| | 69 |
| | (125 | ) | | — |
|
| Total Revenues | $ | 21,366 |
| | $ | 901 |
| | $ | 484 |
| | $ | 22,751 |
| | $ | 117 |
| | $ | (125 | ) | | $ | 22,743 |
|
| Interest Expense | $ | 1,136 |
| | $ | 46 |
| | $ | 53 |
| | $ | 1,235 |
| | $ | 693 |
| | $ | (12 | ) | | $ | 1,916 |
|
| Depreciation and amortization | 2,897 |
| | 115 |
| | 130 |
| | 3,142 |
| | 152 |
| | — |
| | 3,294 |
|
Equity in earnings (losses) of unconsolidated affiliates(a) | 5 |
| | 19 |
| | (82 | ) | | (58 | ) | | 43 |
| | — |
| | (15 | ) |
| Income tax expense (benefit) | 1,672 |
| | 90 |
| | (160 | ) | | 1,602 |
| | (446 | ) | | — |
| | 1,156 |
|
Segment income (loss)(b)(c) | 3,040 |
| | 152 |
| | 23 |
| | 3,215 |
| | (645 | ) | | 1 |
| | 2,571 |
|
| Add back noncontrolling interest component | |
| | |
| | |
| | |
| | |
| | |
| | 7 |
|
Loss from discontinued operations, net of tax(d) | |
| | |
| | |
| | |
| | |
| | |
| | (408 | ) |
| Net income | |
| | |
| | |
| | |
| | |
| | |
| | $ | 2,170 |
|
Capital investments expenditures and acquisitions(e) | $ | 6,649 |
| | $ | 5,519 |
| | $ | 857 |
| | $ | 13,025 |
| | $ | 190 |
| | $ | — |
| | $ | 13,215 |
|
| Segment assets | 114,993 |
| | 10,760 |
| | 4,377 |
| | 130,130 |
| | 2,443 |
| | 188 |
| | 132,761 |
|
(a) Commercial Renewables includes a pretax impairment charge of $71 million. See Note 12 for additional information.
| |
| (b) | Other includes $329 million of after-tax costs to achieve mergers. Refer to Note 2 for additional information on costs related to the Piedmont merger. |
| |
| (c) | Other includes after-tax charges of $57 million related to cost savings initiatives. Refer to Note 19 for further information. |
| |
| (d) | Includes a loss on sale of the International Disposal Group. Refer to Note 2 for further information. |
| |
| (e) | Other includes $26 million of capital investments expenditures related to the International Disposal Group. Gas Utilities and Infrastructure includes the Piedmont acquisition of $5 billion. Refer to Note 2 for more information on the Piedmont acquisition. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Electric |
| | Gas |
| | | | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Commercial |
| | Reportable |
| | | | | | |
| (in millions) | Infrastructure |
| | Infrastructure |
| | Renewables |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Unaffiliated Revenues | $ | 21,489 |
| | $ | 536 |
| | $ | 286 |
| | $ | 22,311 |
| | $ | 60 |
| | $ | — |
| | $ | 22,371 |
|
| Intersegment Revenues | 32 |
| | 5 |
| | — |
| | 37 |
| | 75 |
| | (112 | ) | | — |
|
| Total Revenues | $ | 21,521 |
| | $ | 541 |
| | $ | 286 |
| | $ | 22,348 |
| | $ | 135 |
| | $ | (112 | ) | | $ | 22,371 |
|
| Interest Expense | $ | 1,074 |
| | $ | 25 |
| | $ | 44 |
| | $ | 1,143 |
| | $ | 393 |
| | $ | (9 | ) | | $ | 1,527 |
|
| Depreciation and amortization | 2,735 |
| | 79 |
| | 104 |
| | 2,918 |
| | 135 |
| | — |
| | 3,053 |
|
| Equity in (losses) earnings of unconsolidated affiliates | (2 | ) | | 1 |
| | (6 | ) | | (7 | ) | | 76 |
| | — |
| | 69 |
|
| Income tax expense (benefit) | 1,602 |
| | 44 |
| | (128 | ) | | 1,518 |
| | (262 | ) | | — |
| | 1,256 |
|
Segment income (loss) (a)(b)(c) | 2,819 |
| | 73 |
| | 52 |
| | 2,944 |
| | (299 | ) | | — |
| | 2,645 |
|
| Add back noncontrolling interest component | |
| | |
| | |
| | |
| | |
| | |
| | 9 |
|
Income from discontinued operations, net of tax(d) | |
| | |
| | |
| | |
| | |
| | |
| | 177 |
|
| Net income | |
| | |
| | |
| | |
| | |
| | |
| | $ | 2,831 |
|
Capital investments expenditures and acquisitions(e) | $ | 6,852 |
| | $ | 234 |
| | $ | 1,019 |
| | $ | 8,105 |
| | $ | 258 |
| | $ | — |
| | $ | 8,363 |
|
Segment assets(f) | 109,097 |
| | 2,637 |
| | 3,861 |
| | 115,595 |
| | 5,373 |
| | 188 |
| | 121,156 |
|
| |
| (a) | Electric Utilities and Infrastructure includes an after-tax charge of $58 million related to the Edwardsport settlement. Refer to Note 4 for further information. |
| |
| (b) | Other includes $60 million of after-tax costs to achieve mergers. |
| |
| (c) | Other includes after-tax charges of $77 million related to cost savings initiatives. Refer to Note 19 for further information. |
| |
| (d) | Includes the impact of a settlement agreement reached in a lawsuit related to the Midwest Generation Disposal Group. Refer to Note 5 for further information related to the lawsuit and Note 2 for further information on discontinued operations. |
| |
| (e) | Other includes capital investment expenditures of $45 million related to the International Disposal Group. |
| |
| (f) | Other includes Assets Held for Sale balances related to the International Disposal Group. Refer to Note 2 for further information. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Geographical Information
For the years ended December 31, 2017, 2016 and 2015, all assets and revenues from continuing operations are within the U.S.
Major Customers
For the year ended December 31, 2017, revenues from one customer of Duke Energy Progress are $521 million. Duke Energy Progress has one reportable segment, Electric Utilities and Infrastructure. No other subsidiary registrant has an individual customer representing more than 10 percent of its revenues.
Products and Services
The following table summarizes revenues of the reportable segments by type. |
| | | | | | | | | | | | | | | | | | | |
| | Retail |
| | Wholesale |
| | Retail |
| | | | Total |
|
| (in millions) | Electric |
| | Electric |
| | Natural Gas |
| | Other |
| | Revenues |
|
| 2017 | | | | | | | | |
|
| Electric Utilities and Infrastructure | $ | 18,177 |
| | $ | 2,104 |
| | $ | — |
| | $ | 1,050 |
| | $ | 21,331 |
|
| Gas Utilities and Infrastructure | — |
| | — |
| | 1,732 |
| | 104 |
| | 1,836 |
|
| Commercial Renewables | — |
| | 375 |
| | — |
| | 85 |
| | 460 |
|
| Total Reportable Segments | $ | 18,177 |
| | $ | 2,479 |
| | $ | 1,732 |
|
| $ | 1,239 |
| | $ | 23,627 |
|
| 2016 | | | | | | | | |
|
| Electric Utilities and Infrastructure | $ | 18,338 |
| | $ | 2,095 |
| | $ | — |
| | $ | 933 |
| | $ | 21,366 |
|
| Gas Utilities and Infrastructure | — |
| | — |
| | 871 |
| | 30 |
| | 901 |
|
| Commercial Renewables | — |
| | 303 |
| | — |
| | 181 |
| | 484 |
|
| Total Reportable Segments | $ | 18,338 |
| | $ | 2,398 |
| | $ | 871 |
|
| $ | 1,144 |
| | $ | 22,751 |
|
| 2015 | | | | | | | | |
|
| Electric Utilities and Infrastructure | $ | 18,695 |
| | $ | 2,014 |
| | $ | — |
| | $ | 812 |
| | $ | 21,521 |
|
| Gas Utilities and Infrastructure | — |
| | — |
| | 546 |
| | (5 | ) | | 541 |
|
| Commercial Renewables | — |
| | 245 |
| | — |
| | 41 |
| | 286 |
|
| Total Reportable Segments | $ | 18,695 |
| | $ | 2,259 |
| | $ | 546 |
|
| $ | 848 |
| | $ | 22,348 |
|
Duke Energy Ohio
Duke Energy Ohio has two reportable operating segments, Electric Utilities and Infrastructure and Gas Utilities and Infrastructure.
Electric Utilities and Infrastructure transmits and distributes electricity in portions of Ohio and generates, distributes and sells electricity in portions of Northern Kentucky. Gas Utilities and Infrastructure transports and sells natural gas in portions of Ohio and Northern Kentucky. It conducts operations primarily through Duke Energy Ohio and its wholly owned subsidiary, Duke Energy Kentucky.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The remainder of Duke Energy Ohio's operations is presented as Other, which is primarily comprised of governance costs allocated by its parent, Duke Energy, and revenues and expenses related to Duke Energy Ohio's contractual arrangement to buy power from OVEC's (Ohio Valley Electric Corporation) power plants. See Note 13 for additional information on related party transactions. For the years ended December 31, 2017, 2016 and 2015, all Duke Energy Ohio assets and revenues are within the U.S. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Electric |
| | Gas |
| | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Reportable |
| | | | | | |
(in millions) | Infrastructure |
| | Infrastructure |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Total revenues | $ | 1,373 |
| | $ | 508 |
| | $ | 1,881 |
| | $ | 42 |
| | $ | — |
| | $ | 1,923 |
|
| Interest expense | $ | 62 |
| | $ | 28 |
| | $ | 90 |
| | $ | 1 |
| | $ | — |
| | $ | 91 |
|
| Depreciation and amortization | 178 |
| | 83 |
| | 261 |
| | $ | — |
| | — |
| | 261 |
|
| Income tax expense (benefit) | 40 |
| | 39 |
| | 79 |
| | $ | (20 | ) | | — |
| | 59 |
|
| Segment income (loss) | 138 |
| | 85 |
| | 223 |
| | $ | (30 | ) | | — |
| | 193 |
|
| Loss from discontinued operations, net of tax | | | | | | | | | | | (1 | ) |
| Net income |
|
| |
|
| |
|
| |
|
| | | | $ | 192 |
|
| Capital expenditures | $ | 491 |
| | $ | 195 |
| | $ | 686 |
| | $ | — |
| | $ | — |
| | $ | 686 |
|
| Segment assets | 5,066 |
| | 2,758 |
| | 7,824 |
| | 66 |
| | (15 | ) | | 7,875 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Electric |
| | Gas |
| | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Reportable |
| | | | | | |
| (in millions) | Infrastructure |
| | Infrastructure |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Total revenues | $ | 1,410 |
| | $ | 503 |
| | $ | 1,913 |
| | $ | 31 |
| | $ | — |
| | $ | 1,944 |
|
| Interest expense | $ | 58 |
| | $ | 27 |
| | $ | 85 |
| | $ | 1 |
| | $ | — |
| | $ | 86 |
|
| Depreciation and amortization | 151 |
| | 80 |
| | 231 |
| | 2 |
| | — |
| | 233 |
|
| Income tax expense (benefit) | 55 |
| | 44 |
| | 99 |
| | (21 | ) | | — |
| | 78 |
|
| Segment income (loss) | 154 |
| | 77 |
| | 231 |
| | (39 | ) | | — |
| | 192 |
|
| Income from discontinued operations, net of tax | | | | | | | | | | | 36 |
|
| Net income |
|
| |
|
| |
|
| |
|
| | | | $ | 228 |
|
| Capital expenditures | $ | 322 |
| | $ | 154 |
| | $ | 476 |
| | $ | — |
| | $ | — |
| | $ | 476 |
|
| Segment assets | 4,782 |
| | 2,696 |
| | 7,478 |
| | 62 |
| | (12 | ) | | 7,528 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Electric |
| | Gas |
| | Total |
| | | | | | |
| | Utilities and |
| | Utilities and |
| | Reportable |
| | | | | | |
| (in millions) | Infrastructure |
| | Infrastructure |
| | Segments |
| | Other |
| | Eliminations |
| | Total |
|
| Total revenues | $ | 1,331 |
| | $ | 541 |
| | $ | 1,872 |
| | $ | 33 |
| | $ | — |
| | $ | 1,905 |
|
| Interest expense | $ | 53 |
| | $ | 25 |
| | $ | 78 |
| | $ | 1 |
| | $ | — |
| | $ | 79 |
|
| Depreciation and amortization | 147 |
| | 79 |
| | 226 |
| | 1 |
| | — |
| | 227 |
|
| Income tax expense (benefit) | 59 |
| | 45 |
| | 104 |
| | (23 | ) | | — |
| | 81 |
|
| Segment income (loss) | 118 |
| | 73 |
| | 191 |
| | (41 | ) | | (1 | ) | | 149 |
|
| Income from discontinued operations, net of tax | | | | | | | | | | | 23 |
|
| Net income |
|
| |
|
| |
|
| |
|
| | | | $ | 172 |
|
| Capital expenditures | $ | 264 |
| | $ | 135 |
| | $ | 399 |
| | $ | — |
| | $ | — |
| | $ | 399 |
|
| Segment assets | 4,534 |
| | 2,516 |
| | 7,050 |
| | 56 |
| | (9 | ) | | 7,097 |
|
4. REGULATORY MATTERS
REGULATORY ASSETS AND LIABILITIES
The Duke Energy Registrants record regulatory assets and liabilities previously included withinthat result from the line items “Other assets” and “Other liabilities,” respectively, to provide additional detail and to present such information within separate line items, “Regulatory assets” and “Regulatory liabilities.” The 2013 and 2012 presentation has been changed to conform to the current year presentation. The reclassifications had no effect on previously reported amountsratemaking process. See Note 1 for net cash flows from operating, investing or financing activities.further information.
2. Regulatory MattersPART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three regulatory commissions address our gas supply hedging activities. Additionally, all three regulatory commissions allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense.
North Carolina
The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.
The NCUC had allowed EasternNCfollowing tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets of Duke Energy and Progress Energy. See separate tables below for balances by individual registrant. |
| | | | | | | | | | | | | | | |
| | Duke Energy | | Progress Energy |
| | December 31, | | December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| Regulatory Assets | | | | | | | |
| AROs – coal ash | $ | 4,025 |
| | $ | 3,761 |
| | $ | 1,984 |
| | $ | 1,830 |
|
| AROs – nuclear and other | 852 |
| | 684 |
| | 655 |
| | 569 |
|
| Accrued pension and OPEB | 2,249 |
| | 2,387 |
| | 906 |
| | 882 |
|
| Retired generation facilities | 480 |
| | 534 |
| | 386 |
| | 422 |
|
| Debt fair value adjustment | 1,197 |
| | 1,313 |
| | — |
| | — |
|
| Net regulatory asset related to income taxes | — |
| | 894 |
| | — |
| | 231 |
|
| Storm cost deferrals | 531 |
| | 153 |
| | 526 |
| | 148 |
|
| Nuclear asset securitized balance, net | 1,142 |
| | 1,193 |
| | 1,142 |
| | 1,193 |
|
| Hedge costs deferrals | 234 |
| | 217 |
| | 94 |
| | 91 |
|
| Derivatives – natural gas supply contracts | 142 |
| | 187 |
| | — |
| | — |
|
| Demand side management (DSM)/Energy efficiency (EE) | 530 |
| | 407 |
| | 281 |
| | 278 |
|
| Grid modernization | 39 |
| | 65 |
| | — |
| | — |
|
| Vacation accrual | 213 |
| | 196 |
| | 42 |
| | 38 |
|
| Deferred fuel and purchased power | 507 |
| | 156 |
| | 349 |
| | 111 |
|
| Nuclear deferral | 119 |
| | 226 |
| | 35 |
| | 134 |
|
| Post-in-service carrying costs (PISCC) and deferred operating expenses | 366 |
| | 413 |
| | 38 |
| | 42 |
|
| Transmission expansion obligation | 46 |
| | 71 |
| | — |
| | — |
|
| Manufactured gas plant (MGP) | 91 |
| | 99 |
| | — |
| | — |
|
| Advanced metering infrastructure (AMI) | 362 |
| | 218 |
| | 150 |
| | — |
|
| NCEMPA deferrals | 53 |
| | 51 |
| | 53 |
| | 51 |
|
| East Bend deferrals | 45 |
| | 32 |
| | — |
| | — |
|
| Deferred pipeline integrity costs | 54 |
| | 36 |
| | — |
| | — |
|
| Amounts due from customers | 64 |
| | 66 |
| | — |
| | — |
|
| Other | 538 |
| | 542 |
| | 110 |
| | 103 |
|
| Total regulatory assets | 13,879 |
| | 13,901 |
|
| 6,751 |
|
| 6,123 |
|
| Less: current portion | 1,437 |
| | 1,023 |
| | 741 |
| | 401 |
|
| Total noncurrent regulatory assets | $ | 12,442 |
| | $ | 12,878 |
|
| $ | 6,010 |
|
| $ | 5,722 |
|
| Regulatory Liabilities | | | | | | | |
| Costs of removal | $ | 5,968 |
| | $ | 5,613 |
| | $ | 2,537 |
| | $ | 2,198 |
|
| ARO – nuclear and other | 806 |
| | 461 |
| | — |
| | — |
|
| Net regulatory liability related to income taxes | 8,113 |
| | — |
| | 2,802 |
| | — |
|
| Amounts to be refunded to customers | 10 |
| | 45 |
| | — |
| | — |
|
| Storm reserve | 20 |
| | 83 |
| | — |
| | 60 |
|
| Accrued pension and OPEB | 146 |
| | 174 |
| | — |
| | — |
|
| Deferred fuel and purchased power | 47 |
| | 192 |
| | 1 |
| | 81 |
|
| Other | 622 |
| | 722 |
| | 179 |
| | 245 |
|
| Total regulatory liabilities | 15,732 |
| | 7,290 |
| | 5,519 |
| | 2,584 |
|
| Less: current portion | 402 |
| | 409 |
| | 213 |
| | 189 |
|
| Total noncurrent regulatory liabilities | $ | 15,330 |
| | $ | 6,881 |
| | $ | 5,306 |
| | $ | 2,395 |
|
Descriptions of regulatory assets and liabilities summarized in the tables above and below follow. See tables below for recovery and amortization periods at the separate registrants.
AROs – coal ash. Represents deferred depreciation and accretion related to defer its O&M expenses during the first eight years of operationlegal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. See Notes 1 and 9 for additional information.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
AROs – nuclear and other. Represents regulatory assets or until the first rate case order, whichever occurred first,liabilities, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The AROs relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains and losses on NDTF investments. See Notes 1 and 9 for additional information.
Accrued pension and OPEB. Accrued pension and other post-retirement benefit obligations (OPEB) represent regulatory assets and liabilities related to each of the Duke Energy Registrants’ respective shares of unrecognized actuarial gains and losses and unrecognized prior service cost and credit attributable to Duke Energy’s pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. The accrued pension and OPEB regulatory asset is expected to be recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.
Retired generation facilities. Represents amounts accruing interest per annum. In December 2003,to be recovered for facilities that have been retired and are probable of recovery.
Debt fair value adjustment. Purchase accounting adjustments recorded to state the NCUC confirmed that thesecarrying value of Progress Energy and Piedmont at fair value in connection with the 2012 and 2016 mergers, respectively. Amount is amortized over the life of the related debt.
Net regulatory asset or liability related to income taxes. Amounts for all registrants include regulatory liabilities related primarily to impacts from the Tax Act. See Note 22 for additional information. Amounts have no immediate impact on rate base as regulatory assets are offset by deferred expenses should be treatedtax liabilities.
Storm cost deferrals. Represents deferred incremental costs incurred related to extraordinary weather-related events.
Nuclear asset securitized balance, net.Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the upfront financing costs securitized in 2016 with issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion.
Hedge costs and other deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled.
Derivatives – natural gas supply contracts. Represents costs for certain long-dated, fixed quantity forward gas supply contracts, which are recoverable through PGA clauses.
DSM/EE. Deferred costs related to various DSM and EE programs recoverable through various mechanisms.
Grid modernization. Amounts represent deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.
Vacation accrual. Generally recovered within one year.
Deferred fuel and purchased power. Represents certain energy-related costs that are recoverable or refundable as approved by the applicable regulatory body.
Nuclear deferral. Includes amounts related to levelizing nuclear plant outage costs, which allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, resulting in the deferral of operations and maintenance costs associated with refueling.
Post-in-service carrying costs and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service.
Gasification services agreement buyout. The IURC authorized Duke Energy Indiana to recover costs incurred to buy out a gasification services agreement, including carrying costs through 2017.
Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio’s withdrawal from Midcontinent Independent System Operator, Inc. (MISO).
MGP. Represents remediation costs incurred at former MGP sites and the deferral of costs to be incurred at the East End and West End sites through 2019.
AMI. Represents deferred costs related to the installation of AMI meters and remaining net book value of non-AMI meters to be replaced at Duke Energy Carolinas, net book value of existing meters at Duke Energy Florida, Duke Energy Progress and Duke Energy Ohio and expected future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balancenet book value of the EasternNC deferred O&M expenses of $9 millionelectromechanical meters that have been replaced with AMI meters at October 31, 2008 was to be amortized over a twelve year period beginning November 1, 2008, with interest accruing at 7.84% per annum. Under the settlement of the 2013 general rate proceeding discussed below, the unamortized balance of the EasternNC deferred O&M expenses was $6.3 million as of December 31, 2013. This balance is accruing interest at a rate of 6.55% per annum with amortization beginning January 1, 2014over an 82-month period ending October 31, 2020. As of October 31, 2014 and 2013, we had unamortized balances, including accrued interest, of $5.6 million and $6.4 million, respectively.Duke Energy Indiana.
NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA in 2015.
We incur certainEast Bend deferrals. Represents both deferred operating expenses and deferred depreciation as well as carrying costs on the portion of East Bend Generating Station (East Bend) that was acquired from Dayton Power and Light and that had been previously operated as a jointly owned facility.
Deferred pipeline integrity costs. Represents pipeline integrity management costs in compliance with federal regulations recovered through a rider mechanism.
Amounts due from customers. Relates primarily to margin decoupling and IMR recovery mechanisms.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Costs of removal. Represents funds received from customers to cover the Pipeline Safety Improvement Actfuture removal of 1992property, plant and equipment from retired or abandoned sites as property is retired. Also includes certain regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the O&M costs applicable to certain incremental pipeline integrity external expenditures beginning November 1, 2004. The approved balance for recovery of actual pipeline integrity management O&M costs incurred between July 1, 2008 through August 31, 2013 as established in the settlement of the 2013 general rate proceeding discussed below was $17.3 milliondeferred gains on NDTF investments.
Amounts to be amortized overrefunded to customers. Represents required rate reductions to retail customers by the applicable regulatory body.
Storm reserve. Amounts are used to offset future incurred costs for named storms as approved by regulatory commissions.
RESTRICTIONS ON THE ABILITY OF CERTAIN SUBSIDIARIES TO MAKE DIVIDENDS, ADVANCES AND LOANS TO DUKE ENERGY
As a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2014 and 2013, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $28.2 million and $19.4 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs will continue until another recovery mechanism is established in a future rate proceeding.
Withcondition to the approval of merger transactions, the settlementNCUC, PSCSC, PUCO, KPSC and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky, Duke Energy Indiana and Piedmont to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the parent by obtaining approval of the 2013 NCUC general rate proceeding discussed below, future capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements will be separately tracked and recovered on an annual basis through an IMR. The settlement also approved recovery of $6.3 million of deferred North Carolina environmental costs over a five-year period from January 2014 through December 2018.
In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Our gas costs have never been disallowedrespective state regulatory commissions. These conditions imposed restrictions on the basisability of prudence.the public utility subsidiaries to pay cash dividends as discussed below.
In January 2012, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2011, with adjustments agreedDuke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures, which, in certain circumstances, limit their ability to by usmake cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2017.
Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements.
The restrictions discussed below were less than 25 percent of Duke Energy's and Progress Energy's net assets at December 31, 2017.
Duke Energy Carolinas
Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the NCUC Public Staff’s auditamount of retained earnings on the day prior to the closing of the 2011mergers, plus (ii) any future earnings recorded.
Duke Energy Progress
Duke Energy Progress must limit cumulative distributions subsequent to the mergers between Duke Energy and Progress Energy and Duke Energy and Piedmont to (i) the amount of retained earnings on the day prior to the closing of the respective mergers, plus (ii) any future earnings recorded.
Duke Energy Ohio
Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy Corp. (Cinergy) merger not been applied to Duke Energy Ohio’s balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30 percent of total capital.
Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35 percent equity in its capital structure.
Duke Energy Indiana
Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.
Piedmont
Piedmont must limit cumulative distributions subsequent to the acquisition of Piedmont by Duke Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded.
RATE RELATED INFORMATION
The NCUC, PSCSC, FPSC, IURC, PUCO, TPUC and KPSC approve rates for retail electric and natural gas cost review period. We were deemed prudent on ourservices within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service. The FERC also regulates certification and siting of new interstate natural gas purchasing policies and practices during this review period and allowed 100% recovery.pipeline projects.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
All Registrants
Tax Act Impacts
On December 22, 2017, President Trump signed the Tax Act into law, which, among other provisions, reduces the maximum federal corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018. As a result of the Tax Act, the Subsidiary Registrants revalued their deferred tax assets and deferred tax liabilities, as of December 31, 2017, to account for the future impact of lower corporate tax rates on these deferred tax amounts. For the Subsidiary Registrants regulated operations, where the reduction is expected to be accounted for and applied to customers’ rates in future commission proceedings, including rate proceedings, the net remeasurement has been deferred as a regulatory liability. Each of the Subsidiary Registrant's regulatory commissions is reviewing the Tax Act to determine the potential impacts on customer rates. Beginning in January 2018, the Subsidiary Registrants will defer the estimated ongoing impacts of the Tax Act that are expected to be returned to customers. See Note 22 for additional information.
Duke Energy Carolinas and Duke Energy Progress
Ash Basin Closure Costs Deferral
On December 30, 2016, Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the NCUC approved ourseeking an accounting order authorizing deferral of gascertain costs incurred in connection with federal and state environmental remediation requirements related to the permanent closure of ash basins and other ash storage units at coal-fired generating facilities that have provided or are providing generation to customers located in North Carolina. Initial comments were received in March 2017, and reply comments were filed on April 19, 2017. The NCUC has consolidated Duke Energy Carolinas' and Duke Energy Progress’ coal ash deferral requests into their respective general rate case dockets for decision. See "2017 North Carolina Rate Case" sections below for additional discussion. Duke Energy Carolinas and Duke Energy Progress cannot predict the twelve months ended May 31, 2012. We were deemed prudentoutcome of this matter.
Duke Energy Carolinas
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on our gas purchasing policies and practices during this review period and allowed 100% recovery.Duke Energy Carolinas' Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
| AROs - coal ash | $ | 1,645 |
| $ | 1,536 |
| | (i) | (b) |
| AROs - nuclear and other | — |
| 9 |
| | | |
| Accrued pension and OPEB | 410 |
| 481 |
| | | (j) |
Retired generation facilities(c) | 29 |
| 39 |
| | X | 2023 |
Net regulatory asset related to income taxes(d) | — |
| 484 |
| | | |
Hedge costs deferrals(c) | 109 |
| 93 |
| | X | 2041 |
| DSM/EE | 210 |
| 122 |
| | (h) | (h) |
| Vacation accrual | 83 |
| 76 |
| | (e) | 2018 |
| Deferred fuel and purchased power | 140 |
| — |
| | (f) | 2018 |
| Nuclear deferral | 84 |
| 92 |
| | | 2019 |
PISCC(c) | 35 |
| 70 |
| | X | (b) |
| AMI | 185 |
| 172 |
| | X | (b) |
| Other | 222 |
| 223 |
| | | (b) |
| Total regulatory assets | 3,152 |
| 3,397 |
| | | |
| Less: current portion | 299 |
| 238 |
| | | |
| Total noncurrent regulatory assets | $ | 2,853 |
| $ | 3,159 |
| | | |
Regulatory Liabilities(a) | | | | | |
Costs of removal(c) | $ | 2,054 |
| $ | 2,015 |
| | X | (g) |
| ARO - nuclear and other | 806 |
| 461 |
| | | (b) |
Net regulatory liability related to income taxes(d) | 3,028 |
| — |
| | | (b) |
Storm reserve(c) | 20 |
| 22 |
| | | (b) |
| Accrued pension and OPEB | 44 |
| 46 |
| | | (j) |
| Deferred fuel and purchased power | 46 |
| 105 |
| | (f) | 2018 |
| Other | 359 |
| 352 |
| | | (b) |
| Total regulatory liabilities | 6,357 |
| 3,001 |
| | | |
| Less: current portion | 126 |
| 161 |
| | | |
| Total noncurrent regulatory liabilities | $ | 6,231 |
| $ | 2,840 |
| | | |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Included in rate base. |
| |
| (d) | Includes regulatory liabilities related to the change in the North Carolina tax rate discussed in Note 22. |
| |
| (e) | Earns a return on outstanding balance in North Carolina. |
| |
| (f) | Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina. |
| |
| (g) | Recovered over the life of the associated assets. |
| |
| (h) | Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism. |
| |
| (i) | Earns a debt return on coal ash expenditures for North Carolina and South Carolina retail customers. |
| |
| (j) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
2017 North Carolina Rate Case
On August 25, 2017, Duke Energy Carolinas filed an application with the NCUC approved our accountingfor a rate increase for retail customers of gasapproximately $647 million, which represents an approximate 13.6 percent increase in annual base revenues. The rate increase is driven by capital investments subsequent to the previous base rate case, including grid improvement projects, AMI, investments in customer service technologies, costs forof complying with coal combustion residuals (CCR) regulations and the twelve months ended MayNorth Carolina Coal Ash Management Act of 2014 (Coal Ash Act) and recovery of costs related to licensing and development of the William States Lee III Nuclear Station (Lee Nuclear Station) discussed below. On January 23, 2018, the North Carolina Public Staff filed testimony recommending an overall rate decrease of approximately $290 million. An evidentiary hearing is scheduled to begin on February 27, 2018, and a decision and revised customer rates are expected by mid-2018. Duke Energy Carolinas cannot predict the outcome of this matter.
FERC Formula Rate Matter
On July 31, 2013. We were deemed prudent on our gas purchasing policies2017, Piedmont Municipal Power Agency (PMPA) filed a complaint with FERC against Duke Energy Carolinas alleging that Duke Energy Carolinas misapplied the formula rate under the purchase power agreement (PPA) between the parties by including regulatory amortization in its rates without FERC approval. Duke Energy Carolinas disagreed with PMPA as it believed it was properly applying its FERC filed rate. On February 15, 2018, FERC issued an order ruling in favor of PMPA and practices duringordered Duke Energy Carolinas to refund to PMPA all amounts improperly collected under the PPA. Resolution of this review period and allowed 100% recovery.matter is not expected to be material.
Lincoln County Combustion Turbine
In November 2014,On December 7, 2017, the NCUC approved our accountingissued an order approving a Certificate of Public Convenience and Necessity (CPCN) for Duke Energy Carolinas' proposed 402-megawatt (MW) simple cycle, advanced combustion turbine natural gas-fueled electric generating unit at its existing Lincoln County site. The CPCN also includes construction of related transmission and natural gas costs forpipeline interconnection facilities. Construction is scheduled to begin in 2018 with an extended commissioning and validation period from 2020-2024 and an estimated commercial operation date in 2024. As a condition of the twelve months ended May 31, 2014. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
Our gas cost hedging plan for North Carolina is designed to provide a level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below,approval, Duke Energy Carolinas will not seek recovery of costs associated with the project until it is placed into commercial operation.
Advanced Metering Infrastructure Deferral
On July 12, 2016, the PSCSC issued an accounting order for Duke Energy Carolinas to defer the financial effects of depreciation expense incurred for the installation of AMI meters, the carrying costs on the investment at its weighted average cost of capital (WACC) and the carrying costs on the deferred costs at its WACC not to exceed $45 million. The decision also allows Duke Energy Carolinas to continue to depreciate the non-AMI meters to be replaced. Current retail rates will not change as a result of the decision and the ability of interested parties to challenge the reasonableness of expenditures in subsequent proceedings is not limited.
William States Lee Combined Cycle Facility
On April 9, 2014, the PSCSC granted Duke Energy Carolinas and North Carolina hedging planElectric Membership Corporation (NCEMC) a Certificate of Environmental Compatibility and Public Convenience and Necessity (CECPCN) for the construction and operation of a 750-MW combined-cycle natural gas-fired generating plant at Duke Energy Carolinas' existing William States Lee Generating Station in Anderson, South Carolina. Duke Energy Carolinas began construction in July 2015 and estimates a cost to build of $600 million for its share of the facility, including allowance for funds used during construction (AFUDC). The project is expected to be commercially available in the first quarter of 2018. NCEMC will own approximately 13 percent of the project. On July 3, 2014, the South Carolina Coastal Conservation League (SCCL) and Southern Alliance for Clean Energy (SACE) jointly filed a Notice of Appeal with the Court of Appeals of South Carolina (S.C. Court of Appeals) seeking the court's review of the PSCSC's decision, claiming the PSCSC did not properly consider a request related to a proposed solar facility prior to granting approval of the CECPCN. The S.C. Court of Appeals affirmed the PSCSC's decision on February 10, 2016, and on March 24, 2016, denied a request for rehearing filed by SCCL and SACE. On April 21, 2016, SCCL and SACE petitioned the South Carolina Supreme Court for review of the S.C. Court of Appeals decision. On March 24, 2017, the South Carolina Supreme Court denied the request for review, thus concluding the matter.
Lee Nuclear Station
In December 2007, Duke Energy Carolinas applied to the NRC for combined operating licenses (COLs) for two Westinghouse AP1000 reactors for the proposed William States Lee III Nuclear Station to be located at a site in Cherokee County, South Carolina. The NCUC and PSCSC concurred with the prudency of Duke Energy Carolinas incurring certain project development and preconstruction costs through several separately issued orders, although full cost recovery is not pre-approvedguaranteed. In December 2016, the NRC issued a COL for each reactor. Duke Energy Carolinas is not required to build the nuclear reactors as result of the COLs being issued.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
On March 29, 2017, Westinghouse filed for voluntary Chapter 11 bankruptcy in the U.S. Bankruptcy Court for the Southern District of New York. As part of its 2017 North Carolina Rate Case discussed above, Duke Energy Carolinas is seeking NCUC approval to cancel the development of the Lee Nuclear Station project due to the Westinghouse bankruptcy filing and other market activity and is requesting recovery of incurred licensing and development costs. Duke Energy Carolinas will maintain the license issued by the NRC in December 2016 as an option for potential future development. As of December 31, 2017, Duke Energy Carolinas has incurred approximately $558 million of costs, including AFUDC, related to the project. These project costs are included in Net property, plant and equipment on Duke Energy Carolinas’ Consolidated Balance Sheets. Duke Energy Carolinas cannot predict the outcome of this matter.
Duke Energy Progress
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on Duke Energy Progress' Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
| AROs - coal ash | $ | 1,975 |
| $ | 1,822 |
| | (i) | (b) |
| AROs - nuclear and other | 359 |
| 275 |
| | | (c) |
| Accrued pension and OPEB | 430 |
| 423 |
| | | (l) |
| Retired generation facilities | 170 |
| 165 |
| | X | 2023 |
| Net regulatory asset related to income taxes | — |
| 7 |
| | | (d) |
Storm cost deferrals(e) | 150 |
| 148 |
| | X | (b) |
| Hedge costs deferrals | 64 |
| 66 |
| | | (b) |
DSM/EE(f) | 264 |
| 263 |
| | (j) | 2018 |
| Vacation accrual | 42 |
| 38 |
| | | 2018 |
| Deferred fuel and purchased power | 130 |
| 24 |
| | (g) | 2018 |
| Nuclear deferral | 35 |
| 38 |
| | | 2019 |
| PISCC and deferred operating expenses | 38 |
| 42 |
| | X | 2054 |
| AMI | 75 |
| — |
| | | (b) |
| NCEMPA deferrals | 53 |
| 51 |
| | (h) | 2042 |
| Other | 74 |
| 69 |
| | | (b) |
| Total regulatory assets | 3,859 |
| 3,431 |
| | | |
| Less: current portion | 352 |
| 188 |
| | | |
| Total noncurrent regulatory assets | $ | 3,507 |
| $ | 3,243 |
| | | |
Regulatory Liabilities(a) | | | | | |
| Costs of removal | $ | 2,122 |
| $ | 1,840 |
| | X | (k) |
| Net regulatory liability related to income taxes | 1,854 |
| — |
| | | (b) |
| Deferred fuel and purchased power | 1 |
| 64 |
| | (g) | 2018 |
| Other | 161 |
| 200 |
| | | (b) |
| Total regulatory liabilities | 4,138 |
| 2,104 |
| | | |
| Less: current portion | 139 |
| 158 |
| | | |
| Total noncurrent regulatory liabilities | $ | 3,999 |
| $ | 1,946 |
| | | |
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Recovery period for costs related to nuclear facilities runs through the decommissioning period of each unit. |
| |
| (d) | Recovery over the life of the associated assets. Includes regulatory liabilities related to the change in the North Carolina tax rate discussed in Note 22. |
| |
| (e) | South Carolina storm costs are included in rate base. |
| |
| (f) | Included in rate base. |
| |
| (g) | Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina. |
| |
| (h) | South Carolina retail allocated costs are earning a return. |
| |
| (i) | Earns a debt return on coal ash expenditures for North Carolina and South Carolina retail customers. |
| |
| (j) | Includes incentives on DSM/EE investments. |
| |
| (k) | Recovered over the life of the associated assets. |
| |
| (l) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
2017 North Carolina Rate Case
On June 1, 2017, Duke Energy Progress filed an application with the NCUC for a rate increase for retail customers of approximately $477 million, which represented an approximate 14.9 percent increase in annual base revenues. Subsequent to the filing, Duke Energy Progress adjusted the requested amount to $420 million, representing an approximate 13 percent increase. The rate increase is driven by capital investments subsequent to the previous base rate case, costs of complying with CCR regulations and the Coal Ash Act, costs relating to storm recovery, investments in customer service technologies and recovery of costs associated with renewable purchased power. On November 22, 2017, Duke Energy Progress and the North Carolina Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding, pending NCUC approval. Terms of the settlement include a return on equity of 9.9 percent and a capital structure of 52 percent equity and 48 percent debt. As a result of the settlement, in 2017 Duke Energy Progress recorded pretax charges totaling approximately $25 million to Impairment charges and Operation, maintenance and other on the Consolidated Income Statements, principally related to disallowances from rate base of certain projects at the Mayo and Sutton plants. The settlement does not include agreement on portions of the rate case relating to recovery of deferred storm recovery costs and coal ash basin deferred costs, which will be decided by the NCUC separately. Taking into consideration the settled portions and Duke Energy Progress’ requested recovery of the costsnon-settled portions, the requested rate increase is reduced to approximately $300 million. An evidentiary hearing ended December 7, 2017, and a decision and revised customer rates are treated as gas costs subject toexpected in the annual gas cost prudence review. Any gain or loss recognition underfirst quarter of 2018. Duke Energy Progress cannot predict the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued January 2012, November 2012, November 2013 and November 2014 found our hedging activities during the review periods to be reasonable and prudent.outcome of this matter.
Storm Cost Deferral Filings
In October 2012, weOn December 16, 2016, Duke Energy Progress filed a petition with the NCUC seeking authorityrequesting an accounting order to transfer the total balancedefer certain costs incurred in connection with response to Hurricane Matthew and other significant storms in 2016. The final estimate of $6.7 million ofincremental operation and maintenance and capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use”of $116 million was comprised of real estate and non-real estate costs and related to the development of a LNG facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In April 2013, we withdrew the petition, citing our intent to address the matter in a general rate application. The appropriate treatment of the Robeson County LNG costs was addressed in the general rate settlement discussed below.
In May 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges. In December 2013, the NCUC approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective January 2014. In its order, the NCUC approved the following:
Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7% and a return on common equity of 10% and an overall rate of return of 7.51%.
Increased total annual revenues of $30.7 million, a 3.58% increase in total revenues, or .7% annual increase, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs, and annual pre-tax income of $24.2 million after taking into account revised depreciation rates and changes to regulatory asset amortizations.
Implementation of a new IMR designed to separately track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements.
Implementation of lower depreciation rates that provide increased annual pre-tax income of $10.9 million. These new lower rates reflect the most recent study conducted in 2009, as discussed in Note 1 to the consolidated financial statements.
Amortization and collection of $1.2 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above.
Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses through August 31, 2013 that had been deferred since our last general rate case in 2008.
Provision for ongoing increased annual contributions to fund pipeline safety and integrity research.
Future adjustments to rates to recognize the lower state corporate income taxes from North Carolina legislation for fiscal years beginning November 1, 2014 and November 1, 2015.
In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year.September 2017. On February 5, 2014, the NCUC approved as filed the initial IMR adjustment totaling $.8 million in annual margin revenues that we reflected in our rates to customers beginning that month. In December 2014, we filed a petition with the NCUC seeking authority to adjust rates to collect an additional $26.6 million in annual IMR margin
revenues effective February 1, 2015 based on $241.9 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2014. We are waiting on a ruling from the NCUC at this time.
In April 2014, we filed a petition with the NCUC for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. In August 2014, we andMarch 15, 2017, the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement included the grantingcomments supporting deferral of a waiverportion of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. In October 2014,Duke Energy Progress’ requested amount. Duke Energy Progress filed reply comments on April 12, 2017. On July 10, 2017, the NCUC issued an order rejectingconsolidated Duke Energy Progress' storm deferral request into the joint stipulation of settlement, finding that we must bill our customersDuke Energy Progress rate case docket for the higher commodity cost of gas pursuant to tariffs and assessing a $65,000 penalty against us for failure to bill and collect according to the commission-approved tariffs. The order further requires us to engage in discussions with each customer served under an interruptible rate schedule to explain the service and obligation under that rate schedule and to conduct an investigation to determine if customers are receiving service under the appropriate tariff.
In April 2014, the NCUC issued an order granting us the authority to issue up to $1 billion in the aggregate of senior or subordinated debt securities or equity securities under our open shelf registration statement. This request was made by us to allow flexibility to access the capital markets as needed for business purposes, including for capital investments and to fund the operations of our subsidiaries. For further information on this shelf registration statement, see Note 4 to the consolidated financial statements.
South Carolina
We currently operate under the Natural Gas Rate Stabilization Act of 2005 in South Carolina. If a utility elects to operate under this act, the annual cost and revenue filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.
In June 2012, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2011 order. In October 2012, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (ORS) and us that resulted in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012.
In June 2013, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2013 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2012 order. In October 2013, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2013. The PSCSC also approved the recovery of $.2 million of our deferred South Carolina environmental costs over a one-year period beginning November 2013 and ending October 2014.
In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2013 order. In October 2014, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $2.9 million annual decrease in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2014. Also in this proceeding, the PSCSC approved the recovery of $.1 million of our deferred South Carolina environmental costs and $.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located indecision. See "2017 North Carolina as discussed above, both with amortization periodsRate Case" for additional discussion. As of one year beginning November 2014 and ending October 2015.December 31, 2017, Duke Energy Progress has approximately $77 million included in Regulatory assets on its Consolidated Balance Sheets. Duke Energy Progress cannot predict the outcome of this matter.
In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.
The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates. In an August 2011 order, the PSCSC approved a stipulation that our hedging program should no longer have a required minimum volume of hedging.
In August 2012, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2012.
In August 2013, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2013.
In August 2014, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2014.
In July 2014, weOn December 16, 2016, Duke Energy Progress filed a petition with the PSCSC requesting a limited waiver ofan accounting order to defer certain billing provisions of our tariffcosts incurred related to emergencyrepairs and restoration of service for customers infollowing Hurricane Matthew. The final estimate of incremental operation and maintenance and capital costs was approximately $74 million. In January 2014. In August 2014,2017, the PSCSC granted ourapproved the deferral request and ordered us to continue to collaborate withissued an accounting order. As of December 31, 2017, Duke Energy Progress has approximately $73 million included in Regulatory assets on its Consolidated Balance Sheets.
South Carolina Rate Case
In December 2016, the PSCSC approved a rate case settlement agreement among the ORS to revise our tariff to address the situation that led to this petition.
Tennessee
In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection(Office of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 millionRegulatory Staff), intervenors and Duke Energy Progress. Terms of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would have denied recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in “Operating Expenses” as “Operations and maintenance” in the Consolidated Statements of Comprehensive Income. In November 2011, we filed for reconsideration, which was granted that month. In February 2012, a hearing on this matter was held before the TRA. In May 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in O&M expenses. The written order was issued by the TRA in June 2012.
In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the Actual Cost Adjustment (ACA) mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating secondary marketing gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.
In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. In March 2012, the TRA approved our TIP account balance. The TRA issued its written order approving the deferred gas cost balances in April 2012.
In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In March 2012, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in April 2012.
In August 2012, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2012 under the TIP. In February 2013, the TRA approved the TIP account balances. The TRA issued its written order approving our TIP account balances in March 2013.
In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2013, the TRA approved the deferred gas cost account balances. The TRA issued its written order approving the deferred gas cost balances in March 2013.
In December 2014, we filed an annual report for the twelve months ended June 30, 2013 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.
In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under
the TIP. In February 2014, the TRA Utilities Division Audit Staff (Audit Staff) submitted their report with which we concurred. In March 2014, the TRA approved and adopted the Audit Staff’s report. The TRA’s written order was issued in April 2014.
In August 2014, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2014 under the TIP. We are waiting on a ruling from the TRA at this time.
In August 2013, we filed an ACA petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. In November 2014, we filed a joint settlement agreement with the TRA staff and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) in which the parties agreed that we may include in our next ACA filing prior period adjustments totaling $2 million in lieu of the $3.7 million as originally petitioned. In September 2014, we recorded as expense $1.7 million in the Consolidated Statements of Comprehensive Income. In December 2014, the TRA approved the settlement agreement included an approximate $56 million increase in revenues over a two-year period. An increase of approximately $38 million in revenues was effective January 1, 2017, and we included the stipulated $2an additional increase of approximately $18.5 million of prior period adjustments in the ACA annual report filed in December 2014 for the twelve-month period ended June 30, 2013, as described above.
In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges, proposed to berevenues was effective MarchJanuary 1, 2012. In addition, the petition also requested modifications of2018. Duke Energy Progress amortized approximately $18.5 million from the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and expanding the period of the WNA to October through April. We also sought approval to implementremoval reserve in 2017. Other settlement terms included a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. In December 2011, we and the CAD reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocation and rate designs shifted10.1 percent, recovery of fixed chargescoal ash costs incurred from 29%January 1, 2015, through June 30, 2016, over a 15‑year period and ongoing deferral of allocated ash basin closure costs from July 1, 2016, until the next base rate case. The settlement also provides that Duke Energy Progress will not seek an increase in rates in South Carolina to 37%occur prior to 2019, with limited exceptions.
Western Carolinas Modernization Plan
On November 4, 2015, Duke Energy Progress announced a resulting decreaseWestern Carolinas Modernization Plan, which included retirement of volumetric charges from 71%the existing Asheville coal-fired plant, the construction of two 280‑MW combined-cycle natural gas plants having dual fuel capability, with the option to 63%.build a third natural gas simple cycle unit in 2023 based upon the outcome of initiatives to reduce the region's power demand. The stipulationplan also included upgrades to existing transmission lines and settlement agreement did not includesubstations, installation of solar generation and a pilot battery storage project. These investments will be made within the next seven years. Duke Energy Progress is also working with the local natural gas distribution company to upgrade an existing natural gas pipeline to serve the natural gas plant.
On March 28, 2016, the NCUC issued an order approving a CPCN for the new combined-cycle natural gas plants, but denying the CPCN for the contingent simple cycle unit without prejudice to Duke Energy Progress to refile for approval in the future. On March 28, 2017, Duke Energy Progress filed an annual progress report for the construction of the combined-cycle plants with the NCUC, with an estimated cost of $893 million. Site preparation activities for the combined-cycle plants are underway and construction of these plants began in 2017, with an expected in-service date in late 2019. Duke Energy Progress plans to file for future approvals related to the proposed solar generation and pilot battery storage project.
The carrying value of the 376-MW Asheville coal-fired plant, including associated ash basin closure costs, of $385 million and $492 million are included in Generation facilities to be retired, net on Duke Energy Progress' Consolidated Balance Sheets as of December 31, 2017, and 2016, respectively.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Shearon Harris Nuclear Plant Expansion
In 2006, Duke Energy Progress selected a site at Harris to evaluate for possible future nuclear expansion. On February 19, 2008, Duke Energy Progress filed its COL application with the NRC for two Westinghouse AP1000 reactors at Harris, which the NRC docketed for review. On May 2, 2013, Duke Energy Progress filed a letter with the NRC requesting the NRC to suspend its review activities associated with the COL at the Harris site. The NCUC and PSCSC approved deferral of retail costs. Total deferred costs were approximately $47 million as of December 31, 2017, and are recorded in Regulatory assets on Duke Energy Progress’ Consolidated Balance Sheets. On November 17, 2016, the FERC approved Duke Energy Progress’ rate recovery mechanismrequest filing for the wholesale ratepayers’ share of the abandonment costs, including a school-based energy education program. In January 2012,debt only return to be recovered through revised formula rates and amortized over a hearing on this matter was held by the TRA. The TRA approved15-year period beginning May 1, 2014. As part of the settlement agreement atfor the January 2012 hearing.2017 North Carolina Rate Case discussed above, Duke Energy Progress will amortize the regulatory asset over an eight-year period. The TRA’s written order was issued in April 2012.settlement is subject to NCUC approval. Duke Energy Progress cannot predict the outcome of this matter.
Duke Energy Florida
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on Duke Energy Florida's Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
AROs - coal ash(c) | $ | 9 |
| $ | 8 |
| | X | (b) |
AROs - nuclear and other(c) | 296 |
| 294 |
| | X | (b) |
Accrued pension and OPEB(c) | 476 |
| 458 |
| | X | (h) |
Retired generation facilities(c) | 216 |
| 257 |
| | X | (b) |
Net regulatory asset related to income taxes(c) | — |
| 224 |
| | X | (d) |
Storm cost deferrals(c) | 376 |
| — |
| | (f) | 2021 |
| Nuclear asset securitized balance, net | 1,142 |
| 1,193 |
| | | 2036 |
| Hedge costs deferrals | 30 |
| 25 |
| | | 2018 |
DSM/EE(c) | 17 |
| 15 |
| | X | 2018 |
Deferred fuel and purchased power(c) | 219 |
| 87 |
| | (g) | 2019 |
| Nuclear deferral | — |
| 96 |
| | | |
AMI(c) | 75 |
| — |
| | X | 2032 |
| Other | 36 |
| 36 |
| | | (b) |
| Total regulatory assets | 2,892 |
| 2,693 |
| | | |
| Less: current portion | 389 |
| 213 |
| | | |
| Total noncurrent regulatory assets | $ | 2,503 |
| $ | 2,480 |
| | | |
Regulatory Liabilities(a) | | | | | |
Costs of removal(c) | $ | 415 |
| $ | 358 |
| | (e) | (b) |
Net regulatory liability related to income taxes(c) | 948 |
| — |
| | | (b) |
Storm reserve(c) | — |
| 60 |
| | | |
Deferred fuel and purchased power(c) | — |
| 17 |
| | (g) | |
| Other | 18 |
| 44 |
| | | (b) |
| Total regulatory liabilities | 1,381 |
| 479 |
| | | |
| Less: current portion | 74 |
| 31 |
| | | |
| Total noncurrent regulatory liabilities | $ | 1,307 |
| $ | 448 |
| | | |
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Included in rate base. |
| |
| (d) | Recovery over the life of the associated assets. |
| |
| (e) | Certain costs earn a return. |
| |
| (f) | Earns a debt return/interest once collections begin. |
| |
| (g) | Earns commercial paper rate. |
| |
| (h) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
As a part of the rate case settlement mentioned above, the TRA approved the recovery of $1 million incurred as a result of our response to severe flooding in Nashville in May 2010. These direct incremental expenses had been approved for deferred accounting treatment in October 2010. These deferred expenses are being amortized over eight years beginning March 1, 2012 through February 2020.
Storm Restoration Cost Recovery
In August 2013, weSeptember 2017, Duke Energy Florida’s service territory suffered significant damage from Hurricane Irma, resulting in approximately 1.3 million customers experiencing outages. In the fourth quarter of 2017, Duke Energy Florida also incurred preparation costs related to Hurricane Nate. On December 28, 2017, Duke Energy Florida filed a petition with the TRA seeking authority to implement an IMRFPSC to recover incremental storm restoration costs for Hurricanes Irma and Nate and to replenish the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment on January 1, 2014 of $13.1storm reserve. The estimated recovery amount is approximately $513 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outsiderecovered over a three-year period beginning in March 2018, subject to true up, which includes reestablishment of general rate cases fora $132 million storm reserve. At December 31, 2017, Duke Energy Florida's Consolidated Balance Sheets included approximately $376 million of recoverable costs under the returnFPSC's storm rule in Regulatory assets within Other Noncurrent Assets related to storm recovery. On February 6, 2018, the FPSC approved Duke Energy Florida's motion to approve a stipulation that would apply tax savings resulting from the Tax Act toward storm costs in lieu of implementing a storm surcharge.
2017 Second Revised and on these capital investments. In September 2013,Restated Settlement Agreement
On November 20, 2017, the TRAFPSC issued an order suspending this proposed tariffto approve the 2017 Second Revised and Restated Settlement Agreement (2017 Settlement) filed by Duke Energy Florida. The 2017 Settlement replaces and supplants the 2013 Settlement. The 2017 Settlement extends the base rate case stay-out provision from the 2013 Settlement through December 30, 2013.the end of 2021 unless actual or projected return on equity falls below 9.5 percent; however, Duke Energy Florida is allowed a multiyear increase to its base rates of $67 million per year in 2019, 2020 and 2021, as well as base rate increases for solar generation. In Novemberaddition to carrying forward the provisions contained in the 2013 weSettlement related to the Crystal River 1 and 2 coal units discussed below and future generation needs in Florida, the 2017 Settlement contains provisions related to future investments in solar and renewable energy technology, future investments in AMI technology as well as recovery of existing meters, impacts of the Tax Act, an electric vehicle charging station pilot program and the CAD filed an IMR settlementtermination of the proposed Levy Nuclear Project discussed below. As part of the 2017 Settlement, Duke Energy Florida will not move forward with building the Levy nuclear plant and recorded a pretax impairment charge of approximately $135 million in 2017 to write off all unrecovered Levy Nuclear Project costs, including the COL. As a result of the 2017 Settlement, Duke Energy Florida transferred $75 million to a regulatory asset for the net book value of existing meter technology, which will be recovered over a 15-year period.
The 2017 Settlement includes provisions to recover 2017 under-recovered fuel costs of approximately $196 million over a 24-month period beginning in January 2018. On September 1, 2017, Duke Energy Florida submitted Alternate 2018 Fuel and Capacity clause projection filings consistent with the TRA. A hearingterms of the 2017 Settlement. The updated capacity filing reflects the removal of all Levy costs. The FPSC approved Duke Energy Florida's 2018 Alternate projection filings on this matterOctober 25, 2017.
Hines Chiller Uprate Project
On February 2, 2017, Duke Energy Florida filed a petition seeking approval to include in base rates the revenue requirement for a Chiller Uprate Project (Uprate Project) at the Hines Energy Complex. The Uprate Project was heldplaced into service in December 2013,March 2017 at a cost of approximately $150 million. The annual retail revenue requirement is approximately $19 million. On March 28, 2017, the FPSC issued an order approving the revenue requirement, which was included in base rates for the first billing cycle of April 2017.
Citrus County Combined Cycle Facility
On October 2, 2014, the FPSC granted Duke Energy Florida a Determination of Need for the construction of a 1,640-MW combined-cycle natural gas plant in Citrus County, Florida. On May 5, 2015, the Florida Department of Environmental Protection approved Duke Energy Florida's Site Certification Application. The project has received all required permits and approvals and construction began in October 2015. The facility is expected to be commercially available in 2018 at an estimated cost of $1.5 billion, including AFUDC. The plant will receive natural gas from the Sabal Trail Transmission, LLC (Sabal Trail) pipeline discussed below.
Purchase of Osprey Energy Center
Duke Energy Florida received a Civil Investigative Demand from the Department of Justice (DOJ) related to alleged violation of the waiting period for the Hart-Scott-Rodino Antitrust Improvements Act of 1976 related to the purchase of the Osprey Energy Center, LLC, which was completed in January 2017. The DOJ alleged Duke Energy Florida assumed operational control of the Osprey Plant before the waiting period expiration on February 27, 2015. On January 17, 2017, Duke Energy Florida entered into a stipulation agreement to settle with the DOJ for $600,000 without admission of liability. On January 18, 2017, the DOJ filed a complaint and the TRAstipulation in the U.S. District Court for the District of Columbia, which was approved by the IMR settlement as filed for $13.1 million withcourt. A final order dismissing the IMR rate adjustments beginning January 2014. A written ordercase was issuedentered in May 2014. April 2017.
Crystal River Unit 3
In December 2014, wethe FPSC approved Duke Energy Florida's decision to construct an independent spent fuel storage installation (ISFSI) for the retired Crystal River Unit 3 nuclear plant and approved Duke Energy Florida's request to defer amortization of the ISFSI pending resolution of litigation against the federal government as a result of the Department of Energy's breach of its obligation to accept spent nuclear fuel. The return rate is based on the currently approved AFUDC rate with a return on equity of 7.35 percent, or 70 percent of the currently approved 10.5 percent. The return rate is subject to change if the return on equity changes in the future. In September 2016, the FPSC approved an amendment to the 2013 Settlement authorizing recovery of the ISFSI through the Capacity Cost Recovery Clause. Through December 31, 2017, Duke Energy Florida has deferred approximately $113 million for recovery associated with building the ISFSI. See Note 5 for additional information on spent nuclear fuel litigation.
The regulatory asset associated with the original Crystal River Unit 3 power uprate project will continue to be recovered through the NCRC over an estimated seven-year period that began in 2013 with a remaining uncollected balance of $87 million at December 31, 2017.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Crystal River Unit 3 Regulatory Asset
On September 15, 2015, the FPSC approved Duke Energy Florida's motion for approval of a settlement agreement with intervenors to reduce the value of the projected Crystal River Unit 3 regulatory asset to be recovered to $1.283 billion as of December 31, 2015. An impairment charge of $15 million was recognized in 2015 to adjust the regulatory asset balance. In November 2015, the FPSC issued a financing order approving Duke Energy Florida’s request to issue nuclear asset-recovery bonds to finance its unrecovered regulatory asset related to Crystal River Unit 3 through a wholly owned special purpose entity. Nuclear asset-recovery bonds replace the base rate recovery methodology authorized by the 2013 Settlement and result in a lower rate impact to customers with a recovery period of approximately 20 years.
Pursuant to provisions in Florida Statutes and the FPSC financing order, in 2016, Duke Energy Florida formed Duke Energy Florida Project Finance, LLC (DEFPF), a wholly owned, bankruptcy remote special purpose subsidiary for the purpose of issuing nuclear asset-recovery bonds. In June 2016, DEFPF issued $1,294 million aggregate principal amount of senior secured bonds (nuclear asset-recovery bonds) to finance the recovery of Duke Energy Florida's Crystal River 3 regulatory asset.
In connection with this financing, net proceeds to DEFPF of approximately $1,287 million, after underwriting costs, were used to acquire nuclear asset-recovery property from Duke Energy Florida and to pay transaction related expenses. The nuclear asset-recovery property includes the right to impose, bill, collect and adjust a non-bypassable nuclear asset-recovery charge, to be collected on a per kilowatt-hour basis, from all Duke Energy Florida retail customers until the bonds are paid in full. Duke Energy Florida began collecting the nuclear asset-recovery charge on behalf of DEFPF in customer rates in July 2016.
See Note 17 for additional information.
Levy Nuclear Project
On July 28, 2008, Duke Energy Florida applied to the NRC for COLs for two Westinghouse AP1000 reactors at Levy (Levy Nuclear Project). In 2008, the FPSC granted Duke Energy Florida’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule, together with the associated facilities, including transmission lines and substation facilities. In October 2016, the NRC issued COLs for the proposed Levy Nuclear Plant Units 1 and 2. Duke Energy Florida is not required to build the nuclear reactors as a result of the COLs being issued.
On January 28, 2014, Duke Energy Florida terminated the Levy engineering, procurement and construction agreement (EPC). Duke Energy Florida may be required to pay for work performed under the EPC. Duke Energy Florida recorded an exit obligation in 2014 for the termination of the EPC. This liability was recorded within Other in Other Noncurrent Liabilities with an offset primarily to Regulatory assets on the Consolidated Balance Sheets. Duke Energy Florida is allowed to recover reasonable and prudent EPC cancellation costs from its retail customers. On May 1, 2017, Duke Energy Florida filed a request with the FPSC to recover approximately $82 million of Levy Nuclear Project costs from retail customers in 2018. As part of the 2017 Settlement discussed above, Duke Energy Florida is no longer seeking recovery of costs related to the Levy Nuclear Project and the ongoing Westinghouse litigation discussed in Note 5. All remaining Levy Nuclear Project issues have been resolved.
Crystal River 1 and 2 Coal Units
Duke Energy Florida has evaluated Crystal River 1 and 2 coal units for retirement in order to comply with certain environmental regulations. Based on this evaluation, those units are expected to be retired by the end of 2018. Once those units are retired Duke Energy Florida will continue recovery of existing annual depreciation expense through the end of 2020. Beginning in 2021, Duke Energy Florida will be allowed to recover any remaining net book value of the assets from retail customers through the Capacity Cost Recovery Clause.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy Ohio
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on Duke Energy Ohio's Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
| AROs - coal ash | $ | 17 |
| $ | 12 |
| | X | (b) |
| Accrued pension and OPEB | 139 |
| 135 |
| | | (g) |
Net regulatory asset related to income taxes(c) | — |
| 63 |
| | | (d) |
| Storm cost deferrals | 5 |
| 5 |
| | | (b) |
| Hedge costs deferrals | 6 |
| 7 |
| | | (b) |
| DSM/EE | 18 |
| 6 |
| | (f) | (e) |
| Grid modernization | 39 |
| 65 |
| | X | (e) |
| Vacation accrual | 5 |
| 4 |
| | | 2018 |
| Deferred fuel and purchased power | — |
| 5 |
| | | |
PISCC and deferred operating expenses(c) | 19 |
| 20 |
| | X | 2083 |
| Transmission expansion obligation | 50 |
| 71 |
| | | (e) |
| MGP | 91 |
| 99 |
| | | (b) |
| AMI | 6 |
| — |
| | | (b) |
| East Bend deferrals | 45 |
| 32 |
| | X | (b) |
| Deferred pipeline integrity costs | 12 |
| 7 |
| | X | (b) |
| Other | 42 |
| 26 |
| | | (b) |
| Total regulatory assets | 494 |
| 557 |
| | | |
| Less: current portion | 49 |
| 37 |
| | | |
| Total noncurrent regulatory assets | $ | 445 |
| $ | 520 |
| | | |
Regulatory Liabilities(a) | | | | | |
| Costs of removal | $ | 189 |
| $ | 212 |
| | | (d) |
| Net regulatory liability related to income taxes | 688 |
| — |
| | | (b) |
| Accrued pension and OPEB | 16 |
| 19 |
| | | (g) |
| Deferred fuel and purchased power | — |
| 6 |
| | | |
| Other | 34 |
| 20 |
| | | (b) |
| Total regulatory liabilities | 927 |
| 257 |
| | | |
| Less: current portion | 36 |
| 21 |
| | | |
| Total noncurrent regulatory liabilities | $ | 891 |
| $ | 236 |
| | | |
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Included in rate base. |
| |
| (d) | Recovery over the life of the associated assets. |
| |
| (e) | Recovered via a rider mechanism. |
| |
| (f) | Includes incentives on DSM/EE investments. |
| |
| (g) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
Duke Energy Kentucky Rate Case
On September 1, 2017, Duke Energy Kentucky filed a rate case with the KPSC requesting an increase in electric base rates of approximately $49 million, which represents an approximate 15 percent increase on the average customer bill. The rate increase is driven by increased investment in utility plant, increased operations and maintenance expenses and recovery of regulatory assets. The application also includes implementation of the Environmental Surcharge Mechanism to recover environmental costs not included in base rates, requests to establish a Distribution Capital Investment Rider to recover incremental costs of specific programs, requests to establish a FERC Transmission Cost Reconciliation Rider to recover escalating transmission costs and modification to the Profit Sharing Mechanism to increase customers' share of proceeds from the benefits of owning generation and to mitigate shareholder risks associated with that generation. An evidentiary hearing is scheduled to begin on March 6, 2018.Duke Energy Kentucky anticipates that rates will go into effect in mid-April 2018. Duke Energy Kentucky cannot predict the outcome of this matter.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
2017 Electric Security Plan
On June 1, 2017, Duke Energy Ohio filed with the PUCO a request for a standard service offer in the form of an electric security plan (ESP). If approved by the PUCO, the term of the ESP would be from June 1, 2018, to May 31, 2024. Terms of the ESP include continuation of market-based customer rates through competitive procurement processes for generation, continuation and expansion of existing rider mechanisms and proposed new rider mechanisms relating to regulatory mandates, costs incurred to enhance the customer experience and transform the grid and a service reliability rider for vegetation management. On February 15, 2018, the procedural schedule was suspended to facilitate ongoing settlement discussions. Duke Energy Ohio cannot predict the outcome of this matter.
Woodsdale Station Fuel System Filing
On June 9, 2015, the FERC ruled in favor of PJM Interconnection, LLC (PJM) on a revised Tariff and Reliability Assurance Agreement including implementation of a Capacity Performance (CP) proposal and to amend sections of the Operating Agreement related to generation non-performance. The CP proposal includes performance-based penalties for non-compliance. Duke Energy Kentucky is a Fixed Resource Requirement (FRR) entity, and therefore is subject to the compliance standards through its FRR plans. A partial CP obligation will apply to Duke Energy Kentucky in the delivery year beginning June 1, 2019, with full compliance beginning June 1, 2020. Duke Energy Kentucky has developed strategies for CP compliance investments. On December 21, 2017, the KPSC issued an order approving Duke Energy Kentucky's request for a CPCN to construct an ultra-low sulfur diesel backup fuel system for the Woodsdale Station. The backup fuel system is projected to cost approximately $55 million and is anticipated to be in service prior to the CP compliance deadline of April 2019.
Ohio Valley Electric Corporation
On March 31, 2017, Duke Energy Ohio filed for approval to adjust its existing price stabilization rider (Rider PSR), which is currently set at zero dollars, to pass through net costs related to its contractual entitlement to capacity and energy from the generating assets owned by OVEC. The filing seeks to adjust Rider PSR for OVEC costs subsequent to April 1, 2017. Duke Energy Ohio is seeking deferral authority for net costs incurred from April 1, 2017, until the new rates under Rider PSR are put into effect. Various intervenors have filed motions to dismiss or stay the proceeding and Duke Energy Ohio has opposed these filings. See Note 13 for additional discussion of Duke Energy Ohio's ownership interest in OVEC. Duke Energy Ohio cannot predict the outcome of this matter.
East Bend Coal Ash Basin Filing
On December 2, 2016, Duke Energy Kentucky filed with the KPSC a request for a CPCN for construction projects necessary to close and repurpose an ash basin at the East Bend facility as a result of current and proposed EPA regulations. Duke Energy Kentucky estimated a total cost of approximately $93 million in the filing and expects in-service date by the first quarter of 2021. On June 6, 2017, the KPSC approved the CPCN request.
Electric Base Rate Case
Duke Energy Ohio filed with the PUCO an electric distribution base rate case application and supporting testimony in March 2017. Duke Energy Ohio requested an estimated annual increase of approximately $15 million and a return on equity of 10.4 percent. The application also includes requests to continue certain current riders and establish new riders. On September 26, 2017, the PUCO staff filed a report recommending a revenue decrease between approximately $18 million and $29 million and a return on equity between 9.22 percent and 10.24 percent. On February 15, 2018, the procedural schedule was suspended to facilitate ongoing settlement discussions. Duke Energy Ohio expects rates will go into effect the second quarter of 2018. Duke Energy Ohio cannot predict the outcome of this matter.
Natural Gas Pipeline Extension
Duke Energy Ohio is proposing to install a new natural gas pipeline in its Ohio service territory to increase system reliability and enable the retirement of older infrastructure. On January 20, 2017, Duke Energy Ohio filed an amended application with the Ohio Power Siting Board for approval of one of two proposed routes. A public hearing was held on June 15, 2017, and an adjudicatory hearing was scheduled to begin September 11, 2017. On August 24, 2017, an administrative law judge (ALJ) granted a request made by Duke Energy Ohio to delay the procedural schedule while it works through various issues related to the pipeline route. If approved, construction of the pipeline extension is expected to be completed before the 2020/2021 winter season. The proposed project involves the installation of a natural gas line and is estimated to cost approximately $110 million, excluding AFUDC.
Advanced Metering Infrastructure
On April 25, 2016, Duke Energy Kentucky filed with the KPSC an application for approval of a CPCN for the construction of advanced metering infrastructure. Duke Energy Kentucky estimates the $49 million project will take two years to complete. Duke Energy Kentucky also requested approval to establish a regulatory asset for the remaining book value of existing meter equipment and inventory to be replaced. Duke Energy Kentucky and the Kentucky attorney general entered into a stipulation to settle matters related to the application. On May 25, 2017, the KPSC issued an order to approve the stipulation with certain modifications. On June 1, 2017, Duke Energy Kentucky filed its acceptance of the modifications. The deployment of AMI meters began in third quarter 2017 and is expected to be completed in early 2019. Duke Energy Ohio has approximately $6 million included in Regulatory assets on its Consolidated Balance Sheets at December 31, 2017, for the book value of existing meter equipment.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Accelerated Natural Gas Service Line Replacement Rider
On January 20, 2015, Duke Energy Ohio filed an application for approval of an accelerated natural gas service line replacement program (ASRP). Under the ASRP, Duke Energy Ohio proposed to replace certain natural gas service lines on an accelerated basis over a 10-year period. Duke Energy Ohio also proposed to complete preliminary survey and investigation work related to natural gas service lines that are customer owned and for which it does not have valid records and, further, to relocate interior natural gas meters to suitable exterior locations where such relocation can be accomplished. Duke Energy Ohio's projected total capital and operations and maintenance expenditures under the ASRP were approximately $240 million. The filing also sought approval of a rider mechanism (Rider ASRP) to recover related expenditures. Duke Energy Ohio proposed to update Rider ASRP on an annual basis. Intervenors opposed the ASRP, primarily because they believe the program is neither required nor necessary under federal pipeline regulation. On October 26, 2016, the PUCO issued an order denying the proposed ASRP. Duke Energy Ohio's application for rehearing of the PUCO decision was denied on May 17, 2017.
Energy Efficiency Cost Recovery
On March 28, 2014, Duke Energy Ohio filed an application for recovery of program costs, lost distribution revenue and performance incentives related to its energy efficiency and peak demand reduction programs. These programs are undertaken to comply with environmental mandates set forth in Ohio law. The PUCO approved Duke Energy Ohio’s application but found that Duke Energy Ohio was not permitted to use banked energy savings from previous years in order to calculate the amount of allowed incentive. This conclusion represented a change to the cost recovery mechanism that had been agreed upon by intervenors and approved by the PUCO in previous cases. The PUCO granted the applications for rehearing filed by Duke Energy Ohio and an intervenor. On January 6, 2016, Duke Energy Ohio and the PUCO Staff entered into a stipulation, pending the PUCO's approval, to resolve issues related to performance incentives and the PUCO Staff audit of 2013 costs, among other issues. In December 2015, based upon the stipulation, Duke Energy Ohio re-established approximately $20 million of the revenues that had been previously reversed. On October 26, 2016, the PUCO issued an order approving the stipulation without modification. In December 2016, the PUCO granted the intervenors request for rehearing for the purpose of further review. Duke Energy Ohio cannot predict the outcome of this matter.
On June 15, 2016, Duke Energy Ohio filed an application for approval of a three-year energy efficiency and peak demand reduction portfolio of programs. A stipulation and modified stipulation were filed on December 22, 2016, and January 27, 2017, respectively. Under the terms of the stipulations, which included support for deferral authority of all costs and a cap on shared savings incentives, Duke Energy Ohio offered its energy efficiency and peak demand reduction programs throughout 2017. On February 3, 2017, Duke Energy Ohio filed for deferral authority of its costs incurred in 2017 in respect of its proposed energy efficiency and peak demand reduction portfolio. On September 27, 2017, the PUCO issued an order approving a modified stipulation. The modifications impose an annual cap of approximately $38 million on program costs and shared savings incentives combined, but allowed for Duke Energy Ohio to file for a waiver of costs in excess of the cap in 2017. The PUCO approved the waiver request up to a total cost of $56 million. On November 21, 2017, the PUCO granted Duke Energy Ohio's and intervenor's applications for rehearing of the September 27, 2017, order. On January 10, 2018, the PUCO denied the Ohio Consumers' Counsel’s application for rehearing of the PUCO order granting Duke Energy Ohio's waiver request. Duke Energy Ohio cannot predict the outcome of this matter.
2014 Electric Security Plan
In April 2015, the PUCO modified and approved Duke Energy Ohio's proposed electric security plan (ESP), with a three-year term and an effective date of June 1, 2015. The PUCO approved a competitive procurement process for SSO load, a distribution capital investment rider and a tracking mechanism for incremental distribution expenses caused by major storms. The PUCO also approved a placeholder tariff for a price stabilization rider, but denied Duke Energy Ohio's specific request to include Duke Energy Ohio's entitlement to generation from OVEC in the rider at this time; however, the order allows Duke Energy Ohio to submit additional information to request recovery in the future. On May 4, 2015, Duke Energy Ohio filed an application for rehearing requesting the PUCO to modify or amend certain aspects of the order. On May 28, 2015, the PUCO granted all applications for rehearing filed in the case for future consideration. Duke Energy Ohio cannot predict the outcome of the appeals in this matter.
2012 Natural Gas Rate Case/MGP Cost Recovery
On November 13, 2013, the PUCO issued an order approving a settlement of Duke Energy Ohio’s natural gas base rate case and authorizing the recovery of costs incurred between 2008 and 2012 for environmental investigation and remediation of two former MGP sites. The PUCO order also authorized Duke Energy Ohio to continue deferring MGP environmental investigation and remediation costs incurred subsequent to 2012 and to submit annual filings to adjust the MGP rider for future costs. Intervening parties appealed this decision to the Ohio Supreme Court and on June 29, 2017, the Ohio Supreme Court issued its decision affirming the PUCO order. Appellants filed a request for reconsideration, which was denied on September 27, 2017. This matter is now final.
The PUCO order also contained deadlines for completing the MGP environmental investigation and remediation costs at the MGP sites. For the property known as the East End site, the PUCO order established a deadline of December 31, 2016, which was subsequently extended to December 31, 2019. In January 2017, intervening parties filed for rehearing of the PUCO's decision. On February 8, 2017, the PUCO denied the rehearing request. As of December 31, 2017, Duke Energy Ohio had approximately, $35 million included in Regulatory assets on the Consolidated Balance Sheets for future remediation costs expected to be incurred at the East End site.
Regional Transmission Organization Realignment
Duke Energy Ohio, including Duke Energy Kentucky, transferred control of its transmission assets from MISO to PJM Interconnection, LLC (PJM), effective December 31, 2011. The PUCO approved a settlement related to Duke Energy Ohio’s recovery of certain costs of the Regional Transmission Organization (RTO) realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MISO Transmission Expansion Planning (MTEP) costs, including but not limited to Multi Value Project (MVP) costs, directly or indirectly charged to Ohio customers. Duke Energy Ohio also agreed to vigorously defend against any charges for MVP projects from MISO. The KPSC also approved a request to effect the RTO realignment, subject to a commitment not to seek double recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio’s recorded liability for its exit obligation and share of MTEP costs, excluding MVP, recorded within Other in Current liabilities and Other in Other Noncurrent Liabilities on the Consolidated Balance Sheets. The retail portions of MTEP costs billed by MISO are recovered by Duke Energy Ohio through a non-bypassable rider. As of December 31, 2017, and 2016, $50 million and $71 million are recorded in Regulatory assets on Duke Energy Ohio's Consolidated Balance Sheets, respectively. |
| | | | | | | | | | | | | | | |
| | | | Provisions/ |
| | Cash |
| | |
| (in millions) | December 31, 2016 |
| | Adjustments |
| | Reductions |
| | December 31, 2017 |
|
| Duke Energy Ohio | $ | 90 |
| | $ | (20 | ) | | $ | (4 | ) | | $ | 66 |
|
MVP. MISO approved 17 MVP proposals prior to Duke Energy Ohio’s exit from MISO on December 31, 2011. Construction of these projects is expected to continue through 2020. Costs of these projects, including operating and maintenance costs, property and income taxes, depreciation and an allowed return, are allocated and billed to MISO transmission owners.
On December 29, 2011, MISO filed a tariff with the FERC providing for the allocation of MVP costs to a withdrawing owner based on monthly energy usage. The FERC set for hearing (i) whether MISO’s proposed cost allocation methodology to transmission owners who withdrew from MISO prior to January 1, 2012, is consistent with the tariff at the time of their withdrawal from MISO and, (ii) if not, what the amount of and methodology for calculating any MVP cost responsibility should be. In 2012, MISO estimated Duke Energy Ohio’s MVP obligation over the period from 2012 to 2071 at $2.7 billion, on an undiscounted basis. On July 16, 2013, a FERC Administrative Law Judge (ALJ) issued an initial decision. Under this initial decision, Duke Energy Ohio would be liable for MVP costs. Duke Energy Ohio filed exceptions to the initial decision, requesting FERC to overturn the ALJ’s decision.
On October 29, 2015, the FERC issued an order reversing the ALJ's decision. The FERC ruled the cost allocation methodology is not consistent with the MISO tariff and that Duke Energy Ohio has no liability for MVP costs after its withdrawal from MISO. On May 19, 2016, the FERC denied the request for rehearing filed by MISO and the MISO Transmission Owners. On July 15, 2016, the MISO Transmission Owners filed a petition for review with the U.S. Court of Appeals for the Sixth Circuit. On June 21, 2017, a three-judge panel affirmed FERC's 2015 decision holding that Duke Energy Ohio has no liability for the cost of the MVP projects constructed after Duke Energy Ohio's withdrawal from MISO. MISO did not file further petitions for review and this matter is now final.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy Indiana
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on Duke Energy Indiana's Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
| AROs - coal ash | $ | 380 |
| $ | 276 |
| | | (b) |
| Accrued pension and OPEB | 197 |
| 222 |
| | | (g) |
Retired generation facilities(c) | 65 |
| 73 |
| | X | 2025 |
| Net regulatory asset related to income taxes | — |
| 119 |
| | | (d) |
| Hedge costs deferrals | 25 |
| 26 |
| | | (b) |
| DSM/EE | 21 |
| — |
| | (e) | (e) |
| Vacation accrual | 11 |
| 10 |
| | | 2018 |
| Deferred fuel and purchased power | 18 |
| 40 |
| | | 2018 |
PISCC and deferred operating expenses(c) | 274 |
| 281 |
| | X | (b) |
Gasification services agreement buyout(f) | — |
| 8 |
| | | |
AMI(c) | 21 |
| 46 |
| | X | (b) |
| Other | 131 |
| 121 |
| | | (b) |
| Total regulatory assets | 1,143 |
| 1,222 |
| | | |
| Less: current portion | 165 |
| 149 |
| | | |
| Total noncurrent regulatory assets | $ | 978 |
| $ | 1,073 |
| | | |
Regulatory Liabilities(a) | | | | | |
| Costs of removal | $ | 644 |
| $ | 660 |
| | | (d) |
| Net regulatory liability related to income taxes | 998 |
| — |
| | | (b) |
| Amounts to be refunded to customers | 10 |
| 45 |
| | | 2018 |
| Accrued pension and OPEB | 64 |
| 72 |
| | | (g) |
| Other | 31 |
| 11 |
| | | (b) |
| Total regulatory liabilities | 1,747 |
| 788 |
| | | |
| Less: current portion | 24 |
| 40 |
| | | |
| Total noncurrent regulatory liabilities | $ | 1,723 |
| $ | 748 |
| | | |
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Included in rate base. |
| |
| (d) | Recovery over the life of the associated assets. |
| |
| (e) | Includes incentives on DSM/EE investments and is recovered through a tracker mechanism over a two-year period. |
| |
| (f) | The IURC authorized Duke Energy Indiana to recover costs incurred to buy out a gasification services agreement, including carrying costs through 2017. |
| |
| (g) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
Coal Combustion Residual Plan
On March 17, 2016, Duke Energy Indiana filed with the IURC a request for approval of its first group of federally mandated CCR rule compliance projects (Phase I CCR Compliance Projects) to comply with the EPA's CCR rule. The projects in this Phase I filing are CCR compliance projects, including the conversion of Cayuga and Gibson stations to dry bottom ash handling and related water treatment. Duke Energy Indiana requested timely recovery of approximately $380 million in retail capital costs, including AFUDC, and recovery of incremental operating and maintenance costs under a federal mandate tracker that provides for timely recovery of 80 percent of such costs and deferral with carrying costs of 20 percent of such costs for recovery in a subsequent retail base rate case. On January 24, 2017, Duke Energy Indiana and various intervenors filed a settlement agreement with the IURC. Terms of the settlement include recovery of 60 percent of the estimated CCR compliance construction project capital costs through existing rider mechanisms and deferral of 40 percent of these costs until Duke Energy Indiana's next general retail rate case. The deferred costs will earn a return based on Duke Energy Indiana's long-term debt rate of 4.73 percent until costs are included in retail rates, at which time the deferred costs will earn a full return. Costs are to be capped at $365 million, plus actual AFUDC. Costs above the cap would be considered for recovery in the next rate case. Terms of the settlement agreement also require Duke Energy Indiana to perform certain reporting and groundwater monitoring. On May 24, 2017, the IURC approved the settlement agreement.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Edwardsport Integrated Gasification Combined Cycle Plant
Costs for the Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant are recovered from retail electric customers via a tracking mechanism (IGCC rider) with updates filed by Duke Energy Indiana. The IGCC Plant was placed into commercial operation in June 2013.
On August 24, 2016, the IURC approved a settlement (IGCC Settlement) among Duke Energy Indiana and several intervenors to resolve disputes related to five IGCC riders (the 11th through 15th) and a subdocket to Duke Energy Indiana's fuel adjustment clause. The IGCC settlement resulted in customers not being billed for previously incurred plant operating costs of $87.5 million and payments and commitments from Duke Energy Indiana of $5.5 million for attorneys’ fees and consumer programs funding. Duke Energy Indiana recognized pretax impairment and related charges of $93 million in 2015. Additionally, under the IGCC settlement, the recovery of operating and maintenance expenses and ongoing maintenance capital at the plant were subject to certain caps during the years of 2016 and 2017. The IGCC settlement also included a commitment to either retire or stop burning coal by December 31, 2022, at the Gallagher Station. Pursuant to the IGCC settlement, the in-service date used for accounting and ratemaking will remain as June 2013. Remaining deferred costs will be recovered over eight years beginning in 2016 and not earn a carrying cost. As of December 31, 2017, deferred costs related to the project are approximately $152 million and are included in Regulatory assets in Current Assets and Other Noncurrent Assets on Duke Energy Indiana's Consolidated Balance Sheets. Under the IGCC settlement, future IGCC riders will be filed annually with the next filing scheduled for first quarter 2018.
The ninth semi-annual IGCC rider order was appealed by various intervenors and the matter was remanded to the IURC for further proceedings and additional findings on a tax in-service issue. On February 2, 2017, the IURC issued an order upholding the original decision, finding that an estimate of impact on customer rates due to the federal income tax in-service determination was reasonable.
FERC Transmission Return on Equity Complaint
Customer groups have filed with the FERC complaints against MISO and its transmission-owning members, including Duke Energy Indiana, alleging, among other things, that the current base rate of return on equity earned by MISO transmission owners of 12.38 percent is unjust and unreasonable. The complaints claim, among other things, that the current base rate of return on equity earned by MISO transmission owners should be reduced to 8.67 percent. On January 5, 2015, the FERC issued an order accepting the MISO transmission owners' adder of 0.50 percent to the base rate of return on equity based on participation in an RTO subject to it being applied to a return on equity that is shown to be just and reasonable in the pending return on equity complaints. On December 22, 2015, the presiding FERC ALJ in the first complaint issued an Initial Decision in which the base rate of return on equity was set at 10.32 percent. On September 28, 2016, the Initial Decision in the first complaint was affirmed by FERC, but is subject to rehearing requests. On June 30, 2016, the presiding FERC ALJ in the second complaint issued an Initial Decision setting the base rate of return on equity at 9.70 percent. The Initial Decision in the second complaint is pending FERC review. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit, in Emera Maine v. FERC, reversed and remanded certain aspects of the methodology employed by FERC to establish rates of return on equity. This decision may affect the outcome of the complaints against Duke Energy Indiana. Duke Energy Indiana currently believes these matters will not have a material impact on its results of operations, cash flows and financial position.
Grid Infrastructure Improvement Plan
On December 7, 2015, Duke Energy Indiana filed a grid infrastructure improvement plan with an estimated cost of $1.8 billion in response to guidance from IURC orders and the Indiana Court of Appeals decisions related to a new statute. The plan uses a combination of advanced technology and infrastructure upgrades to improve service to customers and provide them with better information about their energy use. It also provides for cost recovery through a transmission and distribution rider (T&D Rider). In March 2016, Duke Energy Indiana entered into a settlement with all parties to the proceeding except the Citizens Action Coalition of Indiana, Inc. The settlement agreement decreased the capital expenditures eligible for timely recovery of costs in the seven-year plan to approximately $1.4 billion, including the removal of an AMI project. Under the settlement, the return on equity to be used in the T&D Rider is 10 percent. The IURC approved the settlement and issued a final order on June 29, 2016. The order was not appealed and the proceeding is concluded.
The settlement agreement provided for deferral accounting for depreciation and post-in-service carrying costs for AMI projects outside the plan. Duke Energy Indiana withdrew its request for a regulatory asset for current meters and will retain any savings associated with future AMI installation until the next retail base rate case, which is required to be filed prior to the end of the plan. During the third quarter of 2016, Duke Energy Indiana decided to implement the AMI project. This decision resulted in a pretax impairment charge related to existing or non-AMI meters of approximately $8 million in 2016, based in part on the requirement to file a base rate case in 2022 under the approved plan. Duke Energy Indiana evaluates the need for rate cases as part of its business planning, based on the outlook of emerging costs, ongoing investment and impact related to the Tax Act enacted in late 2017 and expects to file a rate case prior to the 2022 requirement. As a result, in 2017, Duke Energy Indiana recorded an additional impairment charge of approximately $22 million. As of December 31, 2017, Duke Energy Indiana's remaining net book value of non-AMI meters is approximately $21 million and will be depreciated through July 2020.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Benton County Wind Farm Dispute
On December 16, 2013, Benton County Wind Farm LLC (BCWF) filed a lawsuit against Duke Energy Indiana seeking damages for past generation losses alleging Duke Energy Indiana violated its obligations under a 2006 PPA by refusing to offer electricity to the market at negative prices. Damage claims continue to increase during times that BCWF is not dispatched. Under 2013 revised MISO market rules, Duke Energy Indiana is required to make a price offer to MISO for the power it proposes to sell into MISO markets and MISO determines whether BCWF is dispatched. Because market prices would have been negative due to increased market participation, Duke Energy Indiana determined it would not bid at negative prices in order to balance customer needs against BCWF's need to run. BCWF contends Duke Energy Indiana must bid at the lowest negative price to ensure dispatch, while Duke Energy Indiana contends it is not obligated to bid at any particular price, that it cannot ensure dispatch with any bid and that it has reasonably balanced the parties' interests. On July 6, 2015, the U.S. District Court for the Southern District of Indiana entered judgment against BCWF on all claims. BCWF appealed the decision and on December 9, 2016, the appeals court ruled in favor of BCWF. Duke Energy Indiana recorded an obligation and a regulatory asset related to the settlement amount in fourth quarter 2016. On June 30, 2017, the parties finalized a settlement agreement. Terms of the settlement included Duke Energy Indiana paying $29 million for back damages. Additionally, the parties agreed on the method by which the contract will be bid into the market in the future. The settlement amount was paid in June 2017. The IURC issued an order on September 27, 2017, approving recovery of the settlement amount through Duke Energy Indiana's fuel clause. The IURC order has been appealed to the Indiana Court of Appeals. Duke Energy Indiana cannot predict the outcome of this matter.
Piedmont
Regulatory Assets and Liabilities
The following tables present the regulatory assets and liabilities recorded on Piedmont's Consolidated Balance Sheets. |
| | | | | | | | | |
| | December 31, | | Earns/Pays | Recovery/Refund |
| (in millions) | 2017 |
| 2016 |
| | a Return | Period Ends |
Regulatory Assets(a) | | | | | |
| AROs - other | $ | 15 |
| $ | 14 |
| | | (d) |
Accrued pension and OPEB(c) | 91 |
| 166 |
| | | (f) |
| Derivatives - gas supply contracts | 142 |
| 187 |
| | | (e) |
Vacation accrual(c) | 10 |
| 13 |
| | | 2018 |
Deferred pipeline integrity costs(c) | 42 |
| 36 |
| | | 2018 |
| Amount due from customers | 64 |
| 66 |
| | X | (b) |
| Other | 14 |
| 15 |
| | | (b) |
| Total regulatory assets | 378 |
| 497 |
| | | |
| Less: current portion | 95 |
| 124 |
| | | |
| Total noncurrent regulatory assets | $ | 283 |
| $ | 373 |
| | | |
Regulatory Liabilities(a) | | | | | |
| Costs of removal | $ | 544 |
| $ | 528 |
| | | (d) |
| Net regulatory liability related to income taxes | 597 |
| 80 |
| | | (b) |
| Other | 3 |
| — |
| | | (b) |
| Total regulatory liabilities | 1,144 |
| 608 |
| | | |
| Less: current portion | 3 |
| — |
| | | |
| Total noncurrent regulatory liabilities | $ | 1,141 |
| $ | 608 |
| | | |
| |
| (a) | Regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| |
| (b) | The expected recovery or refund period varies or has not been determined. |
| |
| (c) | Included in rate base. |
| |
| (d) | Recovery over the life of the associated assets. |
| |
| (e) | Balance will fluctuate with changes in the market. Current contracts extend into 2031. |
| |
| (f) | Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail. |
South Carolina Rate Stabilization Adjustment Filing
In June 2017, Piedmont filed with the PSCSC under the South Carolina Rate Stabilization Act its quarterly monitoring report for the 12-month period ending March 31, 2017. The filing included a revenue deficiency calculation and tariff rates in order to permit Piedmont the opportunity to earn the rate of return on equity of 12.6 percent established in its last general rate case. On October 4, 2017, the PSCSC approved a settlement agreement between Piedmont and the SC Office of Regulatory Staff. Terms of the settlement included implementation of rates for the 12-month period beginning November 2017 with a return on equity of 10.2 percent.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
North Carolina Integrity Management Rider Filings
In October 2017, Piedmont filed a petition with the TRA seeking authorityNCUC under the Integrity Management Rider (IMR) mechanism to collect an additional $6.5$8.9 million in annual IMR margin revenues, effective January 2015December 2017, based on $54 million ofthe eligible capital investments inclosed to integrity and safety projects over the twelve-monthsix-month period ending October 31, 2014. We are waiting on a ruling fromSeptember 30, 2017. On November 28, 2017, the TRA at this time.
NCUC approved the requested rate adjustment.
In February 2014, weMay 2017, Piedmont filed, and the NCUC approved, a petition under the IMR mechanism to collect an additional $11.6 million in annual revenues, effective June 2017, based on the eligible capital investments closed to integrity and safety projects over the six-month period ending March 31, 2017.
Tennessee Integrity Management Rider Filing
In November 2017, Piedmont filed a petition with the TRATPUC under the IMR mechanism to authorize us to amortize and refund $4.7collect an additional $3.3 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waitingin annual revenues, effective January 2018, based on a ruling from the TRA at this time.
In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of oureligible capital investments closed to integrity and safety projects over the 12-month period ending October 31, 2017. In January 2018, Piedmont filed an amended computation under the IMR mechanism, revising the proposed increase in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the tariff rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014annual revenues to approximately $0.4 million based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of generalthe decrease in the corporate federal income tax rate cases for the return of and on these capital investments. In November 2014, the TRA consolidated this docket with a separate petition we filed seeking modifications to our tariff regarding service to customers using natural gas as a motor fuel. The TRA suspended the proposed tariffs through February 9, 2015.effective January 1, 2018. A hearing on this matter has beenis scheduled for March 2018.
OTHER REGULATORY MATTERS
Atlantic Coast Pipeline
On September 2, 2014, Duke Energy, Dominion Resources (Dominion), Piedmont and Southern Company Gas announced the formation of Atlantic Coast Pipeline, LLC (ACP) to build and own the proposed Atlantic Coast Pipeline (ACP pipeline), an approximately 600-mile interstate natural gas pipeline running from West Virginia to North Carolina. The ACP pipeline is designed to meet, in part, the needs identified by Duke Energy Carolinas, Duke Energy Progress and Piedmont. Dominion will build and operate the ACP pipeline and holds a leading ownership percentage in ACP of 48 percent. Duke Energy owns a 47 percent interest through its Gas Utilities and Infrastructure segment. Southern Company Gas maintains a 5 percent interest. See Notes 12 and 17 for additional information related to Duke Energy's ownership interest.
Duke Energy Carolinas, Duke Energy Progress and Piedmont, among others, will be customers of the pipeline. Purchases will be made under several 20-year supply contracts, subject to state regulatory approval. On September 18, 2015, ACP filed an application with the FERC requesting a CPCN authorizing ACP to construct the pipeline. ACP executed a construction agreement in September 2016. ACP also requested approval of an open access tariff and the precedent agreements it entered into with future pipeline customers. In December 2016, FERC issued a draft Environmental Impact Statement (EIS) indicating that the proposed pipeline would not cause significant harm to the environment or protected populations. The FERC issued the final EIS in July 2017. On October 13, 2017, FERC issued an order approving the CPCN, subject to conditions. On October 16, 2017, ACP accepted the FERC order subject to reserving its right to file a request for rehearing or clarification on a timely basis. On November 9, 2017, ACP filed a request for rehearing on several limited issues. On December 12, 2017, ACP filed an answer to intervenors’ request for rehearing of the certificate order and for stay of the certificate order.
In December 2017, West Virginia issued a waiver of the state water quality permit in reliance on the U.S. Army Corps of Engineers national water quality permit and Virginia issued a conditional water quality permit subject to completion of additional studies and stormwater plans. In early 2018, the FERC issued a series of Partial Notices to Proceed which authorized the project to begin limited construction-related activities along the pipeline route. North Carolina issued the state water quality permit in January 12, 2015.
All States
2018. The project remains subject to other pending federal and state approvals, which will allow full construction activities to begin. The ACP pipeline project has a targeted in-service date of late 2019.
Due to delays in obtaining the seasonal naturerequired permits to commence construction and the conditions imposed upon the project by the permits, ACP's project manager estimates the project's pipeline development costs have increased from a range of our business, we contract with customers$5.0 billion to $5.5 billion to a range of $6.0 billion and $6.5 billion, excluding financing costs. Project construction activities, schedule and final costs are still subject to uncertainty due to potential additional permitting delays, construction productivity and other conditions and risks which could result in potential higher project costs and a potential delay in the targeted in-service date.
Sabal Trail Transmission Pipeline
On May 4, 2015, Duke Energy acquired a 7.5 percent ownership interest in Sabal Trail Transmission, LLC (Sabal Trail) from Spectra Energy Partners, LP, a master limited partnership, formed by Enbridge Inc. (formerly Spectra Energy Corp.). Spectra Energy Partners, LP holds a 50 percent ownership interest in Sabal Trail and NextEra Energy has a 42.5 percent ownership interest. Sabal Trail is a joint venture to construct a 515-mile natural gas pipeline (Sabal Trail pipeline) to transport natural gas to Florida. Total estimated project costs are approximately $3.2 billion. The Sabal Trail pipeline traverses Alabama, Georgia and Florida. The primary customers of the Sabal Trail pipeline, Duke Energy Florida and Florida Power & Light Company (FP&L), have each contracted to buy pipeline capacity for 25-year initial terms. See Notes 12 and 17 for additional information.
On February 3, 2016, the FERC issued an order granting the request for a CPCN to construct and operate the pipeline. The Sabal Trail pipeline received other required regulatory approvals and the phase one mainline was placed in service in July 2017. On October 12, 2017, Sabal Trail filed a request with FERC to place in-service a lateral line to Duke Energy Florida's Citrus County Combined Cycle facility, which remains pending. This request is required to support commissioning and testing activities at the facility.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
On September 21, 2016, intervenors filed an appeal of FERC's CPCN orders to the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals). On August 22, 2017, the appeals court ruled against FERC in the case for failing to include enough information on the impact of greenhouse-gas emissions carried by the pipeline, vacated the CPCN order and remanded the case to FERC. In response to the August 2017 court decision, the FERC issued a draft Supplemental Environmental Impact Statement (SEIS) on September 27, 2017. On October 6, 2017, FERC and a group of industry intervenors, including Sabal Trail and Duke Energy Florida, filed separate petitions with the D.C. Circuit Court of Appeals requesting rehearing regarding the court's decision to vacate the CPCN order. On January 31, 2018, the D.C. Circuit Court of Appeals denied the requests for rehearing. On February 2, 2018, Sabal Trail filed a request with FERC for expedited issuance of its order on remand and reissuance of the CPCN. In the alternative, the pipeline requested that FERC issue a temporary emergency CPCN to allow for continued operations. On February 5, 2018, FERC issued the final SEIS but did not issue the order on remand. On February 6, 2018, FERC and the intervenors in this case each filed motions for stay with the D.C. Circuit Court to stay the court's mandate. The February 6, 2018 motions automatically stay the issuance of the court’s mandate until the later of seven days after the court denies the motions or the expiration of any stay granted by the court. Both motions are pending. Sabal Trail will continue to monitor the progress and the impact to the project going forward.
Constitution Pipeline
Duke Energy owns a 24 percent ownership interest in Constitution Pipeline Company, LLC (Constitution). Constitution is a natural gas pipeline project slated to transport natural gas supplies from the Marcellus supply region in northern Pennsylvania to major northeastern markets. The pipeline will be constructed and operated by Williams Partners L.P., which has a 41 percent ownership share. The remaining interest is held by Cabot Oil and Gas Corporation and WGL Holdings, Inc. Before the permitting delays discussed below, Duke Energy's total anticipated contributions were approximately $229 million. As a result of the permitting delays and project uncertainty, total anticipated contributions by Duke Energy can no longer be reasonably estimated.
In December 2014, Constitution received approval from the FERC to construct and operate the proposed pipeline. However, on April 22, 2016, the New York State Department of Environmental Conservation (NYSDEC) denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit (U.S. Court of Appeals) challenging the legality and appropriateness of the NYSDEC’s decision and on August 18, 2017, the petition was denied in part and dismissed in part. In September 2017, Constitution filed a petition for a rehearing of portions of the decision unrelated to the water quality certification, which was denied by the U.S. Court of Appeals. In January 2018, Constitution petitioned the Supreme Court of the United States to review the U.S. Court of Appeals decision. In October 2017, Constitution filed a petition for declaratory order requesting FERC to find that the NYSDEC waived its rights to issue a Section 401 water quality certification by not acting on Constitution's application within a reasonable period of time as required by statute. This petition was based on precedent established by another pipeline’s successful petition with FERC following a District of Columbia Circuit Court ruling. On January 11, 2018, FERC denied Constitution's petition. In February 2018, Constitution filed a rehearing request with FERC of its finding that the NYSDEC did not waive the Section 401 certification requirement. Constitution is currently unable to approximate an in-service date for the project due to the NYDSEC's denial of the water quality certification. The Constitution partners remain committed to the project and are evaluating next steps to move the project forward. Duke Energy cannot predict the outcome of this matter.
Since April 2016, with the actions of the NYSDEC, Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved.
See Notes 12 and 17 for additional information related to ownership interest and carrying value of the investment.
Progress Energy Merger FERC Mitigation
Following the closing of the Progress Energy merger, outside counsel reviewed Duke Energy’s long-term FERC mitigation plan and discovered a technical error in the calculations. On December 6, 2013, Duke Energy submitted a filing to the FERC disclosing the error and arguing that no additional mitigation is necessary. The city of New Bern filed a protest and requested that FERC order additional mitigation. On October 29, 2014, the FERC ordered that the amount of the stub mitigation be increased from 25 MW to 129 MW. The stub mitigation is Duke Energy’s commitment to set aside for third parties a certain quantity of firm transmission capacity from Duke Energy Carolinas to Duke Energy Progress during summer off-peak hours. The FERC also ordered that Duke Energy operate certain phase shifters to create additional import capability and that such operation be monitored by an independent monitor. The costs to comply with this order are not material. The FERC also referred Duke Energy’s failure to expressly designate the phase shifter reactivation as a mitigation project in the original mitigation plan filing in March 2012 to the FERC Office of Enforcement for further inquiry. In response, and since December 2014, the FERC Office of Enforcement has been conducting a nonpublic investigation of Duke Energy's market power analyses included in the Progress merger filings submitted to FERC. Duke Energy cannot predict the outcome of this investigation.
Potential Coal Plant Retirements
The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and options being considered to meet those needs. Recent IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in Florida and Indiana earlier than their current estimated useful lives primarily because facilities do not have the requisite emission control equipment to meet EPA regulations recently approved or proposed.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The table below contains the net carrying value of generating facilities planned for retirement or included in recent IRPs as evaluated for potential retirement due to a lack of requisite environmental control equipment. Dollar amounts in the table below are included in Net property, plant and equipment on the Consolidated Balance Sheets as of December 31, 2017, and exclude capitalized asset retirement costs. |
| | | | | | |
| | | | Remaining Net |
|
| | Capacity |
| | Book Value |
|
| | (in MW) |
| | (in millions) |
|
| Duke Energy Carolinas | | | |
Allen Steam Station Units 1-3(a) | 585 |
| | $ | 163 |
|
| Progress Energy and Duke Energy Florida | | | |
Crystal River Units 1 and 2(b) | 873 |
| | 107 |
|
| Duke Energy Indiana | | | |
Gallagher Units 2 and 4(c) | 280 |
| | 127 |
|
| Total Duke Energy | 1,738 |
| | $ | 397 |
|
| |
| (a) | Duke Energy Carolinas will retire Allen Steam Station Units 1 through 3 by December 31, 2024, as part of the resolution of a lawsuit involving alleged New Source Review violations. |
| |
| (b) | Duke Energy Florida expects to retire these coal units by the end of 2018 to comply with environmental regulations. |
| |
| (c) | Duke Energy Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the settlement of Edwardsport IGCC matters. |
Refer to the "Western Carolinas Modernization Plan" discussion above for details of Duke Energy Progress' planned retirements.
5. COMMITMENTS AND CONTINGENCIES
INSURANCE
General Insurance
The Duke Energy Registrants have insurance and reinsurance coverage either directly or through indemnification from Duke Energy’s captive insurance company, Bison, and its affiliates, consistent with companies engaged in similar commercial operations with similar type properties. The Duke Energy Registrants’ coverage includes (i) commercial general liability coverage for liabilities arising to third parties for bodily injury and property damage; (ii) workers’ compensation; (iii) automobile liability coverage; and (iv) property coverage for all real and personal property damage. Real and personal property damage coverage excludes electric transmission and distribution lines, but includes damages arising from boiler and machinery breakdowns, earthquakes, flood damage and extra expense, but not outage or replacement power coverage. All coverage is subject to certain deductibles or retentions, sublimits, exclusions, terms and conditions common for companies with similar types of operations. The Duke Energy Registrants self-insure their electric transmission and distribution lines against loss due to storm damage and other natural disasters. As discussed further in Note 4, Duke Energy Florida maintains a storm damage reserve and has a regulatory mechanism to recover the cost of named storms on an expedited basis.
The cost of the Duke Energy Registrants’ coverage can fluctuate from year to year reflecting claims history and conditions of the insurance and reinsurance markets.
In the event of a loss, terms and amounts of insurance and reinsurance available might not be adequate to cover claims and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on the Duke Energy Registrants’ results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.
Nuclear Insurance
Duke Energy Carolinas owns and operates the McGuire Nuclear Station (McGuire) and the Oconee Nuclear Station (Oconee) and operates and has a partial ownership interest in the Catawba Nuclear Station (Catawba). McGuire and Catawba each have two reactors. Oconee has three reactors. The other joint owners of Catawba reimburse Duke Energy Carolinas for certain expenses associated with nuclear insurance per the Catawba joint owner agreements.
Duke Energy Progress owns and operates the Robinson Nuclear Plant (Robinson), Brunswick and Harris. Robinson and Harris each have one reactor. Brunswick has two reactors.
Duke Energy Florida owns Crystal River Unit 3, which permanently ceased operation in 2013 and reached a SAFSTOR condition in January 2018 after the successful transfer of all used nuclear fuel assemblies to an onsite dry cask storage facility.
In the event of a loss, terms and amounts of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material effect on Duke Energy Carolinas’, Duke Energy Progress’ and Duke Energy Florida’s results of operations, cash flows or financial position. Each company is responsible to the extent losses may be excluded or exceed limits of the coverage available.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Nuclear Liability Coverage
The Price-Anderson Act requires owners of nuclear reactors to provide for public nuclear liability protection per nuclear incident up to a maximum total financial protection liability. The maximum total financial protection liability, which is approximately $13.4 billion, is subject to change every five years for inflation and for the number of licensed reactors. Total nuclear liability coverage consists of a combination of private primary nuclear liability insurance coverage and a mandatory industry risk-sharing program to provide for excess nuclear liability coverage above the maximum reasonably available private primary coverage. The U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims.
Primary Liability Insurance
Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida have purchased the maximum reasonably available private primary nuclear liability insurance as required by law, which is $450 million per station.
Excess Liability Program
This program provides $13 billion of coverage per incident through the Price-Anderson Act’s mandatory industrywide excess secondary marketfinancial protection program of risk pooling. This amount is the product of potential cumulative retrospective premium assessments of $127 million times the current 102 licensed commercial nuclear reactors in the U.S. Under this program, licensees could be assessed retrospective premiums to sell supplycompensate for public nuclear liability damages in the event of a nuclear incident at any licensed facility in the U.S. Retrospective premiums may be assessed at a rate not to exceed $19 million per year per licensed reactor for each incident. The assessment may be subject to state premium taxes.
Nuclear Property and capacity assetsAccidental Outage Coverage
Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are members of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company, which provides property damage, nuclear accident decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. Additionally, NEIL provides accidental outage coverage for each station for losses in the event of a major accidental outage at an insured nuclear station.
Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after a qualifying accident and second, to decontaminate the plant before any proceeds can be used for decommissioning, plant repair or restoration.
Losses resulting from acts of terrorism are covered as common occurrences, such that if terrorist acts occur against one or more commercial nuclear power plants insured by NEIL within a 12-month period, they would be treated as one event and the owners of the plants where the act occurred would share one full limit of liability. The full limit of liability is currently $3.2 billion. NEIL sublimits the total aggregate for all of their policies for non-nuclear terrorist events to approximately $1.83 billion.
Each nuclear facility has accident property damage, decontamination and premature decommissioning liability insurance from NEIL with limits of $1.5 billion, except for Crystal River Unit 3. Crystal River Unit 3’s limit is $50 million and is on an actual cash value basis. All nuclear facilities except for Catawba and Crystal River Unit 3 also share an additional $1.25 billion nuclear accident insurance limit above their dedicated underlying limit. This shared additional excess limit is not subject to reinstatement in the event of a loss. Catawba has a dedicated $1.25 billion of additional nuclear accident insurance limit above its dedicated underlying limit. Catawba and Oconee also have an additional $750 million of non-nuclear accident property damage limit. All coverages are subject to sublimits and significant deductibles.
NEIL’s Accidental Outage policy provides some coverage, such as business interruption, for losses in the event of a major accident property damage outage of a nuclear unit. Coverage is provided on a weekly limit basis after a significant waiting period deductible and at 100 percent of the available weekly limits for 52 weeks and 80 percent of the available weekly limits for the next 110 weeks. Coverage is provided until these available weekly periods are met where the accidental outage policy limit will not exceed $490 million for McGuire and Catawba, $462 million for Brunswick, $448 million for Harris, $434 million for Oconee and $378 million for Robinson. NEIL sublimits the accidental outage recovery to the first 104 weeks of coverage not to exceed $328 million from non-nuclear accidental property damage. Coverage amounts decrease in the event more than one unit at a station is out of service due to a common accident. All coverages are subject to sublimits and significant deductibles.
Potential Retroactive Premium Assessments
In the event of NEIL losses, NEIL’s board of directors may assess member companies' retroactive premiums of amounts up to 10 times their annual premiums for up to six years after a loss. NEIL has never exercised this assessment. The maximum aggregate annual retrospective premium obligations for Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida are $146 million, $96 million and $1 million, respectively. Duke Energy Carolinas' maximum assessment amount includes 100 percent of potential obligations to NEIL for jointly owned reactors. Duke Energy Carolinas would seek reimbursement from the joint owners for their portion of these assessment amounts.
ENVIRONMENTAL
The Duke Energy Registrants are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on the Duke Energy Registrants. The following environmental matters impact all of the Duke Energy Registrants.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Remediation Activities
In addition to the ARO recorded as a result of various environmental regulations, discussed in Note 9, the Duke Energy Registrants are responsible for environmental remediation at various sites. These include certain properties that are part of ongoing operations and sites formerly owned or used by Duke Energy entities. These sites are in various stages of investigation, remediation and monitoring. Managed in conjunction with relevant federal, state and local agencies, remediation activities vary based upon site conditions and location, remediation requirements, complexity and sharing of responsibility. If remediation activities involve joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Duke Energy Registrants could potentially be held responsible for environmental impacts caused by other potentially responsible parties and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. Liabilities are recorded when market conditions permit.losses become probable and are reasonably estimable. The total costs that may be incurred cannot be estimated because the extent of environmental impact, allocation among potentially responsible parties, remediation alternatives and/or regulatory decisions have not yet been determined at all sites. Additional costs associated with remediation activities are likely to be incurred in the future and could be significant. Costs are typically expensed as Operation, maintenance and other in the Consolidated Statements of Operations unless regulatory recovery of the costs is deemed probable.
The following tables contain information regarding reserves for probable and estimable costs related to the various environmental sites. These reserves are recorded in Accounts payable within Current Liabilities and Other within Other Noncurrent Liabilities on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Balance at December 31, 2014 | $ | 92 |
| | $ | 10 |
| | $ | 17 |
| | $ | 5 |
| | $ | 12 |
| | $ | 54 |
| | $ | 10 |
|
| Provisions/adjustments | 11 |
| | 1 |
| | 4 |
| | — |
| | 4 |
| | 1 |
| | 5 |
|
| Cash reductions | (9 | ) | | (1 | ) | | (4 | ) | | (2 | ) | | (2 | ) | | (1 | ) | | (3 | ) |
| Balance at December 31, 2015 | 94 |
| | 10 |
| | 17 |
| | 3 |
| | 14 |
| | 54 |
| | 12 |
|
| Provisions/adjustments | 19 |
| | 4 |
| | 7 |
| | 2 |
| | 4 |
| | 7 |
| | 1 |
|
| Cash reductions | (15 | ) | | (4 | ) | | (6 | ) | | (2 | ) | | (4 | ) | | (2 | ) | | (3 | ) |
| Balance at December 31, 2016 | 98 |
| | 10 |
| | 18 |
| | 3 |
| | 14 |
| | 59 |
| | 10 |
|
| Provisions/adjustments | 8 |
| | 3 |
| | 3 |
| | 2 |
| | 2 |
| | 3 |
| | (4 | ) |
| Cash reductions | (25 | ) | | (3 | ) | | (6 | ) | | (2 | ) | | (4 | ) | | (15 | ) | | (1 | ) |
| Balance at December 31, 2017 | $ | 81 |
| | $ | 10 |
| | $ | 15 |
| | $ | 3 |
| | $ | 12 |
| | $ | 47 |
| | $ | 5 |
|
As of December 31, 2016, October 31, 2016, 2015 and 2014, Piedmont's environmental reserve was $1 million. In 2017, a $1 million provision was recorded, resulting in a reserve balance of $2 million at December 31, 2017.
Additional losses in excess of recorded reserves that could be incurred for the stages of investigation, remediation and monitoring for environmental sites that have been evaluated at this time are not material except as presented in the table below. |
| | | |
| (in millions) | |
| Duke Energy | $ | 56 |
|
| Duke Energy Carolinas | 19 |
|
| Duke Energy Ohio | 30 |
|
| Piedmont | 2 |
|
North Carolina and South Carolina we operateAsh Basins
In February 2014, a break in a stormwater pipe beneath an ash basin at Duke Energy Carolinas’ retired Dan River Steam Station caused a release of ash basin water and ash into the Dan River. Duke Energy Carolinas estimates 30,000 to 39,000 tons of ash and 24 million to 27 million gallons of basin water were released into the river. In July 2014, Duke Energy completed remediation work identified by the EPA and continues to cooperate with the EPA's civil enforcement process. Future costs related to the Dan River release, including future state or federal civil enforcement proceedings, future regulatory directives, natural resources damages, future claims or litigation and long-term environmental impact costs, cannot be reasonably estimated at this time.
The North Carolina Department of Environmental Quality (NCDEQ) has historically assessed Duke Energy Carolinas and Duke Energy Progress with Notice of Violations (NOV) for violations that were most often resolved through satisfactory corrective actions and minor, if any, fines or penalties. Subsequent to the Dan River ash release, Duke Energy Carolinas and Duke Energy Progress have been served with a higher level of NOVs, including assessed penalties for violations at L.V. Sutton Combined Cycle Plant (Sutton) and Dan River Steam Station. Duke Energy Carolinas and Duke Energy Progress cannot predict whether the NCDEQ will assess future penalties related to existing unresolved NOVs and if such penalties would be material. See "NCDEQ Notices of Violation" section below for additional discussion.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
LITIGATION
Duke Energy
Duke Energy no longer has exposure to litigation matters related to the International Disposal Group as a result of the divestiture of the business in December 2016. See Note 2 for additional information related to the sale of International Energy.
Ash Basin Shareholder Derivative Litigation
Five shareholder derivative lawsuits were filed in Delaware Chancery Court relating to the release at Dan River and to the management of Duke Energy’s ash basins. On October 31, 2014, the five lawsuits were consolidated in a single proceeding titled In Re Duke Energy Corporation Coal Ash Derivative Litigation. On December 2, 2014, plaintiffs filed a Corrected Verified Consolidated Shareholder Derivative Complaint (Consolidated Complaint). The Consolidated Complaint names as defendants several current and former Duke Energy officers and directors (collectively, the “Duke Energy Defendants”). Duke Energy is named as a nominal defendant.
The Consolidated Complaint alleges the Duke Energy Defendants breached their fiduciary duties by failing to adequately oversee Duke Energy’s ash basins and that these breaches of fiduciary duty may have contributed to the incident at Dan River and continued thereafter. The lawsuit also asserts claims against the Duke Energy Defendants for corporate waste (relating to the money Duke Energy has spent and will spend as a result of the fines, penalties and coal ash removal) and unjust enrichment (relating to the compensation and director remuneration that was received despite these alleged breaches of fiduciary duty). The lawsuit seeks both injunctive relief against Duke Energy and restitution from the Duke Energy Defendants. On January 21, 2015, the Duke Energy Defendants filed a Motion to Stay, which the court granted. The stay was lifted on March 24, 2016, after which plaintiffs filed an Amended Verified Consolidated Shareholder Derivative Complaint (Amended Complaint) making the same allegations as in the Consolidated Complaint. The Duke Energy Defendants filed a motion to dismiss the Amended Complaint on June 21, 2016, which was granted by the Court on December 14, 2016. Plaintiffs filed an appeal to the Delaware Supreme Court on January 9, 2017. Oral argument was held on September 27, 2017. On December 15, 2017, the Delaware Supreme Court affirmed the Chancery Court's order of dismissal.
In addition to the above derivative complaints, in 2014, Duke Energy received two shareholder litigation demand letters. The letters alleged that the members of the Board of Directors and certain officers breached their fiduciary duties by allowing the company to illegally dispose of and store coal ash pollutants. One of the letters also alleged a breach of fiduciary duty in the decision-making relating to the leadership changes following the close of the Progress Energy merger in July 2012. By letter dated September 4, 2015, attorneys for the shareholders were informed that, on the recommendation of the Demand Review Committee formed to consider such matters, the Board of Directors concluded not to pursue potential claims against individuals. One of the shareholders, Mitchell Pinsly, sent a formal demand for records and Duke Energy has responded to this request. There was no follow-up after the records were provided; therefore, this matter has been resolved.
On October 30, 2015, shareholder Saul Bresalier filed a shareholder derivative complaint (Bresalier Complaint) in the U.S. District Court for the District of Delaware. The lawsuit alleges that several current and former Duke Energy officers and directors (Bresalier Defendants) breached their fiduciary duties in connection with coal ash environmental issues, the post-merger change in Chief Executive Officer (CEO) and oversight of political contributions. Duke Energy is named as a nominal defendant. The Bresalier Complaint contends that the Demand Review Committee failed to appropriately consider the shareholder’s earlier demand for litigation and improperly decided not to pursue claims against the Bresalier Defendants. On March 30, 2017, the court granted Defendants’ Motion to Dismiss on the claims relating to coal ash environmental issues and political contributions. As discussed below, a settlement agreement was approved for the merger-related claims in the Bresalier Complaint, and those claims were dismissed. On September 8, 2017, Bresalier filed a notice of appeal to the U.S. Court of Appeals for the Third Circuit (Third Circuit Court) challenging the dismissal of his coal ash and political contribution claims. On January 19 2018, Bresalier filed a stipulation of dismissal, closing this case.
Progress Energy Merger Shareholder Litigation
Duke Energy, the 11 members of the Board of Directors who were also members of the pre-merger Board of Directors (Legacy Duke Energy Directors) and certain Duke Energy officers were defendants in a purported securities class-action lawsuit (Nieman v. Duke Energy Corporation, et al). This lawsuit consolidated three lawsuits originally filed in July 2012. The plaintiffs alleged federal Securities Act of 1933 and Securities Exchange Act of 1934 (Exchange Act) claims based on allegations of materially false and misleading representations and omissions in the Registration Statement filed on July 7, 2011, and purportedly incorporated into other documents, all in connection with the post-merger change in CEO. On August 15, 2014, the parties reached an agreement in principle to settle the litigation. On March 10, 2015, the parties filed a Stipulation of Settlement and a Motion for Preliminary Approval of the Settlement. Under the terms of the agreement, Duke Energy agreed to pay $146 million to settle the claim. On April 22, 2015, Duke Energy made a payment of $25 million into the settlement escrow account. The remainder of $121 million was paid by insurers into the settlement escrow account. The final order approving the settlement was issued on November 2, 2015, thus closing the matter.
On May 31, 2013, the Delaware Chancery Court consolidated four shareholder derivative lawsuits filed in 2012. The Court also appointed a lead plaintiff and counsel for plaintiffs and designated the case as In Re Duke Energy Corporation Derivative Litigation (Merger Chancery Litigation). The lawsuit names as defendants the Legacy Duke Energy Directors. Duke Energy is named as a nominal defendant. The case alleges claims for breach of fiduciary duties of loyalty and care in connection with the post-merger change in CEO.
Two shareholder Derivative Complaints, filed in 2012 in federal district court in Delaware, were consolidated as Tansey v. Rogers, et al. The case alleges claims against the Legacy Duke Energy Directors for breach of fiduciary duty and waste of corporate assets, as well as claims under sharing mechanismsSection 14(a) and 20(a) of the Exchange Act. Duke Energy is named as a nominal defendant. On December 21, 2015, Plaintiff filed a Consolidated Amended Complaint asserting the same claims contained in the original complaints.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The Legacy Duke Energy Directors have reached an agreement-in-principle to settle the Merger Chancery Litigation, conditioned on dismissal as well, of the Tansey v. Rogers, et al case and the merger related claims in the Bresalier Complaint discussed above, which was approved by the NCUCDelaware Chancery Court on July 13, 2017. The entire settlement amount was funded by insurance. The settlement amount, less court-approved attorney fees, totaled $20 million and was paid to Duke Energy in 2017.
Duke Energy Carolinas and Duke Energy Progress
Coal Ash Insurance Coverage Litigation
In March 2017, Duke Energy Carolinas and Duke Energy Progress filed a civil action in North Carolina Superior Court against various insurance providers. The lawsuit seeks payment for coal ash-related liabilities covered by third-party liability insurance policies. The insurance policies were issued between 1971 and 1986 and provide third-party liability insurance for property damage. The civil action seeks damages for breach of contract and indemnification for costs arising from the Coal Ash Act and the PSCSCEPA CCR rule at 15 coal-fired plants in North Carolina and South Carolina. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of this matter.
NCDEQ Notice of Violation
On February 8, 2016, the NCDEQ assessed a penalty of approximately $6.8 million, including enforcement costs, against Duke Energy Carolinas related to stormwater pipes and associated discharges at the Dan River Steam Station. Duke Energy Carolinas recorded a charge in December 2015 for secondary market transactions where 75%this penalty. In March 2016, Duke Energy Carolinas filed an appeal of this penalty. On September 23, 2016, Duke Energy Carolinas entered into a settlement agreement with the NCDEQ, without admission of liability, under which Duke Energy Carolinas agreed to a payment of $6 million to resolve allegations underlying the asserted civil penalty related to the Dan River coal ash release and a March 4, 2016, NOV alleging unpermitted discharges at the facility.
NCDEQ State Enforcement Actions
In the first quarter of 2013, Southern Environmental Law Center (SELC) sent notices of intent to sue Duke Energy Carolinas and Duke Energy Progress related to alleged Clean Water Act (CWA) violations from coal ash basins at two of their coal-fired power plants in North Carolina. The NCDEQ filed enforcement actions against Duke Energy Carolinas and Duke Energy Progress alleging violations of water discharge permits and North Carolina groundwater standards. The cases have been consolidated and are being heard before a single judge in the North Carolina Superior Court.
On August 16, 2013, the NCDEQ filed an enforcement action against Duke Energy Carolinas and Duke Energy Progress related to their remaining plants in North Carolina alleging violations of the net marginsCWA and violations of the North Carolina groundwater standards. Both of these cases have been assigned to the judge handling the enforcement actions discussed above. SELC is representing several environmental groups who have been permitted to intervene in these cases.
The court issued orders in 2016 granting Motions for Partial Summary Judgment for seven of the 14 North Carolina plants with coal ash basins named in the enforcement actions. On February 13, 2017, the court issued an order denying motions for partial summary judgment brought by both the environmental groups and Duke Energy Carolinas and Duke Energy Progress for the remaining seven plants. On March 15, 2017, Duke Energy Carolinas and Duke Energy Progress filed a Notice of Appeal to challenge the trial court’s order. The parties were unable to reach an agreement at mediation in April 2017. The parties submitted briefs to the court on remaining issues to be tried and a ruling is pending. On August 22, 2017, Duke Energy Carolinas and Duke Energy Progress filed a Petition for Discretionary Review, requesting the North Carolina Supreme Court to accept the appeal. On August 24, 2017, SELC filed a motion to dismiss the appeal. Duke Energy Carolinas' and Duke Energy Progress’ opening appellate briefs were filed on October 12, 2017, and briefing is now complete. Argument was held on February 8, 2018.
It is not possible to predict any liability or estimate any damages Duke Energy Carolinas or Duke Energy Progress might incur in connection with these matters.
Federal Citizens Suits
On June 13, 2016, the Roanoke River Basin Association (RRBA) filed a federal citizen suit in the Middle District of North Carolina alleging unpermitted discharges to surface water and groundwater violations at the Mayo Plant. On August 19, 2016, Duke Energy Progress filed a Motion to Dismiss. On April 26, 2017, the court entered an order dismissing four of the claims in the federal citizen suit. Two claims relating to alleged violations of National Pollutant Discharge Elimination System (NPDES) permit provisions survived the motion to dismiss, and Duke Energy Progress filed its response on May 10, 2017. The parties are flowedengaged in pre-trial discovery. Trial has been scheduled for July 9, 2018.
On March 16, 2017, RRBA served Duke Energy Progress with a Notice of Intent to Sue under the CWA for alleged violations of effluent standards and limitations at the Roxboro Plant. In anticipation of litigation, Duke Energy Progress filed a Complaint for Declaratory Relief in the U.S. District Court for the Western District of Virginia on May 11, 2017, which was subsequently dismissed. On May 16, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina which asserts two claims relating to alleged violations of NPDES permit provisions and one claim relating to the use of nearby water bodies. The parties are engaged in pre-trial discovery. Trial has been scheduled for October 1, 2018.
On June 20, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina challenging the closure plans at the Mayo Plant under the EPA CCR Rule. Duke Energy Progress filed a motion to dismiss, which was argued on January 30, 2018.
On August 2, 2017, RRBA filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina challenging the closure plans at the Roxboro Plant under the EPA CCR Rule. Duke Energy Progress filed a motion to dismiss on October 2, 2017.
On December 6, 2017, various parties filed a federal citizen suit in the U.S. District Court for the Middle District of North Carolina for alleged violations at Duke Energy Carolinas' Belews Creek Steam Station (Belews Creek) under the CWA. Duke Energy Carolinas filed a motion to dismiss on February 5, 2018.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
It is not possible to predict whether Duke Energy Carolinas or Duke Energy Progress will incur any liability or to estimate the damages, if any, they might incur in connection with these matters.
Five previously filed cases involving the Riverbend, Cape Fear, H.F. Lee, Sutton and Buck plants have been dismissed or settled during 2016.
Groundwater Contamination Claims
Beginning in May 2015, a number of residents living in the vicinity of the North Carolina facilities with ash basins received letters from the NCDEQ advising them not to drink water from the private wells on their land tested by the NCDEQ as the samples were found to have certain substances at levels higher than the criteria set by the North Carolina Department of Health and Human Services (DHHS). Results of Comprehensive Site Assessments (CSAs) testing performed by Duke Energy under the Coal Ash Act have been consistent with historical data provided to state regulators over many years. The DHHS and NCDEQ sent follow-up letters on October 15, 2015, to residents near coal ash basins who have had their wells tested, stating that private well samplings at a considerable distance from coal ash basins, as well as some municipal water supplies, contain similar levels of vanadium and hexavalent chromium, which led investigators to believe these constituents are naturally occurring. In March 2016, DHHS rescinded the advisories.
Duke Energy Carolinas and Duke Energy Progress have received formal demand letters from residents near Duke Energy Carolinas' and Duke Energy Progress' coal ash basins. The residents claim damages for nuisance and diminution in property value, among other things. The parties held three days of mediation discussions which ended at impasse. On January 6, 2017, Duke Energy Carolinas and Duke Energy Progress received the plaintiffs' notice of their intent to file suits should the matter not settle. The NCDEQ preliminarily approved Duke Energy’s permanent water solution plans on January 13, 2017, and as a result shortly thereafter, Duke Energy issued a press release, providing additional details regarding the homeowner compensation package. This package consists of three components: (i) a $5,000 goodwill payment to each eligible well owner to support the transition to a new water supply, (ii) where a public water supply is available and selected by the eligible well owner, a stipend to cover 25 years of water bills and (iii) the Property Value Protection Plan. The Property Value Protection Plan is a program offered by Duke Energy designed to guarantee eligible plant neighbors the fair market value of their residential property should they decide to sell their property during the time that the plan is offered. Duke Energy Carolinas and Duke Energy Progress recognized reserves of $19 million and $4 million, respectively.
On August 23, 2017, a class-action suit was filed in Wake County Superior Court, North Carolina, against Duke Energy Carolinas and Duke Energy Progress on behalf of certain property owners living near coal ash impoundments at Allen, Asheville, Belews Creek, Buck, Cliffside, Lee, Marshall, Mayo and Roxboro. The class is defined as those who are well-eligible under the Coal Ash Act or those to whom Duke Energy has promised a permanent replacement water supply and seeks declaratory and injunctive relief, along with compensatory damages. Plaintiffs allege that Duke Energy’s improper maintenance of coal ash impoundments caused harm, particularly through groundwater contamination. Despite NCDEQ’s preliminary approval, Plaintiffs contend that Duke Energy’s proposed permanent water solutions plan fails to jurisdictionalcomply with the Coal Ash Act. On September 28, 2017, Duke Energy Carolinas and Duke Energy Progress filed a Motion to Dismiss and Motion to Strike the class designation. The parties entered into a Settlement Agreement on January 24, 2018, which resulted in the dismissal of the underlying class action on January 25, 2018.
On September 14, 2017, a complaint was filed against Duke Energy Progress in New Hanover County Superior Court by a group of homeowners residing approximately 1 mile from Duke Energy Progress' Sutton Steam Plant. The homeowners allege that coal ash constituents have been migrating from ash impoundments at Sutton into their groundwater for decades and that in 2015, Duke Energy Progress discovered these releases of coal ash, but failed to notify any officials or neighbors and failed to take remedial action. The homeowners claim unspecified physical and mental injuries as a result of consuming their well water and seek actual damages for personal injury, medical monitoring and punitive damages. Duke Energy filed its Motion to Dismiss on October 27, 2017, and the hearing is scheduled for March 7, 2018.
It is not possible to estimate the maximum exposure of loss, if any, that may occur in connection with claims which might be made by these residents.
Duke Energy Carolinas
Asbestos-related Injuries and Damages Claims
Duke Energy Carolinas has experienced numerous claims for indemnification and medical cost reimbursement related to asbestos exposure. These claims relate to damages for bodily injuries alleged to have arisen from exposure to or use of asbestos in connection with construction and maintenance activities conducted on its electric generation plants prior to 1985. As of December 31, 2017, there were 161 asserted claims for non-malignant cases with the cumulative relief sought of up to $42 million and 54 asserted claims for malignant cases with the cumulative relief sought of up to $16 million. Based on Duke Energy Carolinas’ experience, it is expected that the ultimate resolution of most of these claims likely will be less than the amount claimed.
Duke Energy Carolinas has recognized asbestos-related reserves of $489 million and $512 million at December 31, 2017, and 2016, respectively. These reserves are classified in Other within Other Noncurrent Liabilities and Other within Current Liabilities on the Consolidated Balance Sheets. These reserves are based upon the minimum amount of the range of loss for current and future asbestos claims through 2037, are recorded on an undiscounted basis and incorporate anticipated inflation. In light of the uncertainties inherent in a longer-term forecast, management does not believe they can reasonably estimate the indemnity and medical costs that might be incurred after 2037 related to such potential claims. It is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy Carolinas has third-party insurance to cover certain losses related to asbestos-related injuries and damages above an aggregate self-insured retention. Duke Energy Carolinas’ cumulative payments began to exceed the self-insurance retention in 2008. Future payments up to the policy limit will be reimbursed by the third-party insurance carrier. The insurance policy limit for potential future insurance recoveries indemnification and medical cost claim payments is $797 million in excess of the self-insured retention. Receivables for insurance recoveries were $585 million and $587 million at December 31, 2017, and 2016, respectively. These amounts are classified in Other within Other Noncurrent Assets and Receivables within Current Assets on the Consolidated Balance Sheets. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims. Duke Energy Carolinas believes the insurance recovery asset is probable of recovery as the insurance carrier continues to have a strong financial strength rating.
Duke Energy Progress and Duke Energy Florida
Spent Nuclear Fuel Matters
On October 16, 2014, Duke Energy Progress and Duke Energy Florida sued the U.S. in the U.S. Court of Federal Claims. The lawsuit claimed the Department of Energy breached a contract in failing to accept spent nuclear fuel under the Nuclear Waste Policy Act of 1982 and asserted damages for the cost of on-site storage. Duke Energy Progress and Duke Energy Florida asserted damages for the period January 1, 2011, through December 31, 2013, of $48 million and $25 million, respectively. On November 17, 2017, the Court awarded Duke Energy Progress and Duke Energy Florida $48 million and $21 million, respectively, subject to appeal. No appeals were filed and Duke Energy Progress and Duke Energy Florida will recognize the recoveries in the first quarter of 2018. Claims for all periods through 2013 have been resolved. Additional claims will be filed in 2018.
Duke Energy Progress
Gypsum Supply Agreements Matter
On June 30, 2017, CertainTeed Gypsum NC, Inc. (CertainTeed) filed a declaratory judgment action against Duke Energy Progress in the North Carolina Business Court relating to a gypsum supply agreement. In its complaint, CertainTeed seeks an order from the court declaring that the minimum amount of gypsum Duke Energy Progress must provide to CertainTeed under the supply agreement is 50,000 tons per month through 2029. On September 28, 2017, the Court denied CertainTeed's motion for summary judgment. Discovery in the case is underway and a trial date has not been set. In light of the volatility in future production of gypsum, Duke Energy Progress cannot predict the outcome of this matter.
Duke Energy Florida
Class-Action Lawsuit
On February 22, 2016, a lawsuit was filed in the U.S. District Court for the Southern District of Florida on behalf of a putative class of Duke Energy Florida and FP&L’s customers in ratesFlorida. The suit alleges the State of Florida’s nuclear power plant cost recovery statutes (NCRS) are unconstitutional and 25%pre-empted by federal law. Plaintiffs claim they are entitled to repayment of all money paid by customers of Duke Energy Florida and FP&L as a result of the NCRS, as well as an injunction against any future charges under those statutes. The constitutionality of the NCRS has been challenged unsuccessfully in a number of prior cases on alternative grounds. Duke Energy Florida and FP&L filed motions to dismiss the complaint on May 5, 2016. On September 21, 2016, the Court granted the motions to dismiss with prejudice. Plaintiffs filed a motion for reconsideration, which was denied. On January 4, 2017, plaintiffs filed a notice of appeal to the U.S. Court of Appeals. The appeal, which has been fully briefed, was heard on August 22, 2017, and a decision is retained by us. In Tennessee, we operatepending. Duke Energy Florida cannot predict the outcome of this appeal.
Westinghouse Contract Litigation
On March 28, 2014, Duke Energy Florida filed a lawsuit against Westinghouse in the U.S. District Court for the Western District of North Carolina. The lawsuit seeks recovery of $54 million in milestone payments in excess of work performed under the amended TIP whereterminated EPC for Levy as well as a determination by the court of the amounts due to Westinghouse as a result of the termination of the EPC. Duke Energy Florida recognized an exit obligation as a result of the termination of the EPC contract.
On March 31, 2014, Westinghouse filed a lawsuit against Duke Energy Florida in U.S. District Court for the Western District of Pennsylvania. The Pennsylvania lawsuit alleged damages under the EPC in excess of $510 million for engineering and design work, costs to end supplier contracts and an alleged termination fee.
On June 9, 2014, the judge in the North Carolina case ruled that the litigation will proceed in the Western District of North Carolina. On July 11, 2016, Duke Energy Florida and Westinghouse filed separate Motions for Summary Judgment. On September 29, 2016, the court issued its ruling on the parties' respective Motions for Summary Judgment, ruling in favor of Westinghouse on a $30 million termination fee claim and dismissing Duke Energy Florida's $54 million refund claim, but stating that Duke Energy Florida could use the refund claim to offset any damages for termination costs. Westinghouse's claim for termination costs was unaffected by this ruling and continued to trial. At trial, Westinghouse reduced its claim for termination costs from $482 million to $424 million. Following a trial on the matter, the court issued its final order in December 2016 denying Westinghouse’s claim for termination costs and re-affirming its earlier ruling in favor of Westinghouse on the $30 million termination fee and Duke Energy Florida’s refund claim. Judgment was entered against Duke Energy Florida in the amount of approximately $34 million, which includes pre-judgment interest. Westinghouse has appealed the trial court's order and Duke Energy Florida has cross-appealed. Duke Energy Florida cannot predict the ultimate outcome of the appeal of the trial court's order.
On March 29, 2017, Westinghouse filed Chapter 11 bankruptcy in the Southern District of New York, which automatically stayed the appeal. On May 23, 2017, the bankruptcy court entered an order lifting the stay with respect to the appeal. Briefing of the appeal concluded on October 20, 2017. Oral argument in the appeal was originally set for March 2018 but has tentatively been rescheduled to May 2018, due to scheduling conflicts.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Ultimate resolution of these matters could have a material effect on the results of operations, financial position or cash flows of Duke Energy Florida. See discussion of the 2017 Settlement and the Levy Nuclear Project in Note 4 for additional information regarding recovery of costs related to Westinghouse. The 2017 Settlement does not permit recovery of any amounts paid to resolve this contract litigation.
MGP Cost Recovery Action
On December 30, 2011, Duke Energy Florida filed a lawsuit against FirstEnergy Corp. (FirstEnergy) to recover investigation and remediation costs incurred by Duke Energy Florida in connection with the restoration of two former MGP sites in Florida. Duke Energy Florida alleged that FirstEnergy, as the successor to Associated Gas & Electric Co., owes past and future contribution and response costs of up to $43 million for the investigation and remediation of MGP sites. On December 6, 2016, the trial court entered judgment against Duke Energy Florida in the case. In January 2017, Duke Energy Florida appealed the decision to the U.S. Court of Appeals for the Sixth Circuit, which has been fully briefed and argued. Duke Energy Florida cannot predict the outcome of this appeal.
Duke Energy Ohio
Antitrust Lawsuit
In January 2008, four plaintiffs, including individual, industrial and nonprofit customers, filed a lawsuit against Duke Energy Ohio in federal court in the Southern District of Ohio. Plaintiffs alleged Duke Energy Ohio conspired to provide inequitable and unfair price advantages for certain large business consumers by entering into nonpublic option agreements in exchange for their withdrawal of challenges to Duke Energy Ohio’s Rate Stabilization Plan implemented in early 2005. In March 2014, a federal judge certified this matter as a class action. Plaintiffs alleged claims of antitrust violations under the federal Robinson Patman Act as well as fraud and conspiracy allegations under the federal Racketeer Influenced and Corrupt Organizations statute and the Ohio Corrupt Practices Act.
During 2015, the parties received preliminary court approval of a settlement agreement. Duke Energy Ohio recorded a litigation settlement reserve of $81 million classified in Other within Current Liabilities on the Consolidated Balance Sheet at December 31, 2015. Duke Energy Ohio also recognized a pretax charge of $81 million in (Loss) Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2015. The settlement agreement was approved at a federal court hearing on April 19, 2016. Distribution of the settlement checks was approved by the court in January 2017 and all settlement amounts have been paid. See Note 2 for further discussion on the Midwest Generation Exit.
Other Litigation and Legal Proceedings
The Duke Energy Registrants are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve significant amounts. The Duke Energy Registrants believe the final disposition of these proceedings will not have a material effect on their results of operations, cash flows or financial position.
The table below presents recorded reserves based on management’s best estimate of probable loss for legal matters, excluding asbestos-related reserves and the exit obligation discussed above related to the termination of an EPC contract. Reserves are classified on the Consolidated Balance Sheets in Other within Other Noncurrent Liabilities and Accounts payable and Other within Current Liabilities. The reasonably possible range of loss in excess of recorded reserves is not material, other than as described above. |
| | | | | | | |
| | December 31, |
(in millions) | 2017 |
| | 2016 |
|
| Reserves for Legal Matters | | | |
| Duke Energy | $ | 88 |
| | $ | 98 |
|
| Duke Energy Carolinas | 30 |
| | 23 |
|
| Progress Energy | 55 |
| | 59 |
|
| Duke Energy Progress | 13 |
| | 14 |
|
| Duke Energy Florida | 24 |
| | 28 |
|
| Duke Energy Ohio | — |
| | 4 |
|
| Piedmont | 2 |
| | 2 |
|
OTHER COMMITMENTS AND CONTINGENCIES
General
As part of their normal business, the Duke Energy Registrants are party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. These guarantees involve elements of performance and credit risk, which are not fully recognized on the Consolidated Balance Sheets and have unlimited maximum potential payments. However, the Duke Energy Registrants do not believe these guarantees will have a material effect on their results of operations, cash flows or financial position.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Purchase Obligations
Purchased Power
Duke Energy Progress, Duke Energy Florida and Duke Energy Ohio have ongoing purchased power contracts, including renewable energy contracts, with other utilities, wholesale marketers, co-generators and qualified facilities. These purchased power contracts generally provide for capacity and energy payments. In addition, Duke Energy Progress and Duke Energy Florida have various contracts to secure transmission rights.
The following table presents executory purchased power contracts with terms exceeding one year, excluding contracts classified as leases. Amounts at Duke Energy Ohio were immaterial. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Minimum Purchase Amount at December 31, 2017 |
| | Contract | | | | | | | | | | | | | | |
| (in millions) | Expiration | | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
| | Thereafter |
| | Total |
|
Duke Energy Progress(a) | 2019-2031 | | $ | 68 |
| | $ | 68 |
| | $ | 51 |
| | $ | 52 |
| | $ | 30 |
| | $ | 239 |
| | $ | 508 |
|
Duke Energy Florida(b) | 2021-2043 | | 357 |
| | 374 |
| | 394 |
| | 378 |
| | 376 |
| | 770 |
| | 2,649 |
|
(a) Contracts represent between 15 percent and 100 percent of net plant output.
(b) Contracts represent between 81 percent and 100 percent of net plant output.
Gas Supply and Capacity Contracts
Duke Energy Ohio and Piedmont routinely enter into long-term natural gas purchase benchmarking gainssupply commodity and lossescapacity commitments and other agreements that commit future cash flows to acquire services needed in their businesses. These commitments include pipeline and storage capacity contracts and natural gas supply contracts to provide service to customers. Costs arising from the natural gas supply commodity and capacity commitments, while significant, are combined with secondary market transaction gains and losses and shared 75% bypass-through costs to customers and 25% by us. Our share of net gainsare generally fully recoverable through the fuel adjustment or lossesPGA procedures and prudence reviews in North Carolina and South Carolina and under the Tennessee is subjectIncentive Plan in Tennessee. In the Midwest, these costs are recovered via the Gas Cost Recovery Rate in Ohio or the Gas Cost Adjustment Clause in Kentucky. The time periods for fixed payments under pipeline and storage capacity contracts are up to an overall annual cap of $1.6 million. In all19 years. The time periods for fixed payments under natural gas supply contracts are up to three jurisdictionsyears. The time period for the twelve months ended October 31, 2014, we generated $97.6 million of margin from secondary market activity, $72.2 million of which is allocated to customers as gas cost reductions and $25.4 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2013, we generated $35.9 million of margin from secondary market activity, $26.9 million of which is allocated to customers as gas cost reductions and $9 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2012, we generated $38.7 million of margin from secondary market activity, $29 million of which is allocated to customers as gas cost reductions and $9.7 million as margin allocated to us.
We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketerssupply purchase commitments is up to 15 years.
Certain storage and pipeline capacity contracts require the payment of demand charges that schedule gas for transportation serviceare based on our systemrates approved by the FERC in order to mitigatemaintain rights to access the risk exposurenatural gas storage or pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Operations and Comprehensive Income as part of natural gas purchases and are included in Cost of natural gas.
The following table presents future unconditional purchase obligations under natural gas supply and capacity contracts as of December 31, 2017. |
| | | | | | | | | |
| (in millions) | Duke Energy | Duke Energy Ohio | Piedmont |
| 2018 | $ | 314 |
| $ | 37 |
| $ | 277 |
|
| 2019 | 280 |
| 28 |
| 252 |
|
| 2020 | 252 |
| 25 |
| 227 |
|
| 2021 | 249 |
| 26 |
| 223 |
|
| 2022 | 226 |
| 11 |
| 215 |
|
| Thereafter | 1,121 |
| 3 |
| 1,118 |
|
| Total | $ | 2,442 |
| $ | 130 |
| $ | 2,312 |
|
Operating and Capital Lease Commitments
The Duke Energy Registrants lease office buildings, railcars, vehicles, computer equipment and other property and equipment with various terms and expiration dates. Additionally, Duke Energy Progress has a capital lease related to firm natural gas pipeline transportation capacity. Duke Energy Progress and Duke Energy Florida have entered into certain purchased power agreements, which are classified as leases. Consolidated capitalized lease obligations are classified as Long-Term Debt or Other within Current Liabilities on the financial conditionConsolidated Balance Sheets. Amortization of assets recorded under capital leases is included in Depreciation and amortization and Fuel used in electric generation on the marketers.
3. Earnings Per ShareConsolidated Statements of Operations.
We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.173
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
A reconciliationThe following tables present rental expense for operating leases. These amounts are included in Operation, maintenance and other on the Consolidated Statements of basicOperations. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | $ | 241 |
| | $ | 242 |
| | $ | 313 |
|
| Duke Energy Carolinas | 44 |
| | 45 |
| | 41 |
|
| Progress Energy | 130 |
| | 140 |
| | 230 |
|
| Duke Energy Progress | 75 |
| | 68 |
| | 149 |
|
| Duke Energy Florida | 55 |
| | 72 |
| | 81 |
|
| Duke Energy Ohio | 15 |
| | 16 |
| | 13 |
|
| Duke Energy Indiana | 23 |
| | 23 |
| | 20 |
|
|
| | | | | | | | | | | | | | | |
| | Year Ended | | Two Months Ended | | Years Ended October 31, |
| (in millions) | December 31, 2017 | | December 31, 2016 | | 2016 |
| | 2015 |
|
| Piedmont | $ | 7 |
| | $ | 1 |
| | $ | 5 |
| | $ | 5 |
|
The following table presents future minimum lease payments under operating leases, which at inception had a non-cancelable term of more than one year. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| Piedmont |
|
| 2018 | $ | 233 |
| | $ | 36 |
| | $ | 133 |
| | $ | 77 |
| | $ | 56 |
| | $ | 20 |
| | $ | 22 |
| $ | 6 |
|
| 2019 | 203 |
| | 29 |
| | 126 |
| | 72 |
| | 54 |
| | 12 |
| | 14 |
| 5 |
|
| 2020 | 183 |
| | 25 |
| | 117 |
| | 62 |
| | 55 |
| | 10 |
| | 10 |
| 5 |
|
| 2021 | 150 |
| | 19 |
| | 97 |
| | 48 |
| | 49 |
| | 7 |
| | 8 |
| 6 |
|
| 2022 | 135 |
| | 16 |
| | 90 |
| | 42 |
| | 48 |
| | 4 |
| | 5 |
| 6 |
|
| Thereafter | 882 |
| | 52 |
| | 525 |
| | 344 |
| | 181 |
| | 5 |
| | 7 |
| 16 |
|
| Total | $ | 1,786 |
| | $ | 177 |
| | $ | 1,088 |
| | $ | 645 |
| | $ | 443 |
| | $ | 58 |
| | $ | 66 |
| $ | 44 |
|
The following table presents future minimum lease payments under capital leases. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| 2018 | $ | 168 |
| | $ | 13 |
| | $ | 46 |
| | $ | 21 |
| | $ | 25 |
| | $ | 3 |
| | $ | 2 |
|
| 2019 | 169 |
| | 13 |
| | 45 |
| | 20 |
| | 25 |
| | 1 |
| | 1 |
|
| 2020 | 174 |
| | 13 |
| | 47 |
| | 21 |
| | 26 |
| | — |
| | 1 |
|
| 2021 | 176 |
| | 8 |
| | 45 |
| | 22 |
| | 25 |
| | — |
| | 1 |
|
| 2022 | 169 |
| | 8 |
| | 45 |
| | 21 |
| | 24 |
| | — |
| | 1 |
|
| Thereafter | 745 |
| | 109 |
| | 323 |
| | 227 |
| | 95 |
| | — |
| | 38 |
|
| Minimum annual payments | 1,601 |
| | 164 |
| | 551 |
| | 332 |
| | 220 |
| | 4 |
| | 44 |
|
| Less: amount representing interest | (601 | ) | | (103 | ) | | (283 | ) | | (192 | ) | | (91 | ) | | — |
| | (33 | ) |
| Total | $ | 1,000 |
| | $ | 61 |
| | $ | 268 |
| | $ | 140 |
| | $ | 129 |
| | $ | 4 |
| | $ | 11 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
6. DEBT AND CREDIT FACILITIES
Summary of Debt and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the years ended October 31, 2014, 2013 and 2012 is presented below.Related Terms
The following tables summarize outstanding debt. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Weighted |
| | | | | | | | | |
| | Average |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Interest |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Rate |
| | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Unsecured debt, maturing 2018-2073 | 4.17 | % | | $ | 20,409 |
| $ | 1,150 |
| $ | 3,950 |
| $ | — |
| $ | 550 |
| $ | 900 |
| $ | 411 |
| $ | 2,050 |
|
| Secured debt, maturing 2018-2037 | 3.15 | % | | 4,458 |
| 450 |
| 1,757 |
| 300 |
| 1,457 |
| — |
| — |
| — |
|
First mortgage bonds, maturing 2018-2047(a) | 4.51 | % | | 23,529 |
| 7,959 |
| 11,801 |
| 6,776 |
| 5,025 |
| 1,100 |
| 2,669 |
| — |
|
Capital leases, maturing 2018-2051(b) | 4.55 | % | | 1,000 |
| 61 |
| 269 |
| 139 |
| 129 |
| 5 |
| 11 |
| — |
|
Tax-exempt bonds, maturing 2019-2041(c) | 3.23 | % | | 941 |
| 243 |
| 48 |
| 48 |
| — |
| 77 |
| 572 |
| — |
|
Notes payable and commercial paper(d) | 1.57 | % | | 2,788 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Money pool/intercompany borrowings | | | — |
| 404 |
| 955 |
| 390 |
| — |
| 54 |
| 311 |
| 364 |
|
| Fair value hedge carrying value adjustment | | | 6 |
| 6 |
| — |
| — |
| — |
| — |
| — |
| — |
|
Unamortized debt discount and premium, net(e) | | | 1,582 |
| (19 | ) | (30 | ) | (16 | ) | (10 | ) | (33 | ) | (9 | ) | (1 | ) |
Unamortized debt issuance costs(f) | | | (271 | ) | (47 | ) | (108 | ) | (40 | ) | (56 | ) | (7 | ) | (21 | ) | (12 | ) |
| Total debt | 4.09 | % | | $ | 54,442 |
| $ | 10,207 |
| $ | 18,642 |
| $ | 7,597 |
| $ | 7,095 |
| $ | 2,096 |
| $ | 3,944 |
| $ | 2,401 |
|
| Short-term notes payable and commercial paper | | | (2,163 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Short-term money pool/intercompany borrowings | | | — |
| (104 | ) | (805 | ) | (240 | ) | — |
| (29 | ) | (161 | ) | (364 | ) |
Current maturities of long-term debt(g) | | | (3,244 | ) | (1,205 | ) | (771 | ) | (3 | ) | (768 | ) | (3 | ) | (3 | ) | (250 | ) |
Total long-term debt(g) |
| | $ | 49,035 |
| $ | 8,898 |
| $ | 17,066 |
| $ | 7,354 |
| $ | 6,327 |
| $ | 2,064 |
| $ | 3,780 |
| $ | 1,787 |
|
| |
| (a) | Substantially all electric utility property is mortgaged under mortgage bond indentures. |
| |
| (b) | Duke Energy includes $81 million and $603 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP. |
| |
| (c) | Substantially all tax-exempt bonds are secured by first mortgage bonds or letters of credit. |
| |
| (d) | Includes $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper program was 14 days. |
| |
| (e) | Duke Energy includes $1,509 million and $176 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively. |
| |
| (f) | Duke Energy includes $47 million in purchase accounting adjustments primarily related to the merger with Progress Energy. |
| |
| (g) | Refer to Note 17 for additional information on amounts from consolidated VIEs. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | |
| In thousands, except per share amounts | | 2014 | | 2013 | | 2012 |
| Net Income | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
| | | | | | | |
| Average shares of common stock outstanding for basic earnings per share | | 77,883 |
| | 74,884 |
| | 71,977 |
|
| Contingently issuable shares under incentive compensation plans | | 310 |
| | 289 |
| | 301 |
|
| Contingently issuable shares under forward sale agreements | | — |
| | 160 |
| | — |
|
| Average shares of dilutive stock | | 78,193 |
| | 75,333 |
| | 72,278 |
|
| | | | | | | |
| Earnings Per Share of Common Stock: | | | | | | |
| Basic | | $ | 1.85 |
| | $ | 1.80 |
| | $ | 1.67 |
|
| Diluted | | $ | 1.84 |
| | $ | 1.78 |
| | $ | 1.66 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Weighted |
| | | | | | | | | |
| | Average |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Interest |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Rate |
| | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Unsecured debt, maturing 2017-2073 | 4.30 | % | | $ | 17,812 |
| $ | 1,150 |
| $ | 3,551 |
| $ | — |
| $ | 150 |
| $ | 810 |
| $ | 415 |
| $ | 1,835 |
|
| Secured debt, maturing 2017-2037 | 2.60 | % | | 3,909 |
| 425 |
| 1,819 |
| 300 |
| 1,519 |
| — |
| — |
| — |
|
First mortgage bonds, maturing 2017-2046(a) | 4.61 | % | | 21,879 |
| 7,410 |
| 10,800 |
| 6,425 |
| 4,375 |
| 1,000 |
| 2,669 |
| — |
|
Capital leases, maturing 2018-2051(b) | 4.48 | % | | 1,100 |
| 22 |
| 285 |
| 142 |
| 143 |
| 7 |
| 11 |
| — |
|
Tax-exempt bonds, maturing 2017-2041(c) | 2.84 | % | | 1,053 |
| 355 |
| 48 |
| 48 |
| — |
| 77 |
| 572 |
| — |
|
Notes payable and commercial paper(d) | 1.01 | % | | 3,112 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Money pool/intercompany borrowings(e) | | | — |
| 300 |
| 1,902 |
| 150 |
| 297 |
| 41 |
| 150 |
| — |
|
| Fair value hedge carrying value adjustment | | | 6 |
| 6 |
| — |
| — |
| — |
| — |
| — |
| — |
|
Unamortized debt discount and premium, net(f) | | | 1,753 |
| (20 | ) | (31 | ) | (16 | ) | (10 | ) | (28 | ) | (9 | ) | (1 | ) |
Unamortized debt issuance costs(g) | | | (242 | ) | (45 | ) | (104 | ) | (38 | ) | (52 | ) | (7 | ) | (22 | ) | (13 | ) |
| Total debt | 4.07 | % | | $ | 50,382 |
| $ | 9,603 |
| $ | 18,270 |
| $ | 7,011 |
| $ | 6,422 |
| $ | 1,900 |
| $ | 3,786 |
| $ | 1,821 |
|
| Short-term notes payable and commercial paper | | | (2,487 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Short-term money pool/intercompany borrowings | | | — |
| — |
| (729 | ) | — |
| (297 | ) | (16 | ) | — |
| — |
|
Current maturities of long-term debt(h) | | | (2,319 | ) | (116 | ) | (778 | ) | (452 | ) | (326 | ) | (1 | ) | (3 | ) | (35 | ) |
Total long-term debt(h) |
| | $ | 45,576 |
| $ | 9,487 |
| $ | 16,763 |
| $ | 6,559 |
| $ | 5,799 |
| $ | 1,883 |
| $ | 3,783 |
| $ | 1,786 |
|
| |
| (a) | Substantially all electric utility property is mortgaged under mortgage bond indentures. |
| |
| (b) | Duke Energy includes $98 million and $670 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP. |
| |
| (c) | Substantially all tax-exempt bonds are secured by first mortgage bonds or letters of credit. |
| |
| (d) | Includes $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy and Piedmont's commercial paper programs were 14 days and eight days, respectively. |
| |
| (e) | Progress Energy amount includes a $1 billion intercompany loan related to the sale of the International Disposal Group. See Note 2 for further discussion of the sale. |
| |
| (f) | Duke Energy includes $1,653 million and $197 million purchase accounting adjustments related to the mergers with Progress Energy and Piedmont, respectively. |
| |
| (g) | Duke Energy includes $53 million in purchase accounting adjustments primarily related to the merger with Progress Energy. |
| |
| (h) | Refer to Note 17 for additional information on amounts from consolidated VIEs. |
4.Current Maturities of Long-Term Debt
The following table shows the significant components of Current maturities of Long-Term Debt on the Consolidated Balance Sheets. The Duke Energy Registrants currently anticipate satisfying these obligations with cash on hand and proceeds from additional borrowings. |
| | | | | | | | |
| (in millions) | Maturity Date | | Interest Rate |
| | December 31, 2017 |
|
| Unsecured Debt | | | | | |
| Duke Energy (Parent) | June 2018 | | 6.250 | % | | $ | 250 |
|
| Duke Energy (Parent) | June 2018 | | 2.100 | % | | 500 |
|
| Piedmont | December 2018 | | 2.286 | % | (b) | 250 |
|
| First Mortgage Bonds | | | | | |
| Duke Energy Carolinas | January 2018 | | 5.250 | % | | 400 |
|
| Duke Energy Carolinas | April 2018 | | 5.100 | % | | 300 |
|
| Duke Energy Florida | June 2018 | | 5.650 | % | | 500 |
|
| Duke Energy Carolinas | November 2018 | | 7.000 | % | | 500 |
|
Other(a) | | | | | 544 |
|
| Current maturities of long-term debt | | | | | $ | 3,244 |
|
Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2014 and 2013 is as follows.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Senior Notes: | | | | |
| 2.92%, due June 6, 2016 | | $ | 40,000 |
| | $ | 40,000 |
|
| 8.51%, due September 30, 2017 | | 35,000 |
| | 35,000 |
|
| 4.24%, due June 6, 2021 | | 160,000 |
| | 160,000 |
|
| 3.47%, due July 16, 2027 | | 100,000 |
| | 100,000 |
|
| 3.57%, due July 16, 2027 | | 200,000 |
| | 200,000 |
|
| 4.10%, due September 18, 2034 | | 250,000 |
| | — |
|
| 4.65%, due August 1, 2043 | | 300,000 |
| | 300,000 |
|
| Medium-Term Notes: | | | | |
| 5.00%, due December 19, 2013 | | — |
| | 100,000 |
|
| 6.87%, due October 6, 2023 | | 45,000 |
| | 45,000 |
|
| 8.45%, due September 19, 2024 | | 40,000 |
| | 40,000 |
|
| 7.40%, due October 3, 2025 | | 55,000 |
| | 55,000 |
|
| 7.50%, due October 9, 2026 | | 40,000 |
| | 40,000 |
|
| 7.95%, due September 14, 2029 | | 60,000 |
| | 60,000 |
|
| 6.00%, due December 19, 2033 | | 100,000 |
| | 100,000 |
|
| Total | | 1,425,000 |
| | 1,275,000 |
|
| Less current maturities | | — |
| | 100,000 |
|
| Less discount on issuance of notes * | | 570 |
| | 143 |
|
| Total | | $ | 1,424,430 |
| | $ | 1,174,857 |
|
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | Includes capital lease obligations, amortizing debt and small bullet maturities. |
| |
| (b) | Debt has a floating interest rate. |
* Maturities and Call Options
The discount onfollowing table shows the 4.65% senior notes was $138 and $143 at October 31, 2014 and 2013, respectively. The discount on the 4.10% senior notes was $432 at October 31, 2014.
Currentannual maturities
of long-term debt for the next five years
ending October 31 and
thereafterthereafter. Amounts presented exclude short-term notes payable and commercial paper and money pool borrowings for the Subsidiary Registrants. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy(a) |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| 2018 | $ | 3,244 |
| | $ | 1,205 |
| | $ | 771 |
| | $ | 3 |
| | $ | 768 |
| | $ | 3 |
| | $ | 3 |
| | $ | 250 |
|
| 2019 | 3,563 |
| | 6 |
| | 2,191 |
| | 903 |
| | 490 |
| | 548 |
| | 61 |
| | — |
|
| 2020 | 3,699 |
| | 906 |
| | 871 |
| | 304 |
| | 568 |
| | — |
| | 502 |
| | — |
|
| 2021 | 3,760 |
| | 502 |
| | 1,472 |
| | 602 |
| | 371 |
| | 48 |
| | 69 |
| | 159 |
|
| 2022 | 3,010 |
| | 302 |
| | 1,176 |
| | 653 |
| | 74 |
| | 23 |
| | 243 |
| | — |
|
| Thereafter | 33,271 |
| | 7,182 |
| | 11,356 |
| | 4,892 |
| | 4,824 |
| | 1,445 |
| | 2,905 |
| | 1,628 |
|
| Total long-term debt, including current maturities | $ | 50,547 |
|
| $ | 10,103 |
|
| $ | 17,837 |
|
| $ | 7,357 |
|
| $ | 7,095 |
|
| $ | 2,067 |
|
| $ | 3,783 |
| | $ | 2,037 |
|
| |
| (a) | Excludes $1,732 million in purchase accounting adjustments related to the Progress Energy merger and the Piedmont acquisition. |
The Duke Energy Registrants have the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than as presented above.
Short-Term Obligations Classified as Long-Term Debt
Tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder and certain commercial paper issuances and money pool borrowings are classified as follows.Long-Term Debt on the Consolidated Balance Sheets. These tax-exempt bonds, commercial paper issuances and money pool borrowings, which are short-term obligations by nature, are classified as long term due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. As Duke Energy’s Master Credit Facility and other bilateral letter of credit agreements have non-cancelable terms in excess of one year as of the balance sheet date, Duke Energy has the ability to refinance these short-term obligations on a long-term basis. The following tables show short-term obligations classified as long-term debt. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Progress |
| | Ohio |
| | Indiana |
|
| Tax-exempt bonds | $ | 312 |
| | $ | — |
| | $ | — |
| | $ | 27 |
| | $ | 285 |
|
Commercial paper(a) | 625 |
| | 300 |
| | 150 |
| | 25 |
| | 150 |
|
| Total | $ | 937 |
|
| $ | 300 |
| | $ | 150 |
|
| $ | 52 |
|
| $ | 435 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Progress |
| | Ohio |
| | Indiana |
|
| Tax-exempt bonds | $ | 347 |
| | $ | 35 |
| | $ | — |
| | $ | 27 |
| | $ | 285 |
|
Commercial paper(a) | 625 |
| | 300 |
| | 150 |
| | 25 |
| | 150 |
|
| Total | $ | 972 |
|
| $ | 335 |
|
| $ | 150 |
| | $ | 52 |
|
| $ | 435 |
|
| |
| (a) | Progress Energy amounts are equal to Duke Energy Progress amounts. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Summary of Significant Debt Issuances
The following tables summarize significant debt issuances (in millions). |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Year Ended December 31, 2017 |
| | | | | | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Maturity | | Interest |
| | Duke |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| Issuance Date | Date | | Rate |
| | Energy |
| | (Parent) |
| | Carolinas |
| | Progress |
| | Florida |
| | Ohio |
|
| Unsecured Debt | | | | | | | | | | | | | | | |
April 2017(a) | April 2025 | | 3.364 | % | | $ | 420 |
| | $ | 420 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
June 2017(b) | June 2020 | | 2.100 | % | | 330 |
| | 330 |
| | — |
| | — |
| | — |
| | — |
|
August 2017(c) | August 2022 | | 2.400 | % | | 500 |
| | 500 |
| | — |
| | — |
| | — |
| | — |
|
August 2017(c) | August 2027 | | 3.150 | % | | 750 |
| | 750 |
| | — |
| | — |
| | — |
| | — |
|
August 2017(c) | August 2047 | | 3.950 | % | | 500 |
| | 500 |
| | — |
| | — |
| | — |
| | — |
|
December 2017(d) | December 2019 | (k) | 2.100 | % | | 400 |
| | — |
| | — |
| | — |
| | 400 |
| | — |
|
| Secured Debt | | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | |
February 2017(e) | June 2034 | | 4.120 | % | | 587 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
August 2017(f) | December 2036 | | 4.110 | % | | 233 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| First Mortgage Bonds | | |
| |
|
| | | | | | | |
| | |
January 2017(g) | January 2020 | | 1.850 | % | | 250 |
| | — |
| | — |
| | — |
| | 250 |
| | — |
|
January 2017(g) | January 2027 | | 3.200 | % | | 650 |
| | — |
| | — |
| | — |
| | 650 |
| | — |
|
March 2017(h) | June 2046 | | 3.700 | % | | 100 |
| | — |
| | — |
| | — |
| | — |
| | 100 |
|
September 2017(i) | September 2020 | | 1.500 | % | (l) | 300 |
| | — |
| | — |
| | 300 |
| | — |
| | — |
|
September 2017(i) | September 2047 | | 3.600 | % | | 500 |
| | — |
| | — |
| | 500 |
| | — |
| | — |
|
November 2017(j) | December 2047 | | 3.700 | % | | 550 |
| | — |
| | 550 |
| | — |
| | — |
| | — |
|
| Total issuances | | | | | $ | 6,070 |
| | $ | 2,500 |
|
| $ | 550 |
| | $ | 800 |
| | $ | 1,300 |
| | $ | 100 |
|
| |
| (a) | Proceeds were used to refinance $400 million of unsecured debt at maturity and to repay a portion of outstanding commercial paper. |
| |
| (b) | Debt issued to repay a portion of outstanding commercial paper. |
| |
| (c) | Debt issued to repay at maturity $700 million of unsecured debt, to repay outstanding commercial paper and for general corporate purposes. |
| |
| (d) | Debt issued to fund storm restoration costs related to Hurricane Irma and for general corporate purposes. |
| |
| (e) | Portfolio financing of four Texas and Oklahoma wind facilities. Duke Energy pledged substantially all of the assets of these wind facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures. |
| |
| (f) | Portfolio financing of eight solar facilities located in California, Colorado and New Mexico. Duke Energy pledged substantially all of the assets of these solar facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures. |
| |
| (g) | Debt issued to fund capital expenditures for ongoing construction and capital maintenance, to repay a $250 million aggregate principal amount of bonds at maturity and for general corporate purposes. |
| |
| (h) | Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance and for general corporate purposes. |
| |
| (i) | Debt issued to repay at maturity a $200 million aggregate principal amount of bonds at maturity, pay down intercompany short-term debt and for general corporate purposes, including capital expenditures. |
| |
| (j) | Debt issued to refinance $400 million aggregate principal amount of bonds due January 2018, pay down intercompany short-term debt and for general corporate purposes. |
| |
| (k) | Principal balance will be repaid in equal quarterly installments beginning in March 2018. |
| |
| (l) | Debt issuance has a floating interest rate. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | |
| In thousands | |
| 2015 | $ | — |
|
| 2016 | 40,000 |
|
| 2017 | 35,000 |
|
| 2018 | — |
|
| 2019 | — |
|
| Thereafter | 1,350,000 |
|
| Total | $ | 1,425,000 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Year Ended December 31, 2016 |
| | | | | | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Maturity | | Interest |
| | Duke |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| Issuance Date | Date | | Rate |
| | Energy |
| | (Parent) |
| | Carolinas |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Unsecured Debt | | | | | | | | | | | | | | | | | |
April 2016(a) | April 2023 | | 2.875 | % | | $ | 350 |
| | $ | 350 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
August 2016(b) | September 2021 | | 1.800 | % | | 750 |
| | 750 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
August 2016(b) | September 2026 | | 2.650 | % | | 1,500 |
| | 1,500 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
August 2016(b) | September 2046 | | 3.750 | % | | 1,500 |
| | 1,500 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Secured Debt | | | | | | | | | | | | | | |
|
| | |
June 2016(c) | March 2020 | | 1.196 | % | | 183 |
| | — |
| | — |
| | — |
| | 183 |
| | — |
| | — |
|
June 2016(c) | September 2022 | | 1.731 | % | | 150 |
| | — |
| | — |
| | — |
| | 150 |
| | — |
| | — |
|
June 2016(c) | September 2029 | | 2.538 | % | | 436 |
| | — |
| | — |
| | — |
| | 436 |
| | — |
| | — |
|
June 2016(c) | March 2033 | | 2.858 | % | | 250 |
| | — |
| | — |
| | — |
| | 250 |
| | — |
| | — |
|
June 2016(c) | September 2036 | | 3.112 | % | | 275 |
| | — |
| | — |
| | — |
| | 275 |
| | — |
| | — |
|
August 2016(d) | June 2034 | | 2.747 | % | (i) | 228 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
August 2016(d) | June 2020 | | 2.747 | % | (i) | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| First Mortgage Bonds | | | | | | | | | | | | | | |
|
| | |
March 2016(e) | March 2023 | | 2.500 | % | | 500 |
| | — |
| | 500 |
| | — |
| | — |
| | — |
| | — |
|
March 2016(e) | March 2046 | | 3.875 | % | | 500 |
| | — |
| | 500 |
| | — |
| | — |
| | — |
| | — |
|
May 2016(f) | May 2046 | | 3.750 | % | | 500 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 500 |
|
June 2016(e) | June 2046 | | 3.700 | % | | 250 |
| | — |
| | — |
| | — |
| | — |
| | 250 |
| | — |
|
September 2016(g) | October 2046 | | 3.400 | % | | 600 |
| | — |
| | — |
| | — |
| | 600 |
| | — |
| | — |
|
September 2016(e) | October 2046 | | 3.700 | % | | 450 |
| | — |
| | — |
| | 450 |
| | — |
| | — |
| | — |
|
November 2016(h) | December 2046 | | 2.950 | % | | 600 |
| | — |
| | 600 |
| | — |
| | — |
| | — |
| | — |
|
| Total issuances | | | | | $ | 9,127 |
| | $ | 4,100 |
|
| $ | 1,600 |
| | $ | 450 |
|
| $ | 1,894 |
|
| $ | 250 |
| | $ | 500 |
|
| |
| (a) | Proceeds were used to pay down outstanding commercial paper and for general corporate purposes. |
| |
| (b) | Proceeds were used to finance a portion of the Piedmont acquisition. The $4.9 billion Bridge Facility was terminated following the issuance of this debt. See Note 2 for additional information on the Piedmont acquisition. |
| |
| (c) | DEFPF issued nuclear-asset recovery bonds and used the proceeds to acquire nuclear-asset recovery property from its parent, Duke Energy Florida. The nuclear-asset recovery bonds are payable only from and secured by the nuclear asset-recovery property. DEFPF is consolidated for financial reporting purposes; however, the nuclear asset-recovery bonds do not constitute a debt, liability or other legal obligation of, or interest in, Duke Energy Florida or any of its affiliates other than DEFPF. The assets of DEFPF, including the nuclear-asset recovery property, are not available to pay creditors of Duke Energy Florida or any of its affiliates. Duke Energy Florida used the proceeds from the sale to repay short-term borrowings under the intercompany money pool borrowing arrangement and make an equity distribution of $649 million to the ultimate parent, Duke Energy (Parent), which repaid short-term borrowings. The nuclear-asset recovery bonds are sequential pay amortizing bonds. The maturity date above represents the scheduled final maturity date for the bonds. See Notes 4 and 17 for additional information. |
| |
| (d) | Emerald State Solar, LLC, an indirect wholly owned subsidiary of Duke Energy entered into portfolio financing of approximately 22 North Carolina solar facilities. Tranche A of $228 million is secured by substantially all of the assets of the solar facilities and is nonrecourse to Duke Energy. Tranche B of $105 million is secured by an Equity Contribution Agreement with Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures related to the Emerald State Solar, LLC portfolio. The initial interest rate on the loans was six months London Interbank Offered Rate (LIBOR) plus an applicable margin of 1.75 percent plus a 0.125 percent increase every three years thereafter. In connection with this debt issuance, Emerald State Solar, LLC entered into two interest rate swaps to convert the substantial majority of the loan interest payments from variable rates to fixed rates of approximately 1.81 percent for Tranche A and 1.38 percent for Tranche B, plus the applicable margin. See Note 14 for further information on the notional amounts of the interest rate swaps. |
| |
| (e) | Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance and for general corporate purposes. |
| |
| (f) | Proceeds were used to repay $325 million of unsecured debt due June 2016, $150 million of first mortgage bonds due July 2016 and for general corporate purposes. |
| |
| (g) | Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance, to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes. |
| |
| (h) | Proceeds were used to repay at maturity $350 million aggregate principal amount of certain bonds due December 2016, as well as to fund capital expenditures for ongoing construction and capital maintenance and for general corporate purposes. |
| |
| (i) | Debt issuance has a floating interest rate. |
We had an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that was available for future use until its expiration date of July 6, 2014. In February 2013, we sold shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements.179
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
On August 1, 2013, weIn July 2016, Piedmont issued $300 million of thirty-year, unsecured senior notes maturing in November 2046 with an interest rate of 4.65% and at a discount of .048% or $144,000, which we began to amortize ratably over the expected life of the notes, under the registration statement in effect noted above. We have3.64%. Piedmont has the option to redeem all or part of the notes before the stated maturity prior to FebruaryMay 1, 2043,2046, at a redemption price equal to the greater of a) 100% of the principal amount plus any accruedof the notes to be redeemed, and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, as supplemented, plus 1525 basis points and any accrued and unpaid interest to the date of redemption. We havePiedmont has the option to redeem all or part of the notes before the stated maturity on or after FebruaryMay 1, 2043,2046, at 100% of the principal amountamounts plus any accrued and unpaid interest to the date of redemption. WePiedmont used the net proceeds of $297.2 million from this issuance to financefund capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term notesborrowings under our unsecuredPiedmont's commercial paper (CP) program and for general corporate purposes.
Available Credit Facilities
72In March 2017, Duke Energy amended its Master Credit Facility to increase its capacity from $7.5 billion to $8 billion, and to extend the termination date of the facility from January 30, 2020, to March 16, 2022. The amendment also added Piedmont as a borrower within the Master Credit Facility. Piedmont's separate $850 million credit facility was terminated in connection with the amendment. With the amendment, the Duke Energy Registrants, excluding Progress Energy (Parent), have borrowing capacity under the Master Credit Facility up to specified sublimits for each borrower. Duke Energy has the unilateral ability at any time to increase or decrease the borrowing sublimits of each borrower, subject to a maximum sublimit for each borrower. The amount available under the Master Credit Facility has been reduced to backstop issuances of commercial paper, certain letters of credit and variable-rate demand tax-exempt bonds that may be put to the Duke Energy Registrants at the option of the holder. Duke Energy Carolinas and Duke Energy Progress are also required to each maintain $250 million of available capacity under the Master Credit Facility as security to meet obligations under plea agreements reached with the U.S. Department of Justice in 2015 related to violations at North Carolina facilities with ash basins.
In January 2018, Duke Energy further amended its Master Credit Facility with consenting lenders to extend $7.65 billion of our existing $8 billion Master Credit Facility by one year to March 16, 2023.
The table below includes the current borrowing sublimits and available capacity under these credit facilities.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | (Parent) |
| | Carolinas |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Facility size(a) | $ | 8,000 |
| | $ | 2,850 |
| | $ | 1,350 |
| | $ | 1,250 |
| | $ | 800 |
| | $ | 450 |
| | $ | 600 |
| | $ | 700 |
|
| Reduction to backstop issuances | | | | | | | | | | | | | | | |
Commercial paper(b) | (1,799 | ) | | (561 | ) | | (371 | ) | | (314 | ) | | — |
| | (45 | ) | | (260 | ) | | (248 | ) |
| Outstanding letters of credit | (63 | ) | | (54 | ) | | (4 | ) | | (2 | ) | | (1 | ) | | — |
| | — |
| | (2 | ) |
| Tax-exempt bonds | (81 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (81 | ) | | — |
|
| Coal ash set-aside | (500 | ) | | — |
| | (250 | ) | | (250 | ) | | — |
| | — |
| | — |
| | — |
|
| Available capacity | $ | 5,557 |
|
| $ | 2,235 |
|
| $ | 725 |
|
| $ | 684 |
|
| $ | 799 |
|
| $ | 405 |
|
| $ | 259 |
| | $ | 450 |
|
| |
| (a) | Represents the sublimit of each borrower. |
| |
| (b) | Duke Energy issued $625 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Consolidated Balance Sheets. |
Three-Year Revolving Credit Facility
In June 2014, we filed with the SEC2017, Duke Energy (Parent) entered into a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC has approved debt and equity issuancesthree-year $1.0 billion revolving credit facility (the Three Year Revolver). Borrowings under this shelf registration statement up to $1 billion during its three-year life. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securitiesfacility will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.
As of December 31, 2017, $500 million has been drawn under the Three Year Revolver. This balance is classified as Long-Term Debt on Duke Energy's Consolidated Balance Sheets. Any undrawn commitments can be drawn, and borrowings can be prepaid, at any time throughout the term of the facility. The terms and conditions of the Three Year Revolver are generally consistent with those governing Duke Energy's Master Credit Facility.
On September 18, 2014, we issuedPiedmont Term Loan Facility
In June 2017, Piedmont entered into an 18-month term loan facility with commitments totaling $250 million of twenty-year, unsecured senior notes with an interest rate of 4.10% and at a discount of .174% or $435,000, which we began to amortize ratably over the expected life of the notes,(the Piedmont Term Loan). Borrowings under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to March 18, 2034, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes tofacility will be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after March 18, 2034, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $247.7 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
As of December 31, 2017, the entire $250 million has been drawn under the Piedmont Term Loan. This balance is classified as Long-Term Debt on Piedmont's Consolidated Balance Sheets. The terms and conditions of the Piedmont Term Loan are generally consistent with those governing Duke Energy's Master Credit Facility.
Other Debt Matters
In September 2016, Duke Energy filed a Registration statement (Form S-3) with the SEC. Under this Form S-3, which is uncapped, the Duke Energy Registrants, excluding Progress Energy, may issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings. The amountregistration statement was filed to replace a similar prior filing upon expiration of cash dividends that may be paid onits three-year term and also allows for the issuance of common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of October 31, 2014, our net earnings available for restricted payments were $1.1 billion.Duke Energy.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Duke Energy has an effective Form S-3 with the SEC to sell up to $3 billion of variable denomination floating-rate demand notes, called PremierNotes. The Form S-3 states that no more than $1.5 billion of the notes will be outstanding at any particular time. The notes are subjectoffered on a continuous basis and bear interest at a floating rate per annum determined by the Duke Energy PremierNotes Committee, or its designee, on a weekly basis. The interest rate payable on notes held by an investor may vary based on the principal amount of the investment. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Duke Energy or at the investor’s option at any time. The balance as of December 31, 2017, and 2016 was $986 million and $1,090 million, respectively. The notes are short-term debt obligations of Duke Energy and are reflected as Notes payable and commercial paper on Duke Energy’s Consolidated Balance Sheets.
In January 2017, Duke Energy amended its Form S-3 to default provisions relatedadd Piedmont as a registrant and included in the amendment a prospectus for Piedmont under which it may issue debt securities in the same manner as other Duke Energy Registrants.
Duke Energy guaranteed debt issued by Duke Energy Carolinas of $650 million and $762 million, respectively, as of December 31, 2017, and 2016.
Money Pool
The Subsidiary Registrants, excluding Progress Energy, are eligible to our long-termreceive support for their short-term borrowing needs through participation with Duke Energy and certain of its subsidiaries in a money pool arrangement. Under this arrangement, those companies with short-term funds may provide short-term loans to affiliates participating in this arrangement. The money pool is structured such that the Subsidiary Registrants, excluding Progress Energy, separately manage their cash needs and working capital requirements. Accordingly, there is no net settlement of receivables and payables between money pool participants. Duke Energy (Parent), may loan funds to its participating subsidiaries, but may not borrow funds through the money pool. Accordingly, as the money pool activity is between Duke Energy and its wholly owned subsidiaries, all money pool balances are eliminated within Duke Energy’s Consolidated Balance Sheets.
Money pool receivable balances are reflected within Notes receivable from affiliated companies on the Subsidiary Registrants’ Consolidated Balance Sheets. Money pool payable balances are reflected within either Notes payable to affiliated companies or Long-Term Debt Payable to Affiliated Companies on the Subsidiary Registrants’ Consolidated Balance Sheets.
Restrictive Debt Covenants
The Duke Energy Registrants’ debt and short-term borrowings.credit agreements contain various financial and other covenants. Duke Energy's Master Credit Facility contains a covenant requiring the debt-to-total capitalization ratio not to exceed 65 percent for each borrower, excluding Piedmont, and 70 percent for Piedmont. Failure to satisfy anymeet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the default provisions may result in total outstanding issues of debt becoming due. There are cross default provisions in all of our debt agreements. As of OctoberDecember 31, 2014, we are2017, each of the Duke Energy Registrants was in compliance with all default provisions.covenants related to their debt agreements. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.
Other Loans
As of December 31, 2017, and 2016, Duke Energy had loans outstanding of $701 million, including $38 million at Duke Energy Progress and $661 million, including $39 million at Duke Energy Progress, respectively, against the cash surrender value of life insurance policies it owns on the lives of its executives. The default provisionsamounts outstanding were carried as a reduction of some or all of our senior debt include:the related cash surrender value that is included in Other within Investments and Other Assets on the Consolidated Balance Sheets.
Failure to make principal or interest payments,7. GUARANTEES AND INDEMNIFICATIONS
Bankruptcy, liquidation or insolvency,
Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal,
Specified events under the Employee Retirement Income Security Act of 1974,
Change in control,Duke Energy and
Failure to observe or perform covenants, including:
Interest coverage of at least 1.75 times. Interest coverage was 4.29 times as of October 31, 2014;
Funded debt cannot exceed 70% of total capitalization. Funded debt was 58% of total capitalization as of October 31, 2014;
Funded debt of all subsidiaries Progress Energy have various financial and performance guarantees and indemnifications, which are issued in the aggregate cannot exceed 15%normal course of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2014;
Restrictions on permitted liens;
Restrictions on paying dividends, on or repurchasing our stock or making investments in subsidiaries; and
Restrictions on burdensome agreements.
5. Short-Term Debt Instruments
We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit forbusiness. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Energy and Progress Energy enter into these arrangements to facilitate commercial transactions with third parties by enhancing the value of $10the transaction to the third party. At December 31, 2017, Duke Energy and Progress Energy do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included on the accompanying Consolidated Balance Sheets.
On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. Guarantees issued by Duke Energy or its affiliates, or assigned to Duke Energy prior to the spin-off, remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Energy Capital, LLC (Spectra Capital) or its affiliates prior to the spin-off remained with Spectra Capital subsequent to the spin-off, except for guarantees that were later assigned to Duke Energy. Duke Energy has indemnified Spectra Capital against any losses incurred under certain of the guarantee obligations that remain with Spectra Capital. At December 31, 2017, the maximum potential amount of future payments associated with these guarantees was $205 million, the majority of which expires by 2028.
Duke Energy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly owned entities, as well as guarantees of debt of certain non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Duke Energy would be required under the guarantees to make payments on the obligations of the less than wholly owned entity. The maximum potential amount of future payments required under these guarantees as of December 31, 2017, was $326 million. Of this amount, $11 million relates to guarantees issued on behalf of less than wholly owned consolidated entities, with the remainder related to guarantees issued on behalf of third parties and unconsolidated affiliates of Duke Energy. Of the guarantees noted above, $281 million of the guarantees expire between 2019 and 2030, with the remaining performance guarantees having no contractual expiration.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
In October 2017, ACP executed a $3.4 billion revolving credit facility with a stated maturity date of October 2021. Duke Energy entered into a guarantee agreement to support its share of the ACP revolving credit facility. Duke Energy's maximum exposure to loss under the terms of the guarantee is limited to 47 percent of the outstanding borrowings under the credit facility, which $1.8was $312 million as of December 31, 2017.
Duke Energy has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a wholly owned and $2.1former non-wholly owned entity to honor its obligations to a third party. Under these arrangements, Duke Energy has payment obligations that are triggered by a draw by the third party or customer due to the failure of the wholly owned or former non-wholly owned entity to perform according to the terms of its underlying contract. At December 31, 2017, Duke Energy had guaranteed $81 million were issued andof outstanding at October 31, 2014 and 2013, respectively. Thesesurety bonds, most of which have no set expiration.
Duke Energy uses bank-issued stand-by letters of credit to secure the performance of wholly owned and non-wholly owned entities to a third party or customer. Under these arrangements, Duke Energy has payment obligations to the issuing bank that are usedtriggered by a draw by the third party or customer due to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expirationfailure of the facility in 2017 provided that we are in compliance with allwholly owned or non-wholly owned entity to perform according to the terms of its underlying contract. At December 31, 2017, Duke Energy had issued a total of $449 million in letters of credit, which expire between 2018 and 2022. The unused amount under these letters of credit was $66 million.
Duke Energy and Progress Energy have issued indemnifications for certain asset performance, legal, tax and environmental matters to third parties, including indemnifications made in connection with sales of businesses. At December 31, 2017, the agreement. See Note 4estimated maximum exposure for these indemnifications was $89 million, most of which have no set expiration. For certain matters for which Progress Energy receives timely notice, indemnity obligations may extend beyond the notice period. Certain indemnifications related to the consolidated financial statements for discussiondiscontinued operations have no limitations as to time or maximum potential future payments.
Duke Energy recognized $21 million and $13 million, as of default provisions, including cross default provisions,December 31, 2017, and 2016, respectively, primarily in all of our debt agreements.
We have an $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest basedOther within Other Noncurrent Liabilities on among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.
As of October 31, 2014, we had $355 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets, with original maturities ranging from 4for the guarantees discussed above. As current estimates change, additional losses related to 28 days fromguarantees and indemnifications to third parties, which could be material, may be recorded by the Duke Energy Registrants in the future.
8. JOINT OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES
The Duke Energy Registrants maintain ownership interests in certain jointly owned generating and transmission facilities. The Duke Energy Registrants are entitled to a share of the generating capacity and output of each unit equal to their datesrespective ownership interests. The Duke Energy Registrants pay their ownership share of issuance at a weighted average interest rateadditional construction costs, fuel inventory purchases and operating expenses. The Duke Energy Registrants share of .17%. Asrevenues and operating costs of October 31, 2013, our outstanding notes under the CP program,jointly owned facilities is included within the corresponding line in the Consolidated Balance Sheets as stated above, were $400 million at a weighted average interest rateStatements of .36%.
We did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2014. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2014 is as follows
|
| | | |
| In thousands | |
| Minimum amount outstanding | $ | 275,000 |
|
| Maximum amount outstanding | $ | 625,000 |
|
| Minimum interest rate | .10 | % |
| Maximum interest rate | .43 | % |
| Weighted average interest rate | .19 | % |
Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 58% at October 31, 2014.
6. Stockholders’ Equity
Capital Stock
Changes in common stock for the years ended October 31, 2014, 2013 and 2011 are as follows.
|
| | | | | | | |
| In thousands | | Shares | | Amount |
| Balance, October 31, 2011 | | 72,318 |
| | $ | 446,791 |
|
| Issued to participants in the Employee Stock Purchase Plan (ESPP) | | 30 |
| | 894 |
|
| Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) | | 677 |
| | 20,508 |
|
| Issued to participants in the Incentive Compensation Plan (ICP) | | 25 |
| | 796 |
|
| Shares repurchased under Accelerated Share Repurchase (ASR) agreement | | (800 | ) | | (26,528 | ) |
| Balance, October 31, 2012 | | 72,250 |
| | 442,461 |
|
| Issued to ESPP | | 33 |
| | 1,056 |
|
| Issued to DRIP | | 720 |
| | 22,791 |
|
| Issued to ICP | | 96 |
| | 3,065 |
|
| Issuance of common stock through public share offering, net of underwriting fees | | 3,000 |
| | 92,640 |
|
| Costs from issuance of common stock | | — |
| | (369 | ) |
| Balance, October 31, 2013 | | 76,099 |
| | 561,644 |
|
| Issued to ESPP | | 34 |
|
| 1,143 |
|
| Issued to DRIP | | 698 |
|
| 23,443 |
|
| Issued to ICP | | 100 |
|
| 3,315 |
|
| Issuance of common stock through forward sale agreements, net of expenses | | 1,600 |
|
| 47,290 |
|
| Balance, October 31, 2014 | | 78,531 |
| | $ | 636,835 |
|
In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in
September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are canceled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.
On December 16, 2005, the Board of Directors approved an increaseOperations. Each participant in the numberjointly owned facilities must provide its own financing.
The following table presents the Duke Energy Registrants' interest of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved at that time an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Programjointly owned plant or facilities and the ASR program, which were consolidated.
On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock of which 3 million direct shares were issued and settledamounts included on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.
The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid-December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.
On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Consolidated Balance Sheets.
Upon settlement, we usedAll facilities are operated by the
net proceeds fromDuke Energy Registrants and are included in the Electric Utilities and Infrastructure segment. |
| | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | | | | | Construction |
|
| | Ownership |
| | Property, Plant |
| | Accumulated |
| | Work in |
|
| (in millions except for ownership interest) | Interest |
| | and Equipment |
| | Depreciation |
| | Progress |
|
| Duke Energy Carolinas | |
| | | | | | |
Catawba Nuclear Station (units 1 and 2)(a) | 19.25 | % | | $ | 927 |
| | $ | 651 |
| | $ | 19 |
|
Lee Combined Combustion Station(b) | 86.67 | % | | — |
| | — |
| | 552 |
|
| Duke Energy Ohio | | | |
| | |
| | |
|
Transmission facilities(c) | Various |
| | 89 |
| | 63 |
| | 1 |
|
| Duke Energy Indiana | |
| | |
| | |
| | |
|
Gibson Station (unit 5)(d) | 50.05 | % | | 348 |
| | 162 |
| | 9 |
|
Vermillion Generating Station(e) | 62.5 | % | | 155 |
| | 120 |
| | — |
|
Transmission and local facilities(d) | Various |
| | 4,672 |
| | 1,739 |
| | — |
|
| |
| (a) | Jointly owned with North Carolina Municipal Power Agency Number 1, NCEMC and Piedmont Municipal Power Agency. |
| |
| (b) | Jointly owned with NCEMC. |
| |
| (c) | Jointly owned with America Electric Power Generation Resources and The Dayton Power and Light Company. |
| |
| (d) | Jointly owned with Wabash Valley Power Association, Inc. (WVPA) and Indiana Municipal Power Agency. |
| |
| (e) | Jointly owned with WVPA. |
9. ASSET RETIREMENT OBLIGATIONS
Duke Energy records an ARO when it has a legal obligation to incur retirement costs associated with the retirement of a long-lived asset and the obligation can be reasonably estimated. Certain assets of the Duke Energy Registrants’ have an indeterminate life, such as transmission and distribution facilities, and thus the fair value of the retirement obligation is not reasonably estimable. A liability for these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.AROs will be recorded when a fair value is determinable.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The Duke Energy Registrants’ regulated operations accrue costs of removal for property that does not have an associated legal retirement obligation based on regulatory orders from state commissions. These costs of removal are recorded as a regulatory liability in accordance with ASC 815-40, regulatory accounting treatment. The Duke Energy Registrants do not accrue the estimated cost of removal for any nonregulated assets. See Note 4 for the estimated cost of removal for assets without an associated legal retirement obligation, which are included in Regulatory liabilities on the Consolidated Balance Sheets.
The following table presents the AROs recorded on the Consolidated Balance Sheets.Derivatives |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Decommissioning of nuclear power facilities(a) | $ | 5,371 |
| | $ | 1,944 |
| | $ | 3,246 |
| | $ | 2,564 |
| | $ | 681 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Closure of ash impoundments | 4,525 |
| | 1,629 |
| | 2,094 |
| | 2,075 |
| | 19 |
| | 39 |
| | 763 |
| | — |
|
Other(b) | 279 |
| | 37 |
| | 74 |
| | 34 |
| | 42 |
| | 45 |
| | 18 |
| | 15 |
|
| Total asset retirement obligation | $ | 10,175 |
| | $ | 3,610 |
| | $ | 5,414 |
| | $ | 4,673 |
| | $ | 742 |
| | $ | 84 |
| | $ | 781 |
|
| $ | 15 |
|
| Less: current portion | 689 |
| | 337 |
| | 295 |
| | 295 |
| | — |
| | 3 |
| | 54 |
| | — |
|
| Total noncurrent asset retirement obligation | $ | 9,486 |
| | $ | 3,273 |
| | $ | 5,119 |
| | $ | 4,378 |
| | $ | 742 |
| | $ | 81 |
| | $ | 727 |
|
| $ | 15 |
|
| |
| (a) | Duke Energy amount includes purchase accounting adjustments related to the merger with Progress Energy. |
| |
| (b) | Primarily includes obligations related to asbestos removal. Duke Energy Ohio and Piedmont also include AROs related to the retirement of natural gas mains and services. Duke Energy includes AROs related to the removal of renewable energy generation assets. |
Nuclear Decommissioning Liability
AROs related to nuclear decommissioning are based on site-specific cost studies. The NCUC, PSCSC and Hedging - Contracts in Entity’s Own EquityFPSC require updated cost estimates for decommissioning nuclear plants every five years.
, we classifiedThe following table summarizes information about the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control. As a result of this classification, no amounts were recordedmost recent site-specific nuclear decommissioning cost studies. Decommissioning costs in the consolidated financial statements until settlement of each FSA.
Upon physical settlementtable below are stated in 2013 or 2014 dollars, depending on the year of the
FSAs, deliverycost study, and include costs to decommission plant components not subject to radioactive contamination. |
| | | | | | | | | |
| | Annual Funding |
| | Decommissioning |
| | |
| (in millions) | Requirement(a) |
| | Costs(a)(b) |
| | Year of Cost Study |
| Duke Energy | $ | 14 |
| | $ | 8,150 |
|
| 2013 and 2014 |
| Duke Energy Carolinas | — |
| | 3,420 |
|
| 2013 |
| Duke Energy Progress | 14 |
| | 3,550 |
|
| 2014 |
| Duke Energy Florida | — |
| | 1,180 |
|
| 2013 |
| |
| (a) | Amounts for Progress Energy equal the sum of Duke Energy Progress and Duke Energy Florida. |
| |
| (b) | Amounts include the Subsidiary Registrant's ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors. |
Nuclear Decommissioning Trust Funds
Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida each maintain NDTFs that are intended to pay for the decommissioning costs of our shares resultedtheir respective nuclear power plants. The NDTF investments are managed and invested in dilution to our EPS ataccordance with applicable requirements of various regulatory bodies including the dateNRC, FERC, NCUC, PSCSC, FPSC and the Internal Revenue Service (IRS).
Use of the settlement. In quarters priorNDTF investments is restricted to the settlement date, any dilutive effectnuclear decommissioning activities including license termination, spent fuel and site restoration. The license termination and spent fuel obligations relate to contaminated decommissioning and are recorded as AROs. The site restoration obligation relates to non-contaminated decommissioning and is recorded to cost of the FSAsremoval within Regulatory liabilities on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements for the dilutive effect of the FSAs on our EPS at October 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.
On January 4, 2012, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the Consolidated Balance Sheets.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table presents the fair value of NDTF assets legally restricted for purposes of settling AROs associated with nuclear decommissioning. Duke Energy Florida is actively decommissioning Crystal River Unit 3 and was granted an exemption from the NRC which allows for use of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expectedNDTF for all aspects of nuclear decommissioning. The entire balance of Duke Energy Florida's NDTF may be applied toward license termination, spent fuel and site restoration costs incurred to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligationdecommission Crystal River Unit 3. See Note 16 for additional information related to the shares it borrowed from third parties and soldfair value of the Duke Energy Registrants' NDTFs. |
| | | | | | | |
| | December 31, |
| (in millions) | 2017 | | 2016 |
| Duke Energy | $ | 5,864 |
| | $ | 5,099 |
|
| Duke Energy Carolinas | 3,321 |
| | 2,882 |
|
| Duke Energy Progress | 2,543 |
| | 2,217 |
|
Nuclear Operating Licenses
Operating licenses for nuclear units are potentially subject to us. At settlement, we, at our option, were required to either pay cash or issue sharesextension. The following table includes the current expiration of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, was higher than the January 4, 2012 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on February 28, 2012, we received $.5 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Consolidated Balance Sheets. The $.5 million was the difference between the investment bank’s
weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares. We had an ASR transaction in 2011 as presented in the table above with a similar structure with the investment bank, which was accounted for in the same manner.
As of October 31, 2014, our shares of common stock were reserved for issuance as follows.
nuclear operating licenses. |
| |
| Unit | Year of Expiration |
In thousandsDuke Energy Carolinas | |
ESPPCatawba Units 1 and 2 | 176 |
2043 |
DRIPMcGuire Unit 1 | 840 |
2041 |
ICPMcGuire Unit 2 | 950 |
2043 |
TotalOconee Units 1 and 2 | 1,9662033 |
| Oconee Unit 3 |
2034 |
| Duke Energy Progress | |
| Brunswick Unit 1 | 2036 |
| Brunswick Unit 2 | 2034 |
| Harris | 2046 |
| Robinson | 2030 |
Duke Energy Florida has requested the NRC terminate the operating license for Crystal River Unit 3 as it permanently ceased operation in February 2013. In January 2018, Crystal River Unit 3 reached a SAFSTOR status.
Other Comprehensive Income (Loss)Closure of Ash Impoundments
The Duke Energy Registrants are subject to state and federal regulations covering the closure of coal ash impoundments, including the EPA CCR rule and the Coal Ash Act, and other agreements. AROs recorded on the Duke Energy Registrants' Consolidated Balance Sheets include the legal obligation for closure of coal ash basins and the disposal of related ash as a result of these regulations and agreements.
The Coal Ash Act, as amended, requires excavation of the Sutton, Riverbend and Dan River basins by August 1, 2019, and Asheville basins by August 1, 2022. Excavation at these sites may include a combination of transfer of coal ash to an engineered landfill or conversion for beneficial use. Basins at the H.F. Lee, Cape Fear and Weatherspoon sites are required to be closed through excavation no later than August 1, 2028. Excavation at these sites can include conversion of the basin to a lined industrial landfill, transfer of ash to an engineered landfill or conversion for beneficial use. The remaining basins are required to be closed no later than December 31, 2024, through conversion to a lined industrial landfill, transfer to an engineered landfill or conversion for beneficial use, unless certain dam improvement projects and alternative drinking water source projects are completed by October 15, 2018. Upon satisfactory completion of these projects, the closure deadline would be extended to December 31, 2029, and could include closure through the combination of a cap system and a groundwater monitoring system.
The Coal Ash Act also required the installation and operation of three large-scale coal ash beneficiation projects to produce reprocessed ash for use in the concrete industry. Duke Energy selected the Buck, H.F. Lee and Cape Fear plants for these projects. Closure at these sites is required to be completed no later than December 31, 2029.
The Coal Ash Act includes a variance procedure for compliance deadlines and other issues surrounding the management of CCR and CCR surface impoundments and prohibits cost recovery in customer rates for unlawful discharge of ash impoundment waters occurring after January 1, 2014. The Coal Ash Act leaves the decision on cost recovery determinations related to closure of ash impoundments to the normal ratemaking processes before utility regulatory commissions. Closure plans and all associated permits must be approved by NCDEQ before any closure work can begin.
The EPA CCR rule establishes requirements regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to ensure the safe disposal and management of CCR. The EPA CCR rule has certain requirements which if not met could initiate impoundment closure and require closure completion within five years. The EPA CCR rule includes extension requirements, which if met could allow the extension of closure completion by up to 10 years.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The ARO amount recorded on the Consolidated Balance Sheets is based upon estimated closure costs for impacted ash impoundments. The amount recorded represents the discounted cash flows for estimated closure costs based upon either specific closure plans or the probability weightings of the potential closure methods as evaluated on a partsite-by-site basis. Actual costs to be incurred will be dependent upon factors that vary from site to site. The most significant factors are the method and time frame of ourclosure at the individual sites. Closure methods considered include removing the water from ash basins, consolidating material as necessary and capping the ash with a synthetic barrier, excavating and relocating the ash to a lined structural fill or lined landfill or recycling the ash for concrete or some other beneficial use. The ultimate method and timetable for closure will be in compliance with standards set by federal and state regulations and other agreements. The ARO amount will be adjusted as additional information is gained through the closure and post-closure process, including acceptance and approval of compliance approaches which may change management assumptions, and may result in a material change to the balance. See ARO Liability Rollforward section below for information on revisions made to the coal ash liability during 2017 and 2016.
Asset retirement costs associated with the AROs for operating plants and retired plants are included in Net property, plant and equipment and Regulatory assets, respectively, on the Consolidated Balance Sheets. See Note 4 for additional information on Regulatory assets related to AROs.
Cost recovery for future expenditures will be pursued through the normal ratemaking process with federal and state utility commissions, which permit recovery of necessary and prudently incurred costs associated with Duke Energy’s regulated operations. See Note 4 for additional information on recovery of coal ash costs.
ARO Liability Rollforward
During 2017 and 2016, the Duke Energy Registrants updated coal ash ARO liability estimates based on additional site-specific information for the related costs, methods and timing of work to be performed. Actual closure costs incurred could be materially different from current estimates that form the basis of the recorded AROs.
The following tables present changes in the liability associated with AROs. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Balance at December 31, 2015 | $ | 10,249 |
| | $ | 3,918 |
| | $ | 5,369 |
| | $ | 4,567 |
| | $ | 802 |
| | $ | 125 |
| | $ | 525 |
|
Acquisitions(a) | 22 |
| | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
|
Accretion expense(b) | 400 |
| | 187 |
| | 230 |
| | 194 |
| | 35 |
| | 5 |
| | 24 |
|
Liabilities settled(c) | (613 | ) | | (287 | ) | | (272 | ) | | (212 | ) | | (60 | ) | | (5 | ) | | (49 | ) |
| Liabilities incurred in the current year | 51 |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
| | 29 |
|
| Revisions in estimates of cash flows | 502 |
| | 77 |
| | 143 |
| | 145 |
| | (1 | ) | | (48 | ) | | 337 |
|
| Balance at December 31, 2016 | 10,611 |
|
| 3,895 |
|
| 5,475 |
|
| 4,697 |
|
| 778 |
|
| 77 |
|
| 866 |
|
Accretion expense(b) | 435 |
| | 184 |
| | 228 |
| | 195 |
| | 33 |
| | 3 |
| | 32 |
|
Liabilities settled(c) | (619 | ) | | (282 | ) | | (270 | ) | | (204 | ) | | (65 | ) | | (7 | ) | | (49 | ) |
Liabilities incurred in the current year(d) | 51 |
| | 5 |
| | — |
| | — |
| | — |
| | 7 |
| | 29 |
|
| Revisions in estimates of cash flows | (303 | ) | | (192 | ) | | (19 | ) | | (15 | ) | | (4 | ) | | 4 |
| | (97 | ) |
| Balance at December 31, 2017 | $ | 10,175 |
|
| $ | 3,610 |
|
| $ | 5,414 |
|
| $ | 4,673 |
|
| $ | 742 |
|
| $ | 84 |
|
| $ | 781 |
|
| |
| (a) | Duke Energy amount relates to the Piedmont acquisition. See Note 2 for additional information. |
| |
| (b) | Substantially all accretion expense for the years ended December 31, 2017, and 2016 relates to Duke Energy’s regulated electric operations and has been deferred in accordance with regulatory accounting treatment. |
| |
| (c) | Amounts primarily relate to ash impoundment closures and nuclear decommissioning of Crystal River Unit 3. |
| |
| (d) | Amounts primarily relate to AROs recorded as a result of state agency closure requirements at Duke Energy Indiana. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | |
| (in millions) | | Piedmont |
| Balance at October 31, 2015 | | $ | 20 |
|
| Accretion expense | | 1 |
|
| Liabilities settled | | (7 | ) |
| Liabilities incurred in the current year | | 6 |
|
| Revisions in estimates of cash flows | | (6 | ) |
| Balance at October 31, 2016 | | 14 |
|
| Liabilities settled | | (1 | ) |
| Liabilities incurred in the current year | | 1 |
|
| Balance at December 31, 2016 | | 14 |
|
| Accretion expense | | 1 |
|
| Liabilities settled | | (8 | ) |
| Liabilities incurred in the current year | | 8 |
|
| Balance at December 31, 2017 | | $ | 15 |
|
10. PROPERTY, PLANT AND EQUIPMENT
The following tables summarize the property, plant and equipment for Duke Energy and its subsidiary registrants. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Estimated | | | | | | | | | | | | | | | | |
| | Useful | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Life | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | (Years) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
| Land | | | $ | 1,559 |
| | $ | 467 |
| | $ | 767 |
| | $ | 424 |
| | $ | 343 |
| | $ | 134 |
| | $ | 111 |
| | $ | 41 |
|
| Plant – Regulated | | | | | | | | | | | | | | | | | |
| Electric generation, distribution and transmission | 8-100 | | 93,687 |
| | 35,657 |
| | 39,419 |
| | 24,502 |
| | 14,917 |
| | 4,870 |
| | 13,741 |
| | — |
|
| Natural gas transmission and distribution | 12-80 | | 8,292 |
| | — |
| | — |
| | — |
| | — |
| | 2,559 |
| | — |
| | 5,733 |
|
| Other buildings and improvements | 15-100 | | 1,936 |
| | 647 |
| | 652 |
| | 316 |
| | 336 |
| | 243 |
| | 240 |
| | 154 |
|
| Plant – Nonregulated | | | | | | | | | | | | | | | | | |
Electric generation, distribution and transmission(a) | 5-30 | | 4,273 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other buildings and improvements | 25-35 | | 465 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Nuclear fuel | | | 3,680 |
| | 2,120 |
| | 1,560 |
| | 1,560 |
| | — |
| | — |
| | — |
| | — |
|
| Equipment | 3-55 | | 2,122 |
| | 402 |
| | 555 |
| | 416 |
| | 139 |
| | 348 |
| | 169 |
| | 266 |
|
| Construction in process | | | 6,995 |
| | 2,614 |
| | 3,059 |
| | 1,434 |
| | 1,625 |
| | 350 |
| | 416 |
| | 231 |
|
| Other | 3-40 | | 4,498 |
| | 1,032 |
| | 1,311 |
| | 931 |
| | 370 |
| | 228 |
| | 271 |
| | 300 |
|
Total property, plant and equipment(b)(e) | | | 127,507 |
| | 42,939 |
| | 47,323 |
| | 29,583 |
| | 17,730 |
| | 8,732 |
| | 14,948 |
| | 6,725 |
|
Total accumulated depreciation – regulated(c)(d)(e) | | | (39,742 | ) | | (15,063 | ) | | (15,857 | ) | | (10,903 | ) | | (4,947 | ) | | (2,691 | ) | | (4,662 | ) | | (1,479 | ) |
Total accumulated depreciation – nonregulated(d)(e) | | | (1,795 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Generation facilities to be retired, net | | | 421 |
| | — |
| | 421 |
| | 421 |
| | — |
| | — |
| | — |
| | — |
|
| Total net property, plant and equipment | | | $ | 86,391 |
|
| $ | 27,876 |
|
| $ | 31,887 |
|
| $ | 19,101 |
|
| $ | 12,783 |
|
| $ | 6,041 |
| | $ | 10,286 |
| | $ | 5,246 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | Includes a pretax impairment charge of $58 million on a wholly owned non-contracted wind project. See discussion below. |
| |
| (b) | Includes capitalized leases of $1,294 million, $81 million, $272 million, $139 million, $133 million, $80 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $114 million, $11 million and $103 million, respectively, of accumulated amortization of capitalized leases. |
| |
| (c) | Includes $2,113 million, $1,283 million, $831 million and $831 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively. |
| |
| (d) | Includes accumulated amortization of capitalized leases of $57 million, $11 million, $21 million and $9 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively. |
| |
| (e) | Includes gross property, plant and equipment cost of consolidated VIEs of $3,941 million and accumulated depreciation of consolidated VIEs of $598 million at Duke Energy. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Estimated | | | | | | | | | | | | | | | | |
| | Useful | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Life | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | (Years) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
| Land | | | $ | 1,501 |
| | $ | 432 |
| | $ | 735 |
| | $ | 393 |
| | $ | 342 |
| | $ | 150 |
| | $ | 106 |
| | $ | 39 |
|
| Plant – Regulated | | | | | | | | | | | | | | | | | |
| Electric generation, distribution and transmission | 8-100 | | 89,864 |
| | 34,515 |
| | 37,596 |
| | 23,683 |
| | 13,913 |
| | 4,593 |
| | 13,160 |
| | — |
|
| Natural gas transmission and distribution | 12-67 | | 7,738 |
| | — |
| | — |
| | — |
| | — |
| | 2,456 |
| | — |
| | 5,282 |
|
| Other buildings and improvements | 15-100 | | 1,692 |
| | 502 |
| | 634 |
| | 293 |
| | 341 |
| | 211 |
| | 197 |
| | 148 |
|
| Plant – Nonregulated | | | | | | | | | | | | | | | | | |
| Electric generation, distribution and transmission | 5-30 | | 4,298 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other buildings and improvements | 25-35 | | 421 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Nuclear fuel | | | 3,572 |
| | 2,092 |
| | 1,480 |
| | 1,480 |
| | — |
| | — |
| | — |
| | — |
|
| Equipment | 3-38 | | 1,941 |
| | 358 |
| | 505 |
| | 378 |
| | 127 |
| | 338 |
| | 156 |
| | 260 |
|
| Construction in process | | | 6,186 |
| | 2,324 |
| | 2,708 |
| | 1,329 |
| | 1,379 |
| | 206 |
| | 396 |
| | 210 |
|
| Other | 5-40 | | 4,184 |
| | 904 |
| | 1,206 |
| | 863 |
| | 332 |
| | 172 |
| | 226 |
| | 235 |
|
Total property, plant and equipment(a)(d) | | | 121,397 |
| | 41,127 |
| | 44,864 |
| | 28,419 |
| | 16,434 |
| | 8,126 |
| | 14,241 |
| | 6,174 |
|
Total accumulated depreciation – regulated(b)(c)(d) | | | (37,831 | ) | | (14,365 | ) | | (15,212 | ) | | (10,561 | ) | | (4,644 | ) | | (2,579 | ) | | (4,317 | ) | | (1,360 | ) |
Total accumulated depreciation – nonregulated(c)(d) | | | (1,575 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Generation facilities to be retired, net | | | 529 |
| | — |
| | 529 |
| | 529 |
| | — |
| | — |
| | — |
| | — |
|
| Total net property, plant and equipment | | | $ | 82,520 |
| | $ | 26,762 |
| | $ | 30,181 |
| | $ | 18,387 |
| | $ | 11,790 |
| | $ | 5,547 |
| | $ | 9,924 |
| | $ | 4,814 |
|
| |
| (a) | Includes capitalized leases of $1,355 million, $40 million, $288 million, $142 million, $146 million, $81 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $99 million, $9 million and $90 million, respectively, of accumulated amortization of capitalized leases. |
| |
| (b) | Includes $1,922 million, $1,192 million, $730 million and $730 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively. |
| |
| (c) | Includes accumulated amortization of capitalized leases of $50 million, $9 million, $19 million and $8 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively. |
| |
| (d) | Includes gross property, plant and equipment cost of consolidated VIEs of $2,591 million and accumulated depreciation of consolidated VIEs of $411 million at Duke Energy. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
During the year ended December 31, 2017, Duke Energy recorded a pretax impairment charge of $69 million on a wholly owned non-contracted wind project. The impairment was recorded within Impairment charges on Duke Energy’s Consolidated Statements of Operations. $58 million of the impairment related to property, plant and equipment and $11 million of the impairment related to a net intangible asset; see Note 11 for additional information. The charge represents the excess carrying value over the estimated fair value of the project, which was based on a Level 3 Fair Value measurement that was determined from the income approach using discounted cash flows. The impairment was primarily due to the non-contracted wind project being located in a market that has experienced continued declining market pricing during 2017 and declining long-term forecasted energy and capacity prices, driven by low natural gas prices, additional renewable generation placed in service and lack of significant load growth.
The following tables present capitalized interest, which includes the debt component of AFUDC. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | $ | 128 |
| | $ | 100 |
| | $ | 98 |
|
| Duke Energy Carolinas | 45 |
| | 38 |
| | 38 |
|
| Progress Energy | 45 |
| | 31 |
| | 24 |
|
| Duke Energy Progress | 21 |
| | 17 |
| | 20 |
|
| Duke Energy Florida | 24 |
| | 14 |
| | 4 |
|
| Duke Energy Ohio | 10 |
| | 8 |
| | 10 |
|
| Duke Energy Indiana | 9 |
| | 7 |
| | 6 |
|
|
| | | | | | | | | | | | | | | |
| | Year Ended | | Two Months Ended | | Years Ended October 31, |
| (in millions) | December 31, 2017 | | December 31, 2016 | | 2016 |
| | 2015 |
|
| Piedmont | $ | 12 |
| | $ | 2 |
| | $ | 12 |
| | $ | 11 |
|
Operating Leases
Duke Energy's Commercial Renewables segment operates various renewable energy projects and sells the generated output to utilities, electric cooperatives, municipalities and commercial and industrial customers through long-term contracts. In certain situations, these long-term contracts and the associated renewable energy projects qualify as operating leases. Rental income from these leases is accounted for as Operating Revenues in the Consolidated Statements of Operations. There are no minimum lease payments as all payments are contingent based on actual electricity generated by the renewable energy projects. Contingent lease payments were $262 million, $216 million, and $172 million for the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, renewable energy projects owned by Duke Energy and accounted for as operating leases had a cost basis of $3,153 million and accumulated OCILdepreciation of $459 million. These assets are principally classified as nonregulated electric generation and transmission assets.
11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
Duke Energy
The following table presents goodwill by reportable operating segment for Duke Energy included on Duke Energy's Consolidated Balance Sheets at December 31, 2017, and 2016.
|
| | | | | | | | | | | | | | | |
| | Electric Utilities |
| | Gas Utilities |
| | Commercial |
| | |
| (in millions) | and Infrastructure |
| | and Infrastructure |
| | Renewables |
| | Total |
|
| Goodwill Balance at December 31, 2016 | $ | 17,379 |
| | $ | 1,924 |
| | $ | 122 |
| | $ | 19,425 |
|
Accumulated impairment charges(a) | — |
| | — |
| | (29 | ) | | (29 | ) |
| Goodwill at December 31, 2017 | $ | 17,379 |
| | $ | 1,924 |
| | $ | 93 |
| | $ | 19,396 |
|
| |
| (a) | Duke Energy evaluated the recoverability of goodwill during 2017 and recorded impairment charges of $29 million related to the Energy Management Solutions reporting unit within the Commercial Renewables segment. The fair value of the reporting unit was determined based on the market approach. |
Duke Energy Ohio
Duke Energy Ohio's Goodwill balance of $920 million, allocated $596 million to Electric Utilities and Infrastructure and $324 million to Gas Utilities and Infrastructure, is comprisedpresented net of hedging activitiesaccumulated impairment charges of $216 million on the Consolidated Balance Sheets at December 31, 2017, and 2016.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Progress Energy
Progress Energy's Goodwill is included in the Electric Utilities and Infrastructure operating segment and there are no accumulated impairment charges.
Piedmont
Piedmont's Goodwill is included in the Gas Utilities and Infrastructure operating segment and there are no accumulated impairment charges. Effective with Piedmont's fiscal year being changed to December 31, as discussed in Note 1, Piedmont changed the date of its annual impairment testing of goodwill from ourOctober 31 to August 31 to align with the other Duke Energy Registrants.
Impairment Testing
Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont are required to perform an annual goodwill impairment test as of the same date each year and, accordingly, perform their annual impairment testing of goodwill as of August 31. Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont update their test between annual tests if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. Except for the Energy Management Solutions reporting unit, the fair value of all other reporting units for Duke Energy, Progress Energy, Duke Energy Ohio and Piedmont exceeded their respective carrying values at the date of the annual impairment analysis.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Intangible Assets
The following tables show the carrying amount and accumulated amortization of intangible assets included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets of the Duke Energy Registrants at December 31, 2017 and 2016. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Emission allowances | $ | 19 |
| | $ | 1 |
| | $ | 5 |
| | $ | 2 |
| | $ | 3 |
| | $ | — |
| | $ | 13 |
| | $ | — |
|
| Renewable energy certificates | 148 |
| | 38 |
| | 107 |
| | 107 |
| | — |
| | 3 |
| | — |
| | — |
|
| Natural gas, coal and power contracts | 24 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| | — |
|
| Renewable operating and development projects | 79 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Total gross carrying amounts | 276 |
| | 39 |
| | 112 |
| | 109 |
| | 3 |
| | 3 |
| | 37 |
| | 3 |
|
| Accumulated amortization – natural gas, coal and power contracts | (19 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19 | ) | | — |
|
| Accumulated amortization – renewable operating and development projects | (22 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Accumulated amortization – other | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) |
| Total accumulated amortization | (46 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19 | ) | | (3 | ) |
| Total intangible assets, net | $ | 230 |
|
| $ | 39 |
|
| $ | 112 |
|
| $ | 109 |
|
| $ | 3 |
|
| $ | 3 |
|
| $ | 18 |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Emission allowances | $ | 19 |
| | $ | 1 |
| | $ | 6 |
| | $ | 2 |
| | $ | 4 |
| | $ | — |
| | $ | 13 |
| | $ | — |
|
| Renewable energy certificates | 125 |
| | 36 |
| | 84 |
| | 84 |
| | — |
| | 4 |
| | — |
| | — |
|
| Natural gas, coal and power contracts | 24 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| | — |
|
| Renewable operating and development projects | 97 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Total gross carrying amounts | 271 |
| | 37 |
| | 90 |
| | 86 |
| | 4 |
| | 4 |
| | 37 |
| | 3 |
|
| Accumulated amortization – natural gas, coal and power contracts | (17 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | — |
|
| Accumulated amortization – renewable operating and development projects | (23 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Accumulated amortization – other | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) |
| Total accumulated amortization | (45 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (3 | ) |
| Total intangible assets, net | $ | 226 |
|
| $ | 37 |
|
| $ | 90 |
|
| $ | 86 |
|
| $ | 4 |
|
| $ | 4 |
|
| $ | 20 |
| | $ | — |
|
During the year ended December 31, 2017, Duke Energy recorded a pretax impairment charge of $69 million on a wholly owned non-contracted wind project. The impairment was recorded within Impairment charges on Duke Energy’s Consolidated Statements of Operations. $58 million of the impairment related to property, plant and equipment and $11 million of the impairment related to a net intangible asset that was recorded in 2007 when the project was acquired. Prior to the impairment, the gross amount of the intangible asset was $18 million and the accumulated amortization was $7 million. The intangible asset was fully impaired. See Note 10 for additional information.
Amortization Expense
The following table presents amortization expense for natural gas, coal and power contracts, renewable operating projects and other intangible assets. |
| | | | | | | | | | | |
| | December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | $ | 7 |
| | $ | 6 |
| | $ | 5 |
|
| Duke Energy Indiana | 1 |
| | 1 |
| | 1 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The table below shows the expected amortization expense for the next five years for intangible assets as of December 31, 2017. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as natural gas and coal under existing contracts, as well as estimated amortization related to renewable operating projects. The amortization amounts discussed below are estimates and actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, delays in the in-service dates of renewable assets, additional intangible acquisitions and other events. |
| | | | | | | | | | | | | | | | | | | |
| (in millions) | 2018 |
| | 2019 |
| | 2020 |
| | 2021 |
| | 2022 |
|
| Duke Energy | $ | 3 |
| | $ | 2 |
| | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| Duke Energy Indiana | 1 |
| | — |
| | — |
| | — |
| | — |
|
12. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
EQUITY METHOD INVESTMENTS
Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method.
The following table presents Duke Energy’s investments in unconsolidated affiliates accounted for under the equity method, investments. For further informationas well as the respective equity in earnings, by segment. |
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | Equity in |
| | | | Equity in |
| | Equity in |
|
| (in millions) | Investments |
| | earnings |
| | Investments |
| | earnings |
| | earnings |
|
| Electric Utilities and Infrastructure | $ | 89 |
| | $ | 5 |
| | $ | 93 |
| | $ | 5 |
| | $ | (2 | ) |
| Gas Utilities and Infrastructure | 763 |
| | 62 |
| | 566 |
| | 19 |
| | 1 |
|
| Commercial Renewables | 190 |
| | (5 | ) | | 185 |
| | (82 | ) | | (6 | ) |
| Other | 133 |
| | 57 |
| | 81 |
| | 43 |
| | 76 |
|
| Total | $ | 1,175 |
|
| $ | 119 |
|
| $ | 925 |
|
| $ | (15 | ) |
| $ | 69 |
|
During the years ended December 31, 2017, 2016 and 2015, Duke Energy received distributions from equity investments of $13 million, $31 million and $104 million, respectively, which are included in Other assets within Cash Flows from Operating Activities on these hedging activities by ourthe Consolidated Statements of Cash Flows. During the year ended December 31, 2017, Duke Energy received distributions from equity investments of $281 million, which are included within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.
During the year ended December 31, 2017, the two months ended December 31, 2016, and the years ended October 31, 2016, and 2015, Piedmont received distributions from equity investments of $4 million, $1 million, $26 million and $25 million, respectively, which are included in Other assets within Cash Flows from Operating Activities and $2 million, $1 million, $18 million and $2 million, respectively, which are included within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.
Significant investments in affiliates accounted for under the equity method investments, seeare discussed below.
Electric Utilities and Infrastructure
Duke Energy owns a 50 percent interest in Duke-American Transmission Co. (DATC) and in Pioneer Transmission, LLC (Pioneer), which build, own and operate electric transmission facilities in North America.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Gas Utilities and Infrastructure
The table below outlines Duke Energy's ownership interests in natural gas pipeline companies and natural gas storage facilities. |
| | | | | | | | | | |
| | | | Investment Amount (in millions) |
| | Ownership | | December 31, | | December 31, |
| Entity Name | Interest | | 2017 | | 2016 |
| Pipeline Investments | | | | | |
Atlantic Coast Pipeline, LLC(a) | 47 | % | | $ | 397 |
| | $ | 265 |
|
| Sabal Trail Transmission, LLC | 7.5 | % | | 219 |
| | 140 |
|
Constitution Pipeline, LLC(a) | 24 | % | | 81 |
| | 82 |
|
Cardinal Pipeline Company, LLC(b) | 21.49 | % | | 11 |
| | 16 |
|
| Storage Facilities | | | | | |
Pine Needle LNG Company, LLC(b) | 45 | % | | 13 |
| | 16 |
|
Hardy Storage Company, LLC(b) | 50 | % | | 42 |
| | 47 |
|
Total Investments(c) | | | $ | 763 |
| | $ | 566 |
|
| |
| (a) | During the year ended December 31, 2017, Piedmont transferred its share of ownership interest in ACP and Constitution to a wholly owned subsidiary of Duke Energy at book value. |
| |
| (b) | Piedmont owns the Cardinal, Pine Needle and Hardy Storage investments. |
| |
| (c) | Duke Energy includes purchase accounting adjustments related to Piedmont. |
In October 2017, Duke Energy entered into a guarantee agreement to support its share of the ACP revolving credit facility. See Note 127 for additional information. As a result of the financing, ACP returned capital of $265 million to Duke Energy.
Piedmont sold its 15 percent membership interest in SouthStar on October 3, 2016, for $160 million resulting in an after tax gain of $81 million during the consolidated financial statements. Beginningyear ended October 31, 2016. Piedmont's Equity in 2014, another component of our accumulated OCIL is the allocation of retirement benefits toEarnings in SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented belowwas $19 million for the years ended October 31, 20142016, and 2013.2015.
For regulatory matters and other information on the ACP, Sabal Trail and Constitution investments, see Notes 4 and 17. |
| | | | | | | | |
Changes in Accumulated OCIL (1) |
| | | | | |
| In thousands | | 2014 | | 2013 |
| Accumulated OCIL beginning balance, net of tax | | $ | (284 | ) | | $ | (305 | ) |
| Hedging activities of equity method investments: | | | | |
| OCIL before reclassifications, net of tax | | 355 |
| | (109 | ) |
| Amounts reclassified from accumulated OCIL, net of tax | | (284 | ) | | 130 |
|
| Total current period activity of hedging activities of equity method investments, net of tax | | 71 |
| | 21 |
|
| Net current period benefit activities of equity method investments, net of tax | | (24 | ) | |
|
|
| Accumulated OCIL ending balance, net of tax | | $ | (237 | ) |
| $ | (284 | ) |
(1) AmountsIn 2016, Duke Energy sold its interest in parentheses indicate debitsthree of the Catamount Sweetwater, LLC wind farm projects. Duke Energy has a 47 percent ownership interest in each of the two other Catamount Sweetwater, LLC wind farm projects and 50 percent interest in DS Cornerstone, LLC, which owns wind farm projects in the U.S.
Impairment of Equity Method Investments
Duke Energy evaluated its investment in Constitution for OTTI as of December 31, 2017. Our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. Based upon these estimates using information known as of December 31, 2017, the fair value of Duke Energy's investment in Constitution approximated its carrying value. As a result, Duke Energy did not recognize any impairment charge in the year ended December 31, 2017. However, due to accumulated OCIL.the FERC’s January 2018 ruling and the resulting increase in uncertainty, Duke Energy is evaluating the potential to recognize a pretax impairment charge on its investment in Constitution during the first quarter of 2018 of up to the current carrying amount of the investment, net of salvage value and any cash and working capital returned. For additional information on the Constitution investment, see Note 4.
During the year ended December 31, 2016, Duke Energy recorded an OTTI of certain wind project investments. The $71 million pretax impairment was recorded within Equity in earnings (losses) of unconsolidated affiliates on Duke Energy's Consolidated Statements of Operations. The other-than-temporary decline in value of these investments was primarily attributable to a sustained decline in market pricing where the wind investments are located, projected net losses for the projects and a reduction in the projected cash distribution to the class of investment owned by Duke Energy.
Other
Duke Energy owns a 17.5 percent indirect interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. Duke Energy's economic ownership interest decreased from 25 percent to 17.5 percent with the successful startup of NMC's polyacetal production facility in 2017. Duke Energy retains 25 percent of the board representation and voting rights of NMC. The investment in NMC is accounted for under the equity method of accounting.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
13. RELATED PARTY TRANSACTIONS
The Subsidiary Registrants engage in related party transactions in accordance with the applicable state and federal commission regulations. Refer to the Consolidated Balance Sheets of the effectSubsidiary Registrants for balances due to or due from related parties. Material amounts related to transactions with related parties included in the Consolidated Statements of Operations and Comprehensive Income are presented in the following table. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy Carolinas | | | | | |
Corporate governance and shared service expenses(a) | $ | 858 |
| | $ | 831 |
| | $ | 914 |
|
Indemnification coverages(b) | 23 |
| | 22 |
| | 24 |
|
JDA revenue(c) | 49 |
| | 38 |
| | 51 |
|
JDA expense(c) | 145 |
| | 156 |
| | 183 |
|
Intercompany natural gas purchases(d) | 9 |
| | 2 |
| | — |
|
| Progress Energy | | | | | |
Corporate governance and shared service expenses(a) | $ | 736 |
| | $ | 710 |
| | $ | 712 |
|
Indemnification coverages(b) | 38 |
| | 35 |
| | 38 |
|
JDA revenue(c) | 145 |
| | 156 |
| | 183 |
|
JDA expense(c) | 49 |
| | 38 |
| | 51 |
|
Intercompany natural gas purchases(d) | 77 |
| | 19 |
| | — |
|
| Duke Energy Progress | | | | | |
Corporate governance and shared service expenses(a) | $ | 438 |
| | $ | 397 |
| | $ | 403 |
|
Indemnification coverages(b) | 15 |
| | 14 |
| | 16 |
|
JDA revenue(c) | 145 |
| | 156 |
| | 183 |
|
JDA expense(c) | 49 |
| | 38 |
| | 51 |
|
Intercompany natural gas purchases(d) | 77 |
| | 19 |
| | — |
|
| Duke Energy Florida | | | | | |
Corporate governance and shared service expenses(a) | $ | 298 |
| | $ | 313 |
| | $ | 309 |
|
Indemnification coverages(b) | 23 |
| | 21 |
| | 22 |
|
| Duke Energy Ohio | | | | | |
Corporate governance and shared service expenses(a) | $ | 363 |
| | $ | 356 |
| | $ | 342 |
|
Indemnification coverages(b) | 5 |
| | 5 |
| | 6 |
|
| Duke Energy Indiana | | | | | |
Corporate governance and shared service expenses(a) | $ | 370 |
| | $ | 366 |
| | $ | 349 |
|
Indemnification coverages(b) | 8 |
| | 8 |
| | 9 |
|
| Piedmont | | | | | |
Corporate governance and shared service expenses(a) | $ | 50 |
| | | | |
Indemnification coverages(b)
| 2 |
| | | | |
Intercompany natural gas sales(d)
| 86 |
| | | | |
| |
| (a) | The Subsidiary Registrants are charged their proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, information technology, legal and accounting fees, as well as other third-party costs. These amounts are primarily recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income. |
| |
| (b) | The Subsidiary Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy’s wholly owned captive insurance subsidiary. These expenses are recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income. |
| |
| (c) | Duke Energy Carolinas and Duke Energy Progress participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customer rates. Revenues from the sale of power and expenses from the purchase of power pursuant to the JDA are recorded in Operating Revenues and Fuel used in electric generation and purchased power, respectively, on the Consolidated Statements of Operations and Comprehensive Income. |
| |
| (d) | Piedmont provides long-term natural gas delivery service to certain Duke Energy Carolinas and Duke Energy Progress natural gas-fired generation facilities. Piedmont records the sales in Regulated natural gas revenues, and Duke Energy Carolinas and Duke Energy Progress record the related purchases in Fuel used in electric generation and purchased power on their respective Consolidated Statements of Operations and Comprehensive Income. The amounts are not eliminated in accordance with rate-based accounting regulations. For the two months ended December 31, 2016, and for sales made subsequent to the acquisition for the year ended October 31, 2016, Piedmont recorded $14 million and $7 million, respectively, of natural gas sales with Duke Energy. For sales made prior to the acquisition for the year ended October 31, 2016, and for the year ended October 31, 2015, Piedmont recorded $74 million and $83 million, respectively of natural gas sales with Duke Energy. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
In addition to the amounts presented above, the Subsidiary Registrants have other affiliate transactions, including rental of office space, participation in a money pool arrangement, other operational transactions and their proportionate share of certain line itemscharged expenses. See Note 6 for more information regarding money pool. These transactions of net income on amounts reclassified out of each component of accumulated OCIL is presented belowthe Subsidiary Registrants were not material for the years ended OctoberDecember 31, 20142017, 2016 and 2013.2015.
As discussed in Note 17, certain trade receivables have been sold by Duke Energy Ohio and Duke Energy Indiana to CRC, an affiliate formed by a subsidiary of Duke Energy. The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from CRC for a portion of the purchase price.
Refer to Note 2 for further information on the sale of the Midwest Generation Disposal Group.
Equity Method Investments
Piedmont has related party transactions as a customer of its equity method investments in natural gas storage and transportation facilities. The following table presents expenses that are included in Cost of natural gas on Piedmont's Consolidated Statements of Operations and Comprehensive Income. |
| | | | | | | | | | | | | |
| | | Year Ended December 31, | Two Months Ended December 31, | Years Ended October 31, |
| (in millions) | Type of expense | 2017 | 2016 | 2016 | 2015 |
| Cardinal | Transportation Costs | $ | 8 |
| $ | 2 |
| $ | 9 |
| $ | 9 |
|
| Pine Needle | Natural Gas Storage Costs | 8 |
| 2 |
| 11 |
| 11 |
|
| Hardy Storage | Natural Gas Storage Costs | 9 |
| 2 |
| 9 |
| 9 |
|
| Total | | $ | 25 |
| $ | 6 |
| $ | 29 |
| $ | 29 |
|
Piedmont had accounts payable to its equity method investments of $2 million at December 31, 2017, and 2016 related to these transactions. These amounts are included in Accounts payable on the Consolidated Balance Sheets.
Intercompany Income Taxes
Duke Energy and the Subsidiary Registrants file a consolidated federal income tax return and other state and jurisdictional returns. The Subsidiary Registrants have a tax sharing agreement with Duke Energy for the allocation of consolidated tax liabilities and benefits. Income taxes recorded represent amounts the Subsidiary Registrants would incur as separate C-Corporations. The following table includes the balance of intercompany income tax receivables and payables for the Subsidiary Registrants.
|
| | | | | | | | | | |
| | | Reclassification Out of Accumulated OCIL (1) | | |
| | | |
|
| | | Years Ended | | |
| | | October 31 | | Affected Line Items on Statement of Comprehensive Income |
| In thousands | | 2014 | | 2013 | |
| Hedging activities of equity method investments | | $ | (461 | ) | | $ | 215 |
| | Income from equity method investments |
| Income tax expense | | 177 |
| | (85 | ) | | Income taxes |
| Hedging activities of equity method investments | | (284 | ) | | $ | 130 |
| | |
| Net benefit activities of equity method investments | | (40 | ) | | | | Income from equity method investments |
| Income tax expense | | 16 |
| | | | Income taxes |
| Net benefit activities of equity method investments | | (24 | ) | | | | |
| Total reclassification for the period, net of tax | | $ | (308 | ) | | $ | 130 |
| | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| December 31, 2017 | | | | | | | |
| Intercompany income tax receivable | $ | — |
| $ | 168 |
| $ | — |
| $ | 44 |
| $ | 22 |
| $ | — |
| $ | 7 |
|
| Intercompany income tax payable | 44 |
| — |
| 21 |
| — |
| — |
| 35 |
| — |
|
| | | | | | | | |
| December 31, 2016 | | | | | | | |
| Intercompany income tax receivable | $ | 1 |
| $ | — |
| $ | — |
| $ | 37 |
| $ | — |
| $ | — |
| $ | — |
|
| Intercompany income tax payable | — |
| 37 |
| 90 |
| — |
| 1 |
| 3 |
| 38 |
|
14. DERIVATIVES AND HEDGING
The Duke Energy Registrants use commodity and interest rate contracts to manage commodity price risk and interest rate risk. The primary use of commodity derivatives is to hedge the generation portfolio against changes in parentheses indicate debitsthe prices of electricity and natural gas. Piedmont enters into natural gas supply contracts to accumulated OCIL.provide diversification, reliability and natural gas cost benefits to its customers. Interest rate swaps are used to manage interest rate risk associated with borrowings.
All derivative instruments not identified as NPNS are recorded at fair value as assets or liabilities on the Consolidated Balance Sheets. Cash collateral related to derivative instruments executed under master netting arrangements is offset against the collateralized derivatives on the Consolidated Balance Sheets. The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows.
INTEREST RATE RISK
76
7. Financial InstrumentsThe Duke Energy Registrants are exposed to changes in interest rates as a result of their issuance or anticipated issuance of variable-rate and Related Fair Valuefixed-rate debt and commercial paper. Interest rate risk is managed by limiting variable-rate exposures to a percentage of total debt and by monitoring changes in interest rates. To manage risk associated with changes in interest rates, the Duke Energy Registrants may enter into interest rate swaps, U.S. Treasury lock agreements and other financial contracts. In anticipation of certain fixed-rate debt issuances, a series of forward-starting interest rate swaps may be executed to lock in components of current market interest rates. These instruments are later terminated prior to or upon the issuance of the corresponding debt.
Derivative Assets and Liabilities under Master Netting Arrangements194
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
We maintain brokerage accountsCash Flow Hedges
For a derivative designated as hedging the exposure to facilitate transactionsvariable cash flows of a future transaction, referred to as a cash flow hedge, the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt. See the Consolidated Statements of Changes in Equity for gains and losses reclassified out of AOCI for the years ended December 31, 2017, and 2016. Duke Energy's interest rate derivatives designated as hedges include interest rate swaps used to hedge existing debt within the Commercial Renewables business.
Undesignated Contracts
Undesignated contracts include contracts not designated as a hedge because they are accounted for under regulatory accounting and contracts that support ourdo not qualify for hedge accounting.
Duke Energy’s interest rate swaps for its regulated operations employ regulatory accounting. With regulatory accounting, the mark-to-market gains or losses on the swaps are deferred as regulatory liabilities or regulatory assets, respectively. Regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process. The accrual of interest on the swaps is recorded as Interest Expense.
In August 2016, Duke Energy unwound $1.4 billion of forward-starting interest rate swaps associated with the Piedmont acquisition financing described in Note 6. The swaps were considered undesignated as they did not qualify for hedge accounting. Losses on the swaps of $190 million are included within Interest Expense on the Consolidated Statements of Operations for the year ended December 31, 2016. See Note 2 for additional information related to the Piedmont acquisition.
The following tables show notional amounts of outstanding derivatives related to interest rate risk. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
|
Cash flow hedges(a) | $ | 660 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Undesignated contracts | 927 |
| | 400 |
| | 500 |
| | 250 |
| | 250 |
| | 27 |
|
| Total notional amount | $ | 1,587 |
| | $ | 400 |
| | $ | 500 |
| | $ | 250 |
| | $ | 250 |
| | $ | 27 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
|
Cash flow hedges(a) | $ | 750 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Undesignated contracts | 927 |
| | 400 |
| | 500 |
| | 250 |
| | 250 |
| | 27 |
|
| Total notional amount | $ | 1,677 |
| | $ | 400 |
| | $ | 500 |
| | $ | 250 |
| | $ | 250 |
| | $ | 27 |
|
| |
| (a) | Duke Energy includes amounts related to consolidated VIEs of $660 million and $750 million at December 31, 2017, and 2016, respectively. During 2016, Duke Energy entered into interest rate swaps related to solar financing with an outstanding notional amount of $300 million, including $81 million of four-year swaps and $219 million of 18-year swaps, at December 31, 2016. See note 6 for additional information related to the solar facilities financing. |
COMMODITY PRICE RISK
The Duke Energy Registrants are exposed to the impact of changes in the prices of electricity purchased and sold in bulk power markets and coal and natural gas purchases, including Piedmont's natural gas supply contracts. Exposure to commodity price risk is influenced by a number of factors including the term of contracts, the liquidity of markets and delivery locations. For the Subsidiary Registrants, bulk power electricity and coal and natural gas purchases flow through fuel adjustment clauses, formula based contracts or other cost sharing mechanisms. Differences between the costs included in rates and the incurred costs, including undesignated derivative contracts, are largely deferred as regulatory assets or regulatory liabilities. Piedmont policies allow for the use of financial instruments to hedge commodity price risks. The strategy and objective of these hedging programs are to use the financial instruments to reduce gas cost hedging plans. volatility for customers.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Volumes
The accounting guidance related to derivativestables below include volumes of outstanding commodity derivatives. Amounts disclosed represent the absolute value of notional volumes of commodity contracts excluding NPNS. The Duke Energy Registrants have netted contractual amounts where offsetting purchase and hedging requires that we use a gross presentation, based on our election, forsale contracts exist with identical delivery locations and times of delivery. Where all commodity positions are perfectly offset, no quantities are shown. |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | |
| | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Indiana |
| | Piedmont |
|
| Electricity (gigawatt-hours) | 34 |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | — |
|
| Natural gas (millions of dekatherms) | 770 |
| | 105 |
| | 183 |
| | 133 |
| | 50 |
| | 2 |
| | 480 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | |
| | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Indiana |
| | Piedmont |
|
| Electricity (gigawatt-hours) | 147 |
| | — |
| | — |
| | — |
| | — |
| | 147 |
| | — |
|
| Natural gas (millions of dekatherms) | 890 |
| | 91 |
| | 269 |
| | 118 |
| | 151 |
| | 1 |
| | 529 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
LOCATION AND FAIR VALUE OF DERIVATIVE ASSETS AND LIABILITIES RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS
The following tables show the fair value amountsand balance sheet location of our derivative instruments. We use longAlthough derivatives subject to master netting arrangements are netted on the Consolidated Balance Sheets, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Assets | | December 31, 2017 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Commodity Contracts | | | | | | | | | | | | | | | | |
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 34 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 27 |
| | $ | 2 |
|
| Noncurrent | | 1 |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Total Derivative Assets – Commodity Contracts | | $ | 35 |
| | $ | 2 |
| | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 27 |
| | $ | 2 |
|
| Interest Rate Contracts | | | | | | | | | | | | | | | | |
| Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Noncurrent | | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Derivative Assets – Interest Rate Contracts | | $ | 16 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
| | $ | — |
|
| Total Derivative Assets | | $ | 51 |
| | $ | 2 |
| | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 27 |
| | $ | 2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Liabilities | | December 31, 2017 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Commodity Contracts | | | | | | | | | | | | | | | | |
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 36 |
| | $ | 6 |
| | $ | 18 |
| | $ | 8 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Noncurrent | | 146 |
| | 4 |
| | 10 |
| | 4 |
| | — |
| | — |
| | — |
| | 131 |
|
| Total Derivative Liabilities – Commodity Contracts | | $ | 182 |
| | $ | 10 |
| | $ | 28 |
| | $ | 12 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 142 |
|
| Interest Rate Contracts | | | | | | | | | | | | | | | | |
| Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 29 |
| | $ | 25 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Noncurrent | | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
| Noncurrent | | 12 |
| | — |
| | 7 |
| | 6 |
| | 2 |
| | 4 |
| | — |
| | — |
|
| Total Derivative Liabilities – Interest Rate Contracts | | $ | 48 |
| | $ | 25 |
| | $ | 8 |
| | $ | 6 |
| | $ | 2 |
| | $ | 5 |
| | $ | — |
| | $ | — |
|
| Total Derivative Liabilities | | $ | 230 |
| | $ | 35 |
| | $ | 36 |
| | $ | 18 |
| | $ | 12 |
| | $ | 5 |
| | $ | — |
| | $ | 142 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Assets | | December 31, 2016 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Commodity Contracts | | | | | | | | | | | | | | | | |
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 108 |
| | $ | 23 |
| | $ | 61 |
| | $ | 35 |
| | $ | 26 |
| | $ | 4 |
| | $ | 16 |
| | $ | 3 |
|
| Noncurrent | | 32 |
| | 10 |
| | 21 |
| | 10 |
| | 11 |
| | 1 |
| | — |
| | — |
|
| Total Derivative Assets – Commodity Contracts | | $ | 140 |
| | $ | 33 |
| | $ | 82 |
| | $ | 45 |
| | $ | 37 |
| | $ | 5 |
| | $ | 16 |
|
| $ | 3 |
|
| Interest Rate Contracts | | | | | | | | | | | | | | | | |
| Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Noncurrent | | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | 3 |
| | — |
| | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| | — |
|
| Total Derivative Assets – Interest Rate Contracts | | $ | 22 |
| | $ | — |
| | $ | 3 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total Derivative Assets | | $ | 162 |
| | $ | 33 |
| | $ | 85 |
| | $ | 46 |
| | $ | 39 |
| | $ | 5 |
| | $ | 16 |
| | $ | 3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Liabilities | | December 31, 2016 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Commodity Contracts | | | | | | | | | | | | | | | | |
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 43 |
| | $ | — |
| | $ | 12 |
| | $ | — |
| | $ | 12 |
| | $ | — |
| | $ | 2 |
| | $ | 35 |
|
| Noncurrent | | 166 |
| | 1 |
| | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | 152 |
|
| Total Derivative Liabilities – Commodity Contracts | | $ | 209 |
| | $ | 1 |
| | $ | 19 |
| | $ | 1 |
| | $ | 12 |
| | $ | — |
| | $ | 2 |
| | $ | 187 |
|
| Interest Rate Contracts | | | | | | | | | | | | | | | | |
| Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Noncurrent | | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Not Designated as Hedging Instruments | | | | | | | | | | | | | | | | |
| Current | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
| Noncurrent | | 26 |
| | 15 |
| | 6 |
| | 6 |
| | — |
| | 5 |
| | — |
| | — |
|
| Total Derivative Liabilities – Interest Rate Contracts | | $ | 43 |
| | $ | 15 |
| | $ | 6 |
| | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
|
| Total Derivative Liabilities | | $ | 252 |
| | $ | 16 |
| | $ | 25 |
| | $ | 7 |
| | $ | 12 |
| | $ | 6 |
| | $ | 2 |
| | $ | 187 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
OFFSETTING ASSETS AND LIABILITIES
The following tables present the line items on the Consolidated Balance Sheets where derivatives are reported. Substantially all of Duke Energy's outstanding derivative contracts are subject to enforceable master netting arrangements. The Gross amounts offset in the tables below show the effect of these netting arrangements on financial position gas purchase optionsand include collateral posted to provide some level of protection for our customersoffset the net position. The amounts shown are calculated by counterparty. Accounts receivable or accounts payable may also be available to offset exposures in the event of significant commodity price increases. As of October 31, 2014 and 2013, we had long gas purchase options providing total coverage of 29.2 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at October 31, 2014bankruptcy. These amounts are fornot included in the period from December 2014 through November 2015.tables below. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Assets | | December 31, 2017 | | |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Current | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 35 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 27 |
| | $ | 2 |
|
| Gross amounts offset | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Current Assets: Other | | $ | 35 |
|
| $ | 2 |
|
| $ | 2 |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | 1 |
|
| $ | 27 |
| | $ | 2 |
|
| Noncurrent | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 16 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Gross amounts offset | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Other Noncurrent Assets: Other | | $ | 16 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Liabilities | | December 31, 2017 | | |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Current | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 66 |
| | $ | 31 |
| | $ | 19 |
| | $ | 8 |
| | $ | 10 |
| | $ | 1 |
| | $ | — |
| | $ | 11 |
|
| Gross amounts offset | | (3 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Current Liabilities: Other | | $ | 63 |
| | $ | 29 |
| | $ | 17 |
| | $ | 6 |
| | $ | 10 |
| | $ | 1 |
| | $ | — |
| | $ | 11 |
|
| Noncurrent | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 164 |
| | $ | 4 |
| | $ | 17 |
| | $ | 10 |
| | $ | 2 |
| | $ | 4 |
| | $ | — |
| | $ | 131 |
|
| Gross amounts offset | | (1 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Other Noncurrent Liabilities: Other | | $ | 163 |
| | $ | 4 |
| | $ | 16 |
| | $ | 9 |
| | $ | 2 |
| | $ | 4 |
| | $ | — |
| | $ | 131 |
|
Fair Value Measurements199
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
We use financial instruments |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Assets | | December 31, 2016 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Current | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 111 |
| | $ | 23 |
| | $ | 64 |
| | $ | 36 |
| | $ | 28 |
| | $ | 4 |
| | $ | 16 |
| | $ | 3 |
|
| Gross amounts offset | | (11 | ) | | — |
| | (11 | ) | | — |
| | (11 | ) | | — |
| | — |
| | — |
|
| Net amounts presented in Current Assets: Other | | $ | 100 |
| | $ | 23 |
| | $ | 53 |
| | $ | 36 |
| | $ | 17 |
| | $ | 4 |
| | $ | 16 |
| | $ | 3 |
|
| Noncurrent | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 51 |
| | $ | 10 |
| | $ | 21 |
| | $ | 10 |
| | $ | 11 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Gross amounts offset | | (2 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Other Noncurrent Assets: Other | | $ | 49 |
| | $ | 9 |
| | $ | 20 |
| | $ | 9 |
| | $ | 11 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative Liabilities | | December 31, 2016 |
| | | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Current | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 52 |
| | $ | — |
| | $ | 12 |
| | $ | — |
| | $ | 12 |
| | $ | 1 |
| | $ | 2 |
| | $ | 35 |
|
| Gross amounts offset | | (11 | ) | | — |
| | (11 | ) | | — |
| | (11 | ) | | — |
| | — |
| | — |
|
| Net amounts presented in Current Liabilities: Other | | $ | 41 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| | $ | 35 |
|
| Noncurrent | | | | | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 200 |
| | $ | 16 |
| | $ | 13 |
| | $ | 7 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 152 |
|
| Gross amounts offset | | (2 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in Other Noncurrent Liabilities: Other | | $ | 198 |
| | $ | 15 |
| | $ | 12 |
| | $ | 6 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 152 |
|
OBJECTIVE CREDIT CONTINGENT FEATURES
Certain derivative contracts contain objective credit contingent features. These features include the requirement to post cash collateral or letters of credit if specific events occur, such as a credit rating downgrade below investment grade. The following tables show information with respect to derivative contracts that are not designatedin a net liability position and contain objective credit-risk-related payment provisions. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
|
| Aggregate fair value of derivatives in a net liability position | $ | 59 |
| | $ | 35 |
| | $ | 25 |
| | $ | 15 |
| | $ | 10 |
|
| Fair value of collateral already posted | — |
| | — |
| | — |
| | — |
| | — |
|
| Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | 59 |
| | 35 |
| | 25 |
| | 15 |
| | 10 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
|
| Aggregate fair value of derivatives in a net liability position | $ | 34 |
| | $ | 16 |
| | $ | 18 |
| | $ | 6 |
| | $ | 12 |
|
| Fair value of collateral already posted | — |
| | — |
| | — |
| | — |
| | — |
|
| Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | 34 |
| | 16 |
| | 18 |
| | 6 |
| | 12 |
|
The Duke Energy Registrants have elected to offset cash collateral and fair values of derivatives. For amounts to be netted, the derivative and cash collateral must be executed with the same counterparty under the same master netting arrangement.
15. INVESTMENTS IN DEBT AND EQUITY SECURITIES
The Duke Energy Registrants classify their investments in debt and equity securities as hedges for accounting purposes to mitigate commodity price risk for our customers. We also have marketableeither trading or available-for-sale.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
TRADING SECURITIES
Piedmont's investments in debt and equity securities that are held in rabbi trusts established forassociated with certain of our deferred compensation plans. In developing ourplans are classified as trading securities. The fair value measurements of these investments was $1 million and $5 million as of December 31, 2017, and 2016, respectively.
AVAILABLE-FOR-SALE (AFS) SECURITIES
All other investments in debt and equity securities are classified as AFS.
Duke Energy’s AFS securities are primarily comprised of investments held in (i) the nuclear decommissioning trust funds (NDTF) at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, (ii) grantor trusts at Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana related to OPEB plans and (iii) Bison.
Duke Energy classifies all other investments in debt and equity securities as long term, unless otherwise noted.
Investment Trusts
The investments within the NDTF investments and the Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana grantor trusts (Investment Trusts) are managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreements. The Duke Energy Registrants have limited oversight of the day-to-day management of these investments. As a result, the ability to hold investments in unrealized loss positions is outside the control of the Duke Energy Registrants. Accordingly, all unrealized losses associated with debt and equity securities within the Investment Trusts are considered OTTIs and are recognized immediately.
Investments within the Investment Trusts generally qualify for regulatory accounting and accordingly realized and unrealized gains and losses are generally deferred as a regulatory asset or liability.
Substantially all amounts of the Duke Energy Registrants' gross unrealized holding losses as of December 31, 2017, and 2016, are considered OTTIs on investments within Investment Trusts that have been recognized immediately as a regulatory asset.
Other AFS Securities
Unrealized gains and losses on all other AFS securities are included in other comprehensive income until realized, unless it is determined the carrying value of an investment is other-than-temporarily impaired. If an OTTI exists, the unrealized loss is included in earnings based on the criteria discussed below.
The Duke Energy Registrants analyze all investment holdings each reporting period to determine whether a decline in fair value should be considered other-than-temporary. Criteria used to evaluate whether an impairment associated with equity securities is other-than-temporary includes, but is not limited to, (i) the length of time over which the market value has been lower than the cost basis of the investment, (ii) the percentage decline compared to the cost of the investment and (iii) management’s intent and ability to retain its investment for a period of time sufficient to allow for any anticipated recovery in market value. If a decline in fair value is determined to be other-than-temporary, the investment is written down to its fair value through a charge to earnings.
If the entity does not have an intent to sell a debt security and it is not more likely than not management will be required to sell the debt security before the recovery of its cost basis, the impairment write-down to fair value would be recorded as a component of other comprehensive income, except for when it is determined a credit loss exists. In determining whether a credit loss exists, management considers, among other things, (i) the length of time and the extent to which the fair value has been less than the amortized cost basis, (ii) changes in the financial instruments, we utilizecondition of the issuer of the security, or in the case of an asset backed security, the financial condition of the underlying loan obligors, (iii) consideration of underlying collateral and guarantees of amounts by government entities, (iv) ability of the issuer of the security to make scheduled interest or principal payments and (v) any changes to the rating of the security by rating agencies. If a credit loss exists, the amount of impairment write-down to fair value is split between credit loss and other factors. The amount related to credit loss is recognized in earnings. The amount related to other factors is recognized in other comprehensive income. There were no material credit losses as of December 31, 2017, and 2016.
Other Investments amounts are recorded in Other within Other Noncurrent Assets on the Consolidated Balance Sheets.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DUKE ENERGY
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| NDTF | | | | | | | | | |
| | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 115 |
| | $ | — |
| | $ | — |
| | $ | 111 |
|
| Equity securities | 2,805 |
| | 27 |
| | 4,914 |
| | 2,092 |
| | 54 |
| | 4,106 |
|
| Corporate debt securities | 17 |
| | 2 |
| | 570 |
| | 10 |
| | 8 |
| | 528 |
|
| Municipal bonds | 4 |
| | 3 |
| | 344 |
| | 3 |
| | 10 |
| | 331 |
|
| U.S. government bonds | 11 |
| | 7 |
| | 1,027 |
| | 10 |
| | 8 |
| | 984 |
|
| Other debt securities | — |
| | 1 |
| | 118 |
| | — |
| | 3 |
| | 124 |
|
| Total NDTF | $ | 2,837 |
| | $ | 40 |
| | $ | 7,088 |
| | $ | 2,115 |
| | $ | 83 |
| | $ | 6,184 |
|
| Other Investments | |
| | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 25 |
|
| Equity securities | 59 |
| | — |
| | 123 |
| | 38 |
| | — |
| | 104 |
|
| Corporate debt securities | 1 |
| | — |
| | 57 |
| | 1 |
| | 1 |
| | 66 |
|
| Municipal bonds | 2 |
| | 1 |
| | 83 |
| | 2 |
| | 1 |
| | 82 |
|
| U.S. government bonds | — |
| | — |
| | 41 |
| | — |
| | 1 |
| | 51 |
|
| Other debt securities | — |
| | 1 |
| | 44 |
| | — |
| | 2 |
| | 42 |
|
| Total Other Investments | $ | 62 |
| | $ | 2 |
| | $ | 363 |
| | $ | 41 |
| | $ | 5 |
| | $ | 370 |
|
| Total Investments | $ | 2,899 |
| | $ | 42 |
| | $ | 7,451 |
| | $ | 2,156 |
| | $ | 88 |
| | $ | 6,554 |
|
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 117 |
|
| Due after one through five years | 552 |
|
| Due after five through 10 years | 554 |
|
| Due after 10 years | 1,061 |
|
| Total | $ | 2,284 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Realized gains | $ | 202 |
| | $ | 246 |
| | $ | 193 |
|
| Realized losses | 160 |
| | 187 |
| | 98 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DUKE ENERGY CAROLINAS
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| NDTF | | | | | | | | | | | |
|
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| Equity securities | 1,531 |
| | 12 |
| | 2,692 |
| | 1,157 |
| | 28 |
| | 2,245 |
|
| Corporate debt securities | 9 |
| | 2 |
| | 359 |
| | 5 |
| | 6 |
| | 354 |
|
| Municipal bonds | — |
| | 1 |
| | 60 |
| | 1 |
| | 2 |
| | 67 |
|
| U.S. government bonds | 3 |
| | 4 |
| | 503 |
| | 2 |
| | 5 |
| | 458 |
|
| Other debt securities | — |
| | 1 |
| | 112 |
| | — |
| | 3 |
| | 116 |
|
Total NDTF | $ | 1,543 |
| | $ | 20 |
| | $ | 3,758 |
| | $ | 1,165 |
| | $ | 44 |
| | $ | 3,258 |
|
| Other Investments | |
| | |
| | |
| | |
| | |
| | |
|
| Other debt securities | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
|
| Total Other Investments | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
|
| Total Investments | $ | 1,543 |
| | $ | 20 |
| | $ | 3,758 |
| | $ | 1,165 |
| | $ | 45 |
| | $ | 3,261 |
|
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 9 |
|
| Due after one through five years | 204 |
|
| Due after five through 10 years | 300 |
|
| Due after 10 years | 521 |
|
| Total | $ | 1,034 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Realized gains | $ | 135 |
| | $ | 157 |
| | $ | 158 |
|
| Realized losses | 103 |
| | 121 |
| | 83 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
PROGRESS ENERGY
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| NDTF | | | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 93 |
|
| Equity securities | 1,274 |
| | 15 |
| | 2,222 |
| | 935 |
| | 26 |
| | 1,861 |
|
| Corporate debt securities | 8 |
| | — |
| | 211 |
| | 5 |
| | 2 |
| | 174 |
|
| Municipal bonds | 4 |
| | 2 |
| | 284 |
| | 2 |
| | 8 |
| | 264 |
|
| U.S. government bonds | 8 |
| | 3 |
| | 524 |
| | 8 |
| | 3 |
| | 526 |
|
| Other debt securities | — |
| | — |
| | 6 |
| | — |
| | — |
| | 8 |
|
| Total NDTF | $ | 1,294 |
| | $ | 20 |
| | $ | 3,330 |
| | $ | 950 |
| | $ | 39 |
| | $ | 2,926 |
|
| Other Investments | |
| | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Municipal bonds | 2 |
| | — |
| | 47 |
| | 2 |
| | — |
| | 44 |
|
| Total Other Investments | $ | 2 |
| | $ | — |
| | $ | 59 |
| | $ | 2 |
| | $ | — |
| | $ | 65 |
|
| Total Investments | $ | 1,296 |
| | $ | 20 |
| | $ | 3,389 |
| | $ | 952 |
| | $ | 39 |
| | $ | 2,991 |
|
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 94 |
|
| Due after one through five years | 301 |
|
| Due after five through 10 years | 203 |
|
| Due after 10 years | 474 |
|
| Total | $ | 1,072 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Realized gains | $ | 65 |
| | $ | 84 |
| | $ | 33 |
|
| Realized losses | 56 |
| | 64 |
| | 13 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DUKE ENERGY PROGRESS
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| NDTF | | | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 50 |
| | $ | — |
| | $ | — |
| | $ | 45 |
|
| Equity securities | 980 |
| | 12 |
| | 1,795 |
| | 704 |
| | 21 |
| | 1,505 |
|
| Corporate debt securities | 6 |
| |
|
| | 149 |
| | 4 |
| | 1 |
| | 120 |
|
| Municipal bonds | 4 |
| | 2 |
| | 283 |
| | 2 |
| | 8 |
| | 263 |
|
| U.S. government bonds | 5 |
| | 2 |
| | 310 |
| | 5 |
| | 2 |
| | 275 |
|
| Other debt securities | — |
| | — |
| | 4 |
| | — |
| | — |
| | 5 |
|
| Total NDTF | $ | 995 |
| | $ | 16 |
| | $ | 2,591 |
| | $ | 715 |
| | $ | 32 |
| | $ | 2,213 |
|
| Other Investments | |
| | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Total Other Investments | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Total Investments | $ | 995 |
| | $ | 16 |
| | $ | 2,592 |
| | $ | 715 |
| | $ | 32 |
| | $ | 2,214 |
|
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 21 |
|
| Due after one through five years | 219 |
|
| Due after five through 10 years | 146 |
|
| Due after 10 years | 360 |
|
| Total | $ | 746 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Realized gains | $ | 54 |
| | $ | 71 |
| | $ | 26 |
|
| Realized losses | 48 |
| | 55 |
| | 11 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DUKE ENERGY FLORIDA
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| NDTF | | | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | 48 |
|
| Equity securities | 294 |
| | 3 |
| | 427 |
| | 231 |
| | 5 |
| | 356 |
|
| Corporate debt securities | 2 |
| | — |
| | 62 |
| | 1 |
| | 1 |
| | 54 |
|
| Municipal bonds | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| U.S. government bonds | 3 |
| | 1 |
| | 214 |
| | 3 |
| | 1 |
| | 251 |
|
| Other debt securities | — |
| | — |
| | 2 |
| | — |
| | — |
| | 3 |
|
Total NDTF(a) | $ | 299 |
| | $ | 4 |
| | $ | 739 |
| | $ | 235 |
| | $ | 7 |
| | $ | 713 |
|
| Other Investments | |
| | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Municipal bonds | 2 |
| | — |
| | 47 |
| | 2 |
| | — |
| | 44 |
|
| Total Other Investments | $ | 2 |
| | $ | — |
| | $ | 48 |
| | $ | 2 |
| | $ | — |
| | $ | 48 |
|
| Total Investments | $ | 301 |
| | $ | 4 |
| | $ | 787 |
| | $ | 237 |
| | $ | 7 |
| | $ | 761 |
|
| |
| (a) | During the year ended December 31, 2017, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3 nuclear plant. |
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 73 |
|
| Due after one through five years | 82 |
|
| Due after five through 10 years | 57 |
|
| Due after 10 years | 114 |
|
| Total | $ | 326 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were as follows. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Realized gains | $ | 11 |
| | $ | 13 |
| | $ | 7 |
|
| Realized losses | 8 |
| | 9 |
| | 2 |
|
DUKE ENERGY INDIANA
The following table presents the estimated fair value of investments in AFS securities. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross |
| | Gross |
| | | | Gross |
| | Gross |
| | |
| | Unrealized |
| | Unrealized |
| | | | Unrealized |
| | Unrealized |
| | |
| | Holding |
| | Holding |
| | Estimated |
| | Holding |
| | Holding |
| | Estimated |
|
| (in millions) | Gains |
| | Losses |
| | Fair Value |
| | Gains |
| | Losses(a) |
| | Fair Value |
|
| Other Investments | | | | | | | | | | | |
| Equity securities | $ | 49 |
| | $ | — |
| | $ | 97 |
| | $ | 33 |
| | $ | — |
| | $ | 79 |
|
| Corporate debt securities | — |
| | — |
| | 3 |
| | — |
| | — |
| | 2 |
|
| Municipal bonds | — |
| | 1 |
| | 28 |
| | — |
| | 1 |
| | 28 |
|
| U.S. government bonds | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Total Other Investments | $ | 49 |
| | $ | 1 |
| | $ | 128 |
| | $ | 33 |
| | $ | 1 |
| | $ | 110 |
|
| Total Investments | $ | 49 |
| | $ | 1 |
| | $ | 128 |
| | $ | 33 |
| | $ | 1 |
| | $ | 110 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The table below summarizes the maturity date for debt securities. |
| | | |
| (in millions) | December 31, 2017 |
|
| Due in one year or less | $ | 5 |
|
| Due after one through five years | 12 |
|
| Due after five through 10 years | 7 |
|
| Due after 10 years | 7 |
|
| Total | $ | 31 |
|
Realized gains and losses, which were determined on a specific identification basis, from sales of AFS securities were insignificant for the years ended December 31, 2017, 2016 and 2015.
16. FAIR VALUE MEASUREMENTS
Fair value is the exchange price to sell an asset or transfer a liability in an orderly transaction between market participants at the measurement date. The fair value definition focuses on an exit price versus the acquisition cost. Fair value measurements use market data or assumptions market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs may be readily observable, corroborated by market data, or generally unobservable. Valuation techniques maximize the use of observable inputs and minimize use of unobservable inputs. A midmarket pricing convention (the midpoint price between bid and ask prices) is permitted for use as a practical expedient.
Fair value refersmeasurements are classified in three levels based on the fair value hierarchy:
Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities that the reporting entity can access at the measurement date. An active market is one in which transactions for an asset or liability occur with sufficient frequency and volume to provide ongoing pricing information.
Level 2 – A fair value measurement utilizing inputs other than quoted prices included in Level 1 that are observable, either directly or indirectly, for an asset or liability. Inputs include (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in markets that are not active, and (iii) inputs other than quoted market prices that are observable for the asset or liability, such as interest rate curves and yield curves observable at commonly quoted intervals, volatilities and credit spreads. A Level 2 measurement cannot have more than an insignificant portion of its valuation based on unobservable inputs. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards, swaps and options; certain marketable debt securities; and financial instruments traded in less than active markets.
Level 3 – Any fair value measurement which includes unobservable inputs for more than an insignificant portion of the valuation. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 measurements may include longer-term instruments that extend into periods in which observable inputs are not available.
Not Categorized – Certain investments are not categorized within the Fair Value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.
Fair value accounting guidance permits entities to elect to measure certain financial instruments that are not required to be accounted for at fair value, such as equity method investments or the company’s own debt, at fair value. The Duke Energy Registrants have not elected to record any of these items at fair value.
Transfers between levels represent assets or liabilities that were previously (i) categorized at a higher level for which the inputs to the estimate became less observable or (ii) classified at a lower level for which the inputs became more observable during the period. The Duke Energy Registrant’s policy is to recognize transfers between levels of the fair value hierarchy at the end of the period. There were no transfers between levels during the years ended December 31, 2017, 2016 and 2015. In addition, for Piedmont, there were no transfers between levels during the two months ended December 31, 2016, and the years ended October 31, 2016, and 2015.
Valuation methods of the primary fair value measurements disclosed below are as follows.
Investments in equity securities
The majority of investments in equity securities are valued using Level 1 measurements. Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the quarter. Principal active markets for equity prices include published exchanges such as the New York Stock Exchange (NYSE) and the NASDAQ Stock Market. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. There was no after-hours market activity that was required to be reflected in the reported fair value measurements.
Investments in debt securities
Most investments in debt securities are valued using Level 2 measurements because the valuations use interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Commodity derivatives
Commodity derivatives with clearinghouses are classified as Level 1. Other commodity derivatives, including Piedmont's natural gas supply contracts, are primarily valued using internally developed discounted cash flow models that incorporate forward price, adjustments for liquidity (bid-ask spread) and credit or non-performance risk (after reflecting credit enhancements such as collateral) and are discounted to present value. Pricing inputs are derived from published exchange transaction prices and other observable data sources. In the absence of an active market, the last available price may be used. If forward price curves are not observable for the full term of the contract and the unobservable period had more than an insignificant impact on the valuation, the commodity derivative is classified as Level 3. In isolation, increases (decreases) in natural gas forward prices result in favorable (unfavorable) fair value adjustments for gas purchase contracts; and increases (decreases) in electricity forward prices result in unfavorable (favorable) fair value adjustments for electricity sales contracts. Duke Energy regularly evaluates and validates pricing inputs used to estimate the fair value of natural gas commodity contracts by a market participant price verification procedure. This procedure provides a comparison of internal forward commodity curves to market participant generated curves.
Interest rate derivatives
Most over-the-counter interest rate contract derivatives are valued using financial models that utilize observable inputs for similar instruments and are classified as Level 2. Inputs include forward interest rate curves, notional amounts, interest rates and credit quality of the counterparties.
Other fair value considerations
See Note 11 for a discussion of the valuation of goodwill and intangible assets. See Note 2 related to the acquisition of Piedmont in 2016 and the purchase of NCEMPA's ownership interests in certain generating assets in 2015.
DUKE ENERGY
The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. Derivative amounts in the table below for all Duke Energy Registrants exclude cash collateral, which is disclosed in Note 14. See Note 15 for additional information related to investments by major security type for the Duke Energy Registrants. |
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
| Not Categorized |
|
| NDTF equity securities | $ | 4,914 |
| $ | 4,840 |
| $ | — |
| $ | — |
| $ | 74 |
|
| NDTF debt securities | 2,174 |
| 635 |
| 1,539 |
| — |
| — |
|
| Other AFS equity securities | 123 |
| 123 |
| — |
| — |
| — |
|
| Other trading and AFS debt securities | 241 |
| 57 |
| 184 |
| — |
| — |
|
| Derivative assets | 51 |
| 3 |
| 20 |
| 28 |
| — |
|
| Total assets | 7,503 |
| 5,658 |
| 1,743 |
| 28 |
| 74 |
|
| Derivative liabilities | (230 | ) | (2 | ) | (86 | ) | (142 | ) | — |
|
| Net assets (liabilities) | $ | 7,273 |
| $ | 5,656 |
| $ | 1,657 |
| $ | (114 | ) | $ | 74 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
| Not Categorized |
|
| NDTF equity securities | $ | 4,106 |
| $ | 4,029 |
| $ | — |
| $ | — |
| $ | 77 |
|
| NDTF debt securities | 2,078 |
| 632 |
| 1,446 |
| — |
| — |
|
| Other trading and AFS equity securities | 104 |
| 104 |
| — |
| — |
| — |
|
| Other trading and AFS debt securities | 266 |
| 75 |
| 186 |
| 5 |
| — |
|
| Derivative assets | 162 |
| 5 |
| 136 |
| 21 |
| — |
|
| Total assets | 6,716 |
| 4,845 |
| 1,768 |
| 26 |
| 77 |
|
| Derivative liabilities | (252 | ) | (2 | ) | (63 | ) | (187 | ) | — |
|
| Net assets | $ | 6,464 |
| $ | 4,843 |
| $ | 1,705 |
| $ | (161 | ) | $ | 77 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following tables provide reconciliations of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. Amounts included in earnings for derivatives are primarily included in Cost of natural gas on the Duke Energy Registrants' Consolidated Statements of Operations and Comprehensive Income. Amounts included in changes of net assets on the Duke Energy Registrants' Consolidated Balance Sheets are included in regulatory assets or liabilities. All derivative assets and liabilities are presented on a net basis. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | | | | | | | | | | | |
| (in millions) | Investments |
| | Derivatives (net) |
| | Total |
| | Investments |
| | Derivatives (net) |
| | Total |
|
| Balance at beginning of period | $ | 5 |
| | $ | (166 | ) | | $ | (161 | ) | | $ | 5 |
| | $ | 10 |
| | $ | 15 |
|
| Total pretax realized or unrealized gains included in comprehensive income | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
| Derivative liability resulting from the acquisition of Piedmont | — |
| | — |
| | — |
| | — |
| | (187 | ) | | (187 | ) |
| Purchases, sales, issuances and settlements: | | | | |
|
| | | | | | |
| Purchases | — |
| | 55 |
| | 55 |
| | — |
| | 33 |
| | 33 |
|
| Sales | (6 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
|
| Settlements | — |
| | (47 | ) | | (47 | ) | | — |
| | (28 | ) | | (28 | ) |
| Total gains included on the Consolidated Balance Sheet | — |
| | 44 |
| | 44 |
| | — |
| | 6 |
| | 6 |
|
| Balance at end of period | $ | — |
|
| $ | (114 | ) | | $ | (114 | ) | | $ | 5 |
| | $ | (166 | ) | | $ | (161 | ) |
DUKE ENERGY CAROLINAS
The following tables provide recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | |
| | December 31, 2017 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
| Not Categorized |
|
| NDTF equity securities | $ | 2,692 |
| $ | 2,618 |
| $ | — |
| $ | — |
| $ | 74 |
|
| NDTF debt securities | 1,066 |
| 204 |
| 862 |
| — |
| — |
|
| Derivative assets | 2 |
| — |
| 2 |
| — |
| — |
|
| Total assets | 3,760 |
| 2,822 |
| 864 |
| — |
| 74 |
|
| Derivative liabilities | (35 | ) | (1 | ) | (34 | ) | — |
| — |
|
| Net assets | $ | 3,725 |
| $ | 2,821 |
| $ | 830 |
| $ | — |
| $ | 74 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
| Not Categorized |
|
| NDTF equity securities | $ | 2,245 |
| $ | 2,168 |
| $ | — |
| $ | — |
| $ | 77 |
|
| NDTF debt securities | 1,013 |
| 178 |
| 835 |
| — |
| — |
|
| Other AFS debt securities | 3 |
| — |
| — |
| 3 |
| — |
|
| Derivative assets | 33 |
| — |
| 33 |
| — |
| — |
|
| Total assets | 3,294 |
| 2,346 |
| 868 |
| 3 |
| 77 |
|
| Derivative liabilities | (16 | ) | — |
| (16 | ) | — |
| — |
|
| Net assets | $ | 3,278 |
| $ | 2,346 |
| $ | 852 |
| $ | 3 |
| $ | 77 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table provides reconciliations of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. |
| | | | | | | |
| | Investments |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| Balance at beginning of period | $ | 3 |
| | $ | 3 |
|
| Total pretax realized or unrealized gains included in comprehensive income | 1 |
| | — |
|
| Purchases, sales, issuances and settlements: | | | |
| Sales | (4 | ) | | — |
|
| Balance at end of period | $ | — |
|
| $ | 3 |
|
PROGRESS ENERGY
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| | Total Fair Value |
| Level 1 |
| Level 2 |
|
| NDTF equity securities | $ | 2,222 |
| $ | 2,222 |
| $ | — |
| | $ | 1,861 |
| $ | 1,861 |
| $ | — |
|
| NDTF debt securities | 1,108 |
| 431 |
| 677 |
| | 1,065 |
| 454 |
| 611 |
|
| Other AFS debt securities | 59 |
| 12 |
| 47 |
| | 65 |
| 21 |
| 44 |
|
| Derivative assets | 3 |
| 1 |
| 2 |
| | 85 |
| — |
| 85 |
|
| Total assets | 3,392 |
| 2,666 |
| 726 |
| | 3,076 |
| 2,336 |
| 740 |
|
| Derivative liabilities | (36 | ) | (1 | ) | (35 | ) | | (25 | ) | — |
| (25 | ) |
| Net assets | $ | 3,356 |
| $ | 2,665 |
| $ | 691 |
| | $ | 3,051 |
| $ | 2,336 |
| $ | 715 |
|
DUKE ENERGY PROGRESS
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| | Total Fair Value |
| Level 1 |
| Level 2 |
|
| NDTF equity securities | $ | 1,795 |
| $ | 1,795 |
| $ | — |
| | $ | 1,505 |
| $ | 1,505 |
| $ | — |
|
| NDTF debt securities | 796 |
| 243 |
| 553 |
| | 708 |
| 207 |
| 501 |
|
| Other AFS debt securities | 1 |
| 1 |
| — |
| | 1 |
| 1 |
| — |
|
| Derivative assets | 2 |
| 1 |
| 1 |
| | 46 |
| — |
| 46 |
|
| Total assets | 2,594 |
| 2,040 |
| 554 |
| | 2,260 |
| 1,713 |
| 547 |
|
| Derivative liabilities | (18 | ) | (1 | ) | (17 | ) | | (7 | ) | — |
| (7 | ) |
| Net assets | $ | 2,576 |
| $ | 2,039 |
| $ | 537 |
| | $ | 2,253 |
| $ | 1,713 |
| $ | 540 |
|
DUKE ENERGY FLORIDA
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| | Total Fair Value |
| Level 1 |
| Level 2 |
|
| NDTF equity securities | $ | 427 |
| $ | 427 |
| $ | — |
| | $ | 356 |
| $ | 356 |
| $ | — |
|
| NDTF debt securities | 312 |
| 188 |
| 124 |
| | 357 |
| 247 |
| 110 |
|
| Other AFS debt securities | 48 |
| 1 |
| 47 |
| | 48 |
| 4 |
| 44 |
|
| Derivative assets | 1 |
| — |
| 1 |
| | 39 |
| — |
| 39 |
|
| Total assets | 788 |
| 616 |
| 172 |
| | 800 |
| 607 |
| 193 |
|
| Derivative liabilities | (12 | ) | — |
| (12 | ) | | (12 | ) | — |
| (12 | ) |
| Net assets | $ | 776 |
| $ | 616 |
| $ | 160 |
| | $ | 788 |
| $ | 607 |
| $ | 181 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DUKE ENERGY OHIO
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 2 |
| Level 3 |
| | Total Fair Value |
| Level 2 |
| Level 3 |
|
| Derivative assets | $ | 1 |
| $ | — |
| $ | 1 |
| | $ | 5 |
| $ | — |
| $ | 5 |
|
| Derivative liabilities | (5 | ) | (5 | ) | — |
| | (6 | ) | (6 | ) | — |
|
| Net (liabilities) assets | $ | (4 | ) | $ | (5 | ) | $ | 1 |
| | $ | (1 | ) | $ | (6 | ) | $ | 5 |
|
The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. |
| | | | | | | |
| | Derivatives (net) |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| Balance at beginning of period | $ | 5 |
| | $ | 3 |
|
| Purchases, sales, issuances and settlements: | | | |
| Purchases | 3 |
| | 5 |
|
| Settlements | (4 | ) | | (5 | ) |
| Total gains included on the Consolidated Balance Sheet | (3 | ) | | 2 |
|
| Balance at end of period | $ | 1 |
| | $ | 5 |
|
DUKE ENERGY INDIANA
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| �� | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
| | Total Fair Value |
| Level 1 |
| Level 2 |
| Level 3 |
|
| Other AFS equity securities | $ | 97 |
| $ | 97 |
| $ | — |
| $ | — |
| | $ | 79 |
| $ | 79 |
| $ | — |
| $ | — |
|
| Other AFS debt securities | 31 |
| — |
| 31 |
| — |
| | 31 |
| — |
| 31 |
| — |
|
| Derivative assets | 27 |
| — |
| — |
| 27 |
| | 16 |
| — |
| — |
| 16 |
|
| Total assets | 155 |
| 97 |
| 31 |
| 27 |
| | 126 |
| 79 |
| 31 |
| 16 |
|
| Derivative liabilities | — |
| — |
| — |
| — |
| | (2 | ) | (2 | ) | — |
| — |
|
| Net assets | $ | 155 |
| $ | 97 |
| $ | 31 |
| $ | 27 |
| | $ | 124 |
| $ | 77 |
| $ | 31 |
| $ | 16 |
|
The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. |
| | | | | | | |
| | Derivatives (net) |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
|
| Balance at beginning of period | $ | 16 |
| | $ | 7 |
|
| Purchases, sales, issuances and settlements: | | | |
| Purchases | 52 |
| | 29 |
|
| Settlements | (43 | ) | | (24 | ) |
| Total gains included on the Consolidated Balance Sheet | 2 |
| | 4 |
|
| Balance at end of period | $ | 27 |
| | $ | 16 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
PIEDMONT
The following table provides recorded balances for assets and liabilities measured at fair value on a recurring basis on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Total Fair Value |
| Level 1 |
| Level 3 |
| | Total Fair Value |
| Level 1 |
| Level 3 |
|
| Other trading equity securities | $ | — |
| $ | — |
| $ | — |
| | $ | 4 |
| $ | 4 |
| $ | — |
|
| Other trading debt securities | 1 |
| 1 |
| — |
| | 1 |
| 1 |
| — |
|
| Derivative assets | 2 |
| 2 |
| — |
| | 3 |
| 3 |
| — |
|
| Total assets | 3 |
| 3 |
| — |
| | 8 |
| 8 |
| — |
|
| Derivative liabilities | (142 | ) | — |
| (142 | ) | | (187 | ) | — |
| (187 | ) |
| Net assets | $ | (139 | ) | $ | 3 |
| $ | (142 | ) | | $ | (179 | ) | $ | 8 |
| $ | (187 | ) |
The following table provides a reconciliation of beginning and ending balances of assets and liabilities measured at fair value using Level 3 measurements. |
| | | | | | | | | | | |
| | Derivatives (net) |
| | Year Ended | | Two Months Ended | | Year Ended |
| (in millions) | December 31, 2017 |
| | December 31, 2016 |
| | October 31, 2016 |
|
| Balance at beginning of period | $ | (187 | ) | | $ | (188 | ) | | $ | — |
|
| Total gains (losses) and settlements | 45 |
| | 1 |
| | (188 | ) |
| Balance at end of period | $ | (142 | ) | | $ | (187 | ) | | $ | (188 | ) |
QUANTITATIVE INFORMATION ABOUT UNOBSERVABLE INPUTS
The following tables include quantitative information about the Duke Energy Registrants' derivatives classified as Level 3. |
| | | | | | | | | | | | |
| | December 31, 2017 |
| | Fair Value | | | | | |
| Investment Type | (in millions) | Valuation Technique | Unobservable Input | Range |
| Duke Energy Ohio | | | | | | |
| FTRs | $ | 1 |
| RTO auction pricing | FTR price – per MWh | $ | 0.07 |
| – | $ | 1.41 |
|
| Duke Energy Indiana | | | | | | |
| FTRs | 27 |
| RTO auction pricing | FTR price – per MWh | (0.77 | ) | – | 7.44 |
|
| Piedmont | | | | | | |
| Natural gas contracts | (142 | ) | Discounted cash flow | Forward natural gas curves - price per MMBtu | 2.10 |
| – | 2.88 |
|
| Duke Energy | | | | | | |
| Total Level 3 derivatives | $ | (114 | ) | | | | | |
|
| | | | | | | | | | |
| | December 31, 2016 |
| | Fair Value | | | | | |
| Investment Type | (in millions) | Valuation Technique | Unobservable Input | Range |
| Duke Energy Ohio | | | | | | |
| FTRs | $ | 5 |
| RTO auction pricing | FTR price – per MWh | 0.77 |
| – | 3.52 |
|
| Duke Energy Indiana | | | | | | |
| FTRs | 16 |
| RTO auction pricing | FTR price – per MWh | (0.83 | ) | – | 9.32 |
|
| Piedmont | | | | | | |
| Natural gas contracts | (187 | ) | Discounted cash flow | Forward natural gas curves - price per MMBtu | 2.31 |
| – | 4.18 |
|
| Duke Energy | | | | | | |
| Total Level 3 derivatives | $ | (166 | ) | | | | | |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
OTHER FAIR VALUE DISCLOSURES
The fair value and book value of long-term debt, including current maturities, is summarized in the following table. Estimates determined are not necessarily indicative of amounts that could have been settled in current markets. Fair value of long-term debt uses Level 2 measurements. |
| | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| (in millions) | Book Value |
| | Fair Value |
| | Book Value |
| | Fair Value |
|
| Duke Energy | $ | 52,279 |
| | $ | 55,331 |
| | $ | 47,895 |
| | $ | 49,161 |
|
| Duke Energy Carolinas | 10,103 |
| | 11,372 |
| | 9,603 |
| | 10,494 |
|
| Progress Energy | 17,837 |
| | 20,000 |
| | 17,541 |
| | 19,107 |
|
| Duke Energy Progress | 7,357 |
| | 7,992 |
| | 7,011 |
| | 7,357 |
|
| Duke Energy Florida | 7,095 |
| | 7,953 |
| | 6,125 |
| | 6,728 |
|
| Duke Energy Ohio | 2,067 |
| | 2,249 |
| | 1,884 |
| | 2,020 |
|
| Duke Energy Indiana | 3,783 |
| | 4,464 |
| | 3,786 |
| | 4,260 |
|
| Piedmont | 2,037 |
| | 2,209 |
| | 1,821 |
| | 1,933 |
|
At both December 31, 2017, and December 31, 2016, fair value of cash and cash equivalents, accounts and notes receivable, accounts payable, notes payable and commercial paper and nonrecourse notes payable of VIEs are not materially different from their carrying amounts because of the short-term nature of these instruments and/or because the stated rates approximate market rates.
17. VARIABLE INTEREST ENTITIES
A VIE is an entity that is evaluated for consolidation using more than a simple analysis of voting control. The analysis to determine whether an entity is a VIE considers contracts with an entity, credit support for an entity, the adequacy of the equity investment of an entity and the relationship of voting power to the amount of equity invested in an entity. This analysis is performed either upon the creation of a legal entity or upon the occurrence of an event requiring reevaluation, such as a significant change in an entity’s assets or activities. A qualitative analysis of control determines the party that consolidates a VIE. This assessment is based on (i) what party has the power to direct the activities of the VIE that most significantly impact its economic performance and (ii) what party has rights to receive benefits or is obligated to absorb losses that could potentially be significant to the VIE. The analysis of the party that consolidates a VIE is a continual reassessment.
CONSOLIDATED VIEs
The obligations of these VIEs discussed in the following paragraphs are nonrecourse to the Duke Energy Registrants. The registrants have no requirement to provide liquidity to, purchase assets of or guarantee performance of these VIEs unless noted in the following paragraphs.
No financial support was provided to any of the consolidated VIEs during the years ended December 31, 2017, 2016 and 2015, or is expected to be provided in the future, that was not previously contractually required.
Receivables Financing – DERF/DEPR/DEFR
Duke Energy Receivables Finance Company, LLC (DERF), Duke Energy Progress Receivables, LLC (DEPR) and Duke Energy Florida Receivables, LLC (DEFR) are bankruptcy remote, special purpose subsidiaries of Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, respectively. DERF, DEPR and DEFR are wholly owned limited liability companies with separate legal existence from their parent companies and their assets are not generally available to creditors of their parent companies. On a revolving basis, DERF, DEPR and DEFR buy certain accounts receivable arising from the sale of electricity and related services from their parent companies.
DERF, DEPR and DEFR borrow amounts under credit facilities to buy these receivables. Borrowing availability from the credit facilities is limited to the amount of qualified receivables purchased. The sole source of funds to satisfy the related debt obligations is cash collections from the receivables. Amounts borrowed under the credit facilities are reflected on the Consolidated Balance Sheets as Long-Term Debt.
The most significant activity that impacts the economic performance of DERF, DEPR and DEFR are the decisions made to manage delinquent receivables. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida consolidate DERF, DEPR and DEFR, respectively, as they make those decisions.
Receivables Financing – CRC
CRC is a bankruptcy remote, special purpose entity indirectly owned by Duke Energy. On a revolving basis, CRC buys certain accounts receivable arising from the sale of electricity, natural gas and related services from Duke Energy Ohio and Duke Energy Indiana. CRC borrows amounts under a credit facility to buy the receivables from Duke Energy Ohio and Duke Energy Indiana. Borrowing availability from the credit facility is limited to the amount of qualified receivables sold to CRC. The sole source of funds to satisfy the related debt obligation is cash collections from the receivables. Amounts borrowed under the credit facility are reflected on Duke Energy's Consolidated Balance Sheets as Long-Term Debt.
The proceeds Duke Energy Ohio and Duke Energy Indiana receive from the sale of receivables to CRC are typically 75 percent cash and 25 percent in the form of a subordinated note from CRC. The subordinated note is a retained interest in the receivables sold. Depending on collection experience, additional equity infusions to CRC may be required by Duke Energy to maintain a minimum equity balance of $3 million.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
CRC is considered a VIE because (i) equity capitalization is insufficient to support its operations, (ii) power to direct the activities that most significantly impact the economic performance of the entity are not performed by the equity holder and (iii) deficiencies in net worth of CRC are funded by Duke Energy. The most significant activities that impact the economic performance of CRC are decisions made to manage delinquent receivables. Duke Energy consolidates CRC as it makes these decisions. Neither Duke Energy Ohio nor Duke Energy Indiana consolidate CRC.
Receivables Financing – Credit Facilities
The following table outlines amounts and expiration dates of the credit facilities described above. |
| | | | | | | | | | | | | | | |
| | Duke Energy |
| | | | Duke Energy |
| | Duke Energy |
| | Duke Energy |
|
| | | | Carolinas |
| | Progress |
| | Florida |
|
| | CRC |
| | DERF |
| | DEPR |
| | DEFR |
|
| Expiration date | December 2020 |
| | December 2020 |
| | February 2019 |
| | April 2019 |
|
| Credit facility amount (in millions) | $ | 325 |
| | $ | 450 |
| | $ | 300 |
| | $ | 225 |
|
| Amounts borrowed at December 31, 2017 | 325 |
| | 450 |
| | 300 |
| | 225 |
|
| Amounts borrowed at December 31, 2016 | 325 |
| | 425 |
| | 300 |
| | 225 |
|
Nuclear Asset-Recovery Bonds – DEFPF
Duke Energy Florida Project Finance, LLC (DEFPF) is a bankruptcy remote, wholly owned special purpose subsidiary of Duke Energy Florida. DEFPF was formed in 2016 for the sole purpose of issuing nuclear asset-recovery bonds to finance Duke Energy Florida's unrecovered regulatory asset related to Crystal River Unit 3.
In June 2016, DEFPF issued $1,294 million of senior secured bonds and used the proceeds to acquire nuclear asset-recovery property from Duke Energy Florida. The nuclear asset-recovery property acquired includes the right to impose, bill, collect and adjust a non-bypassable nuclear asset-recovery charge from all Duke Energy Florida retail customers until the bonds are paid in full and all financing costs have been recovered. The nuclear asset-recovery bonds are secured by the nuclear asset-recovery property and cash collections from the nuclear asset-recovery charges are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to Duke Energy Florida. For additional information see Notes 4 and 6.
DEFPF is considered a VIE primarily because the equity capitalization is insufficient to support its operations. Duke Energy Florida has the power to direct the significant activities of the VIE as described above and therefore Duke Energy Florida is considered the primary beneficiary and consolidates DEFPF.
The following table summarizes the impact of DEFPF on Duke Energy Florida's Consolidated Balance Sheets. |
| | | | | | |
| (in millions) | December 31, 2017 |
| December 31, 2016 |
|
| Receivables of VIEs | $ | 4 |
| $ | 6 |
|
| Regulatory Assets: Current | 51 |
| 50 |
|
| Current Assets: Other | 40 |
| 53 |
|
| Other Noncurrent Assets: Regulatory assets | 1,091 |
| 1,142 |
|
| Current Liabilities: Other | 10 |
| 17 |
|
| Current maturities of long-term debt | 53 |
| 62 |
|
| Long-Term Debt | 1,164 |
| 1,217 |
|
Commercial Renewables
Certain of Duke Energy’s renewable energy facilities are VIEs due to Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Assets are restricted and cannot be pledged as collateral or sold to third parties without prior approval of debt holders. The activities that most significantly impact the economic performance of these renewable energy facilities were decisions associated with siting, negotiating PPAs, engineering, procurement and construction and decisions associated with ongoing operations and maintenance-related activities. Duke Energy consolidates the entities as it is responsible for all of these decisions.
The table below presents material balances reported on Duke Energy's Consolidated Balance Sheets related to renewables VIEs. |
| | | | | | |
| (in millions) | December 31, 2017 |
| December 31, 2016 |
|
| Current Assets: Other | $ | 174 |
| $ | 223 |
|
| Property, plant and equipment, cost | 3,923 |
| 3,419 |
|
| Accumulated depreciation and amortization | (591 | ) | (453 | ) |
| Current maturities of long-term debt | 170 |
| 198 |
|
| Long-Term Debt | 1,700 |
| 1,097 |
|
| Other Noncurrent Liabilities: Deferred income taxes | (148 | ) | 275 |
|
| Other Noncurrent Liabilities: Other | 241 |
| 252 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
NON-CONSOLIDATED VIEs
The following tables summarize the impact of non-consolidated VIEs on the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Duke Energy | | Duke |
| | Duke |
|
| | Pipeline |
| | Commercial |
| | Other |
| | | | Energy |
| | Energy |
|
| (in millions) | Investments |
| | Renewables |
| | VIEs(a) |
| | Total |
| | Ohio |
| | Indiana |
|
| Receivables from affiliated companies | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 87 |
| | $ | 106 |
|
| Investments in equity method unconsolidated affiliates | 697 |
| | 180 |
| | 42 |
| | 919 |
| | — |
| | — |
|
| Other noncurrent assets | 17 |
| | — |
| | — |
| | 17 |
| | — |
| | — |
|
| Total assets | $ | 714 |
| | $ | 180 |
| | $ | 42 |
| | $ | 936 |
| | $ | 87 |
| | $ | 106 |
|
| Taxes accrued | (29 | ) | | — |
| | — |
| | (29 | ) | | — |
| | — |
|
| Other current liabilities | — |
| | — |
| | 4 |
| | 4 |
| | — |
| | — |
|
| Deferred income taxes | 42 |
| | — |
| | — |
| | 42 |
| | — |
| | — |
|
| Other noncurrent liabilities | — |
| | — |
| | 12 |
| | 12 |
| | — |
| | — |
|
| Total liabilities | $ | 13 |
| | $ | — |
| | $ | 16 |
| | $ | 29 |
| | $ | — |
| | $ | — |
|
| Net assets | $ | 701 |
| | $ | 180 |
| | $ | 26 |
| | $ | 907 |
| | $ | 87 |
| | $ | 106 |
|
| |
| (a) | Duke Energy holds a 50 percent equity interest in Duke-American Transmission Company, LLC (DATC). As of December 31, 2016, DATC was considered a VIE due to having insufficient equity to finance its own activities without subordinated financial support. However, DATC is no longer considered a VIE based on sufficient equity to finance its own activities, and, therefore, is no longer considered a VIE as of December 31, 2017. Duke Energy's investment in DATC was $46 million at December 31, 2017. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 | | |
| | Duke Energy | | Duke |
| | Duke |
| | |
| | Pipeline |
| | Commercial |
| | | | | | Energy |
| | Energy |
| | |
| (in millions) | Investments |
| | Renewables |
| | Other |
| | Total |
| | Ohio |
| | Indiana |
| | Piedmont (a) |
|
| Receivables from affiliated companies | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 82 |
| | $ | 101 |
| | $ | — |
|
| Investments in equity method unconsolidated affiliates | 487 |
| | 174 |
| | 90 |
| | 751 |
| | — |
| | — |
| | 139 |
|
| Other noncurrent assets | 12 |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | — |
|
| Total assets | $ | 499 |
| | $ | 174 |
| | $ | 90 |
| | $ | 763 |
| | $ | 82 |
| | $ | 101 |
| | $ | 139 |
|
| Other current liabilities | — |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
| | — |
|
| Other noncurrent liabilities | — |
| | — |
| | 13 |
| | 13 |
| | — |
| | — |
| | 4 |
|
| Total liabilities | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Net assets | $ | 499 |
| | $ | 174 |
| | $ | 74 |
| | $ | 747 |
| | $ | 82 |
| | $ | 101 |
| | $ | 135 |
|
| |
| (a) | In April 2017, Piedmont transferred its non-consolidated VIE investments to a wholly owned subsidiary of Duke Energy. See Note 12 and the "Pipeline Investments" section below for additional detail. |
The Duke Energy Registrants are not aware of any situations where the maximum exposure to loss significantly exceeds the carrying values shown above except for the power purchase agreement with OVEC, which is discussed below, and various guarantees, some of which are reflected in the table above as Other noncurrent liabilities. For more information on various guarantees, refer to Note 7.
Pipeline Investments
Duke Energy has investments in various joint ventures with pipeline projects currently under construction. These entities are considered VIEs due to having insufficient equity to finance their own activities without subordinated financial support. Duke Energy does not have the power to direct the activities that most significantly impact the economic performance, the obligation to absorb losses or the right to receive benefits of these VIEs and therefore does not consolidate these entities.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The table below presents Duke Energy's ownership interest and investment balance in in these joint ventures. |
| | | | | | | | | | |
| | | | Investment Amount (in millions) |
| | Ownership | | December 31, | | December 31, |
| Entity Name | Interest | | 2017 | | 2016 |
| ACP | 47 | % | | $ | 397 |
| | $ | 265 |
|
| Sabal Trail | 7.5 | % | | 219 |
| | 140 |
|
| Constitution | 24 | % | | 81 |
| | 82 |
|
| Total | | | $ | 697 |
| | $ | 487 |
|
Commercial Renewables
Duke Energy has investments in various renewable energy project entities. Some of these entities are VIEs due to Duke Energy issuing guarantees for debt service and operations and maintenance reserves in support of debt financings. Duke Energy does not consolidate these VIEs because power to direct and control key activities is shared jointly by Duke Energy and other owners.
Other VIEs
Duke Energy holds a 50 percent equity interest in Pioneer. Pioneer is considered a VIE due to having insufficient equity to finance their own activities without subordinated financial support. The activities that most significantly impact Pioneer's economic performance are decisions related to the development of new transmission facilities. The power to direct these activities is jointly and equally shared by Duke Energy and the other joint venture partner, American Electric Power, therefore Duke Energy does not consolidate Pioneer.
OVEC
Duke Energy Ohio’s 9 percent ownership interest in OVEC is considered a non-consolidated VIE due to having insufficient equity to finance their activities without subordinated financial support. As a counterparty to an inter-company power agreement (ICPA), Duke Energy Ohio has a contractual arrangement to buy power from OVEC’s power plants through June 2040 commensurate with its power participation ratio, which is equivalent to Duke Energy Ohio's ownership interest. Costs, including fuel, operating expenses, fixed costs, debt amortization, and interest expense are allocated to counterparties to the ICPA based on their power participation ratio. The value of the ICPA is subject to variability due to fluctuation in power prices and changes in OVEC's cost of business, including costs associated with its 2,256 MW of coal-fired generation capacity. Deterioration in the credit quality, or bankruptcy of one or more parties to the ICPA could increase the costs of OVEC. In addition, certain proposed environmental rulemaking could result in future increased cost allocations.
CRC
See discussion under Consolidated VIEs for additional information related to CRC.
Amounts included in Receivables from affiliated companies in the above table for Duke Energy Ohio and Duke Energy Indiana reflect their retained interest in receivables sold to CRC. These subordinated notes held by Duke Energy Ohio and Duke Energy Indiana are stated at fair value. Carrying values of retained interests are determined by allocating carrying value of the receivables between assets sold and interests retained based on relative fair value. The allocated bases of the subordinated notes are not materially different than their face value because (i) the receivables generally turnover in less than two months, (ii) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration and (iii) the equity in CRC is subordinate to all retained interests and thus would absorb losses first. The hypothetical effect on fair value of the retained interests assuming both a 10 percent and a 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio and Duke Energy Indiana on the retained interests using the acceptable yield method. This method generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. An impairment charge is recorded against the carrying value of both retained interests and purchased beneficial interest whenever it is determined that an OTTI has occurred.
Key assumptions used in estimating fair value are detailed in the following table. |
| | | | | | | | | | | |
| | Duke Energy Ohio | | Duke Energy Indiana |
| | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| Anticipated credit loss ratio | 0.5 | % | | 0.5 | % | | 0.3 | % | | 0.3 | % |
| Discount rate | 2.1 | % | | 1.5 | % | | 2.1 | % | | 1.5 | % |
| Receivable turnover rate | 13.5 | % | | 13.3 | % | | 10.7 | % | | 10.6 | % |
The following table shows the gross and net receivables sold. |
| | | | | | | | | | | | | | | |
| | Duke Energy Ohio | | Duke Energy Indiana |
| (in millions) | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| Receivables sold | $ | 273 |
| | $ | 267 |
| | $ | 312 |
| | $ | 306 |
|
| Less: Retained interests | 87 |
| | 82 |
| | 106 |
| | 101 |
|
| Net receivables sold | $ | 186 |
| | $ | 185 |
| | $ | 206 |
| | $ | 205 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table shows sales and cash flows related to receivables sold. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Duke Energy Ohio | | Duke Energy Indiana |
| | Years Ended December 31, | | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
| | 2017 |
| | 2016 |
| | 2015 |
|
| Sales | | | | | | | | | | | |
| Receivables sold | $ | 1,879 |
| | $ | 1,926 |
| | $ | 1,963 |
| | $ | 2,711 |
| | $ | 2,635 |
| | $ | 2,627 |
|
| Loss recognized on sale | 10 |
| | 9 |
| | 9 |
| | 12 |
| | 11 |
| | 11 |
|
| Cash Flows | | | | | | | | | | | |
| Cash proceeds from receivables sold | 1,865 |
| | 1,882 |
| | 1,995 |
| | 2,694 |
| | 2,583 |
| | 2,670 |
|
| Collection fees received | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Return received on retained interests | 3 |
| | 2 |
| | 3 |
| | 7 |
| | 5 |
| | 5 |
|
Cash flows from the sales of receivables are reflected within Cash Flows From Operating Activities on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Cash Flows.
Collection fees received in connection with servicing transferred accounts receivable are included in Operation, maintenance and other on Duke Energy Ohio’s and Duke Energy Indiana’s Consolidated Statements of Operations and Comprehensive Income. The loss recognized on sales of receivables is calculated monthly by multiplying receivables sold during the month by the required discount. The required discount is derived monthly utilizing a three-year weighted average formula that considers charge-off history, late charge history and turnover history on the sold receivables, as well as a component for the time value of money. The discount rate, or component for the time value of money, is the prior month-end LIBOR plus a fixed rate of 1.00 percent.
18. COMMON STOCK
Basic Earnings Per Share (EPS) is computed by dividing net income attributable to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities, by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to Duke Energy common stockholders, as adjusted for distributed and undistributed earnings allocated to participating securities, by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common shares, such as stock options and equity forward sale agreements, were exercised or settled. Duke Energy’s participating securities are restricted stock units that are entitled to dividends declared on Duke Energy common stock during the restricted stock unit’s vesting periods.
The following table presents Duke Energy’s basic and diluted EPS calculations and reconciles the weighted average number of common stock outstanding to the diluted weighted average number of common stock outstanding. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions, except per share amounts) | 2017 |
| | 2016 |
| | 2015 |
|
| Income from continuing operations attributable to Duke Energy common stockholders excluding impact of participating securities | $ | 3,059 |
| | $ | 2,567 |
| | $ | 2,640 |
|
| Weighted average shares outstanding – basic | 700 |
| | 691 |
| | 694 |
|
| Weighted average shares outstanding – diluted | 700 |
| | 691 |
| | 694 |
|
| Earnings per share from continuing operations attributable to Duke Energy common stockholders | | | | | |
| Basic | $ | 4.37 |
| | $ | 3.71 |
| | $ | 3.80 |
|
| Diluted | $ | 4.37 |
| | $ | 3.71 |
| | $ | 3.80 |
|
Potentially dilutive items excluded from the calculation(a) | 2 |
| | 2 |
| | 2 |
|
| Dividends declared per common share | $ | 3.49 |
| | $ | 3.36 |
| | $ | 3.24 |
|
| |
| (a) | Performance stock awards were not included in the dilutive securities calculation because the performance measures related to the awards had not been met. |
Equity Distribution Agreement
On February 20, 2018, Duke Energy filed a prospectus supplement and executed an Equity Distribution Agreement (the EDA) under which it may sell up to $1 billion of its common stock through an at-the-market offering program, including an equity forward sales component. The EDA was entered into with Wells Fargo Securities, LLC, Citigroup Global Markets Inc., and J.P. Morgan Securities LLC (the Agents). Under the terms of the EDA, Duke Energy may issue and sell, through either of the Agents, shares of common stock during the period ending September 23, 2019.
In addition to the issuance and sales of shares by Duke Energy through the Agents, Duke Energy may enter into Equity Forward Agreements with affiliates of the Agents as Forward Purchasers. There were no transactions under the EDA from the time of execution of the EDA to the filing of this document.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Stock Issuance
In March 2016, Duke Energy marketed an equity offering of 10.6 million shares of common stock. In lieu of issuing equity at the time of the offering, Duke Energy entered into Equity Forwards with Barclays. The Equity Forwards required Duke Energy to either physically settle the transactions by issuing 10.6 million shares, or net settle in whole or in part through the delivery or receipt of cash or shares.
On October 5, 2016, following the close of the Piedmont acquisition, Duke Energy physically settled the Equity Forwards in full by delivering 10.6 million shares of common stock in exchange for net cash proceeds of approximately $723 million. The net proceeds were used to finance a portion of the Piedmont acquisition. As a result of the acquisition, all of Piedmont's issued and outstanding stock became the issued and outstanding shares of a wholly owned subsidiary of Duke Energy. See Note 2 for additional information related to the Piedmont acquisition.
Accelerated Stock Repurchase Program
On April 6, 2015, Duke Energy entered into agreements with each of Goldman, Sachs & Co. and JPMorgan Chase Bank, National Association (the Dealers) to repurchase a total of $1.5 billion of Duke Energy common stock under an accelerated stock repurchase program (the ASR). Duke Energy made payments of $750 million to each of the Dealers and was delivered 16.6 million shares, with a total fair value of $1.275 billion, which represented approximately 85 percent of the total number of shares of Duke Energy common stock expected to be repurchased under the ASR. The company recorded the $1.5 billion payment as a reduction to common stock as of April 6, 2015. In June 2015, the Dealers delivered 3.2 million additional shares to Duke Energy to complete the ASR. Approximately 19.8 million shares, in total, were delivered to Duke Energy and retired under the ASR at an average price of $75.75 per share. The final number of shares repurchased was based upon the average of the daily volume weighted average stock prices of Duke Energy’s common stock during the term of the program, less a discount.
19. SEVERANCE
As part of its strategic planning processes, Duke Energy implemented targeted cost savings initiatives during 2016 and 2015 aimed at reducing operations and maintenance expense. The initiatives included efforts to reduce costs through the standardization of processes and systems, leveraging technology and workforce optimization throughout the company.
During 2016, Duke Energy and Piedmont announced severance plans covering certain eligible employees whose employment will be involuntarily terminated without cause as a result of Duke Energy's acquisition of Piedmont. These reductions continue to be implemented and are a part of the synergies expected to be realized with the acquisition. Refer to Note 2 for additional information on the Piedmont acquisition.
Severance benefit costs for initiatives and plans discussed above were accrued for a total of approximately 100 employees in 2017, 600 employees in 2016 and 900 employees in 2015. The following table presents the direct and allocated severance and related expenses recorded by the Duke Energy Registrants. Amounts are included within Operation, maintenance and other on the Consolidated Statements of Operations. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont(a) |
|
| Year Ended December 31, 2017 | $ | 15 |
| $ | 2 |
| $ | 2 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | 1 |
| $ | 9 |
|
| Year Ended December 31, 2016 | 118 |
| 39 |
| 40 |
| 23 |
| 17 |
| 3 |
| 7 |
| |
| Year Ended December 31, 2015 | 142 |
| 93 |
| 36 |
| 28 |
| 8 |
| 2 |
| 6 |
| |
| |
| (a) | Piedmont severance benefit costs were $3 million for the two months ended December 31, 2016, and $19 million for the year ended October 31, 2016. Piedmont did not record any severance benefit costs for the year ended October 31, 2015. |
The table below presents the severance liability for past and ongoing severance plans including the plans described above. Amounts for Duke Energy Indiana and Duke Energy Ohio are not material. |
| | | | | | | | | | | | | | | | | | |
| | | Duke |
| | Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Piedmont |
|
| Balance at December 31, 2016 | $ | 79 |
| $ | 13 |
| $ | 14 |
| $ | 6 |
| $ | 8 |
| $ | 20 |
|
| Provision/Adjustments | 17 |
| 2 |
| — |
| — |
| — |
| 9 |
|
| Cash Reductions | (77 | ) | (10 | ) | (12 | ) | (5 | ) | (8 | ) | (24 | ) |
| Balance at December 31, 2017 | $ | 19 |
| $ | 5 |
| $ | 2 |
| $ | 1 |
| $ | — |
| $ | 5 |
|
20. STOCK-BASED COMPENSATION
The Duke Energy Corporation 2015 Long-Term Incentive Plan (the 2015 Plan) provides for the grant of stock-based compensation awards to employees and outside directors. The 2015 Plan reserves 10 million shares of common stock for issuance. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. However, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards that are exercised or vest in the future. Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table summarizes the total expense recognized by the Duke Energy Registrants, net of tax, for stock-based compensation. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Duke Energy | $ | 43 |
| | $ | 35 |
| | $ | 38 |
|
| Duke Energy Carolinas | 15 |
| | 12 |
| | 14 |
|
| Progress Energy | 16 |
| | 12 |
| | 14 |
|
| Duke Energy Progress | 10 |
| | 7 |
| | 9 |
|
| Duke Energy Florida | 6 |
| | 5 |
| | 5 |
|
| Duke Energy Ohio | 3 |
| | 2 |
| | 2 |
|
| Duke Energy Indiana | 4 |
| | 3 |
| | 4 |
|
Piedmont(a) | 3 |
| | | | |
(a) See discussion below for information on Piedmont's pre-merger stock-based compensation plans.
Duke Energy's pretax stock-based compensation costs, the tax benefit associated with stock-based compensation expense and stock-based compensation costs capitalized are included in the following table. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 |
| | 2016 |
| | 2015 |
|
| Restricted stock unit awards | $ | 41 |
| | $ | 36 |
| | $ | 38 |
|
| Performance awards | 27 |
| | 19 |
| | 23 |
|
| Pretax stock-based compensation cost | $ | 68 |
| | $ | 55 |
| | $ | 61 |
|
| Tax benefit associated with stock-based compensation expense | $ | 25 |
| | $ | 20 |
| | $ | 23 |
|
| Stock-based compensation costs capitalized | 4 |
| | 2 |
| | 3 |
|
RESTRICTED STOCK UNIT AWARDS
Restricted stock unit (RSU) awards generally vest over periods from immediate to three years. Fair value amounts are based on the market price of Duke Energy's common stock on the grant date. The following table includes information related to restricted stock unit awards. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 |
| | 2016 |
| | 2015 |
|
| Shares awarded (in thousands) | 583 |
| | 684 |
| | 524 |
|
| Fair value (in millions) | $ | 47 |
| | $ | 52 |
| | $ | 41 |
|
The following table summarizes information about restricted stock unit awards outstanding. |
| | | | | | |
| | | | Weighted Average |
|
| | Shares |
| | Grant Date Fair Value |
|
| | (in thousands) |
| | (per share) |
|
| Outstanding at December 31, 2016 | 1,139 |
| | $ | 76 |
|
| Granted | 583 |
| | 80 |
|
| Vested | (553 | ) | | 76 |
|
| Forfeited | (48 | ) | | 78 |
|
| Outstanding at December 31, 2017 | 1,121 |
| | 78 |
|
| Restricted stock unit awards expected to vest | 1,094 |
| | 78 |
|
The total grant date fair value of shares vested during the years ended December 31, 2017, 2016 and 2015 was $42 million, $38 million and $41 million, respectively. At December 31, 2017, Duke Energy had $29 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of twenty-three months.
PERFORMANCE AWARDS
Stock-based performance awards generally vest after three years if performance targets are met.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Performance awards granted in 2017, 2016 and 2015 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock relative to a predefined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards. The model uses three-year historical volatilities and correlations for all companies in the predefined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant are incorporated within the model. For performance awards granted in 2017, the model used a risk-free interest rate of 1.5 percent, which reflects the yield on three-year Treasury bonds as of the grant date, and an expected volatility of 17.2 percent based on Duke Energy's historical volatility over three years using daily stock prices.
In addition to TSR, performance awards granted in 2017 and 2016 contain a performance condition based on Duke Energy's cumulative adjusted EPS. Performance awards granted in 2017 also contain a performance condition based on the total incident case rate, one of our key employee safety metrics. The actual number of shares issued will range from zero to 200 percent of target shares depending on the level of performance achieved.
The following table includes information related to stock-based performance awards. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 |
| | 2016 |
| | 2015 |
|
| Shares granted assuming target performance (in thousands) | 461 |
| | 338 |
| | 321 |
|
| Fair value (in millions) | $ | 37 |
| | $ | 25 |
| | $ | 26 |
|
The following table summarizes information about stock-based performance awards outstanding and assumes payout at the target level. |
| | | | | | |
| | | | Weighted Average |
|
| | Shares |
| | Grant Date Fair Value |
|
| | (in thousands) |
| | (per share) |
|
| Outstanding at December 31, 2016 | 862 |
| | $ | 75 |
|
| Granted | 461 |
| | 81 |
|
| Forfeited | (258 | ) | | 69 |
|
| Outstanding at December 31, 2017 | 1,065 |
| | 79 |
|
| Stock-based performance awards expected to vest | 1,034 |
| | 79 |
|
No performance awards vested during the year ended December 31, 2017. The total grant date fair value of shares vested during the years ended December 31, 2016 and 2015 was $25 million and $26 million, respectively. At December 31, 2017, Duke Energy had $34 million of unrecognized compensation cost, which is expected to be recognized over a weighted average period of twenty-three months.
STOCK OPTIONS
Stock options, when granted, have a maximum option term of 10 years and with an exercise price not less than the market price of Duke Energy's common stock on the grant date. There were no stock options granted or exercised during the year ended December 31, 2017. There were no stock options outstanding at December 31, 2017.
The following table summarizes additional information related to stock options exercised and granted. |
| | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2016 |
| | 2015 |
|
| Intrinsic value of options exercised | $ | 1 |
| | $ | 5 |
|
| Tax benefit related to options exercised | — |
| | 2 |
|
| Cash received from options exercised | 7 |
| | 17 |
|
PIEDMONT
Prior to Duke Energy's acquisition of Piedmont, Piedmont had an incentive compensation plan that had a series of three-year performance and RSU awards for eligible officers and other participants. The Agreement and Plan of Merger (Merger Agreement) between Duke Energy and Piedmont provided for the conversion of the 2014-2016 and 2015-2017 performance awards and the nonvested 2016 RSU award into the right to receive $60 cash per share upon the close of the transaction. In December 2015, Piedmont's board of directors authorized the accelerated vesting, payment and taxation of the 2014-2016 and 2015-2017 performance awards, as well as the 2016 RSU award, at the election of the participant. Substantially all participants elected to accelerate the settlement of these awards. As a result of the settlement of these awards, 194 thousand shares of Piedmont shares were issued to participants, net of shares withheld for applicable federal and state income taxes, at a closing price of $56.85 and a fair value of $11 million. The 2016-2018 performance award cycle was approved subsequent to the Merger Agreement and was converted into a Duke Energy RSU award as discussed above at the consummation of the acquisition.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Piedmont's stock-based compensation costs and the tax benefit associated with stock-based compensation expense are included in the following table. Piedmont's stock-based compensation costs were not material for the two months ended December 31, 2016. |
| | | | | | | |
| | Years Ended October 31, |
| (in millions) | 2016 |
| | 2015 |
|
| Pretax stock-based compensation cost | $ | 16 |
| | $ | 14 |
|
| Tax benefit associated with stock-based compensation expense | 6 |
| | 4 |
|
| Net of tax stock-based compensation cost | $ | 10 |
| | $ | 10 |
|
21. EMPLOYEE BENEFIT PLANS
DEFINED BENEFIT RETIREMENT PLANS
Duke Energy and certain subsidiaries maintain, and the Subsidiary Registrants participate in, qualified, non-contributory defined benefit retirement plans. The Duke Energy plans cover most employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits based upon a percentage of current eligible earnings, age or age and years of service and interest credits. Certain employees are eligible for benefits that use a final average earnings formula. Under these final average earnings formulas, a plan participant accumulates a retirement benefit equal to the sum of percentages of their (i) highest three-year, four-year, or five-year average earnings, (ii) highest three-year, four-year, or five-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), (iii) highest three-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains, and the Subsidiary Registrants participate in, non-qualified, non-contributory defined benefit retirement plans that cover certain executives. The qualified and non-qualified, non-contributory defined benefit plans are closed to new participants.
Duke Energy approved plan amendments to restructure its qualified non-contributory defined benefit retirement plans, effective January 1, 2018. The restructuring involved (i) the spin-off of the majority of inactive participants from two plans into a separate inactive plan and (ii) the merger of the active participant portions of such plans, along with a pension plan acquired as part of the Piedmont transaction, into a single active plan. Benefits offered to the plan participants remain unchanged except that the Piedmont plan's final average earnings formula was frozen as of December 31, 2017, and affected participants were moved into the active plan's cash balance formula. Actuarial gains and losses associated with the Inactive Plan will be amortized over the remaining life expectancy of the inactive participants. The longer amortization period is expected to lower Duke Energy's 2018 pretax qualified pension plan expense by approximately $33 million.
Duke Energy uses a December 31 measurement date for its defined benefit retirement plan assets and obligations.
Net periodic benefit costs disclosed in the tables below represent the cost of the respective benefit plan for the periods presented. However, portions of the net periodic benefit costs disclosed in the tables below have been capitalized as a component of property, plant and equipment. Amounts presented in the tables below for the Subsidiary Registrants represent the amounts of pension and other post-retirement benefit cost allocated by Duke Energy for employees of the Subsidiary Registrants. Additionally, the Subsidiary Registrants are allocated their proportionate share of pension and post-retirement benefit cost for employees of Duke Energy’s shared services affiliate that provide support to the Subsidiary Registrants. These allocated amounts are included in the governance and shared service costs discussed in Note 13.
Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefit payments to be paid to plan participants. The following table includes information related to the Duke Energy Registrants’ contributions to its qualified defined benefit pension plans. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont(a) |
|
Anticipated Contributions: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Total anticipated 2018 contributions | $ | 148 |
| | $ | 46 |
| | $ | 45 |
| | $ | 25 |
| | $ | 20 |
| | $ | — |
| | $ | 8 |
| | $ | 7 |
|
| Contributions made January 2, 2018 | 141 |
| | 46 |
| | 45 |
| | 25 |
| | 20 |
| | — |
| | 8 |
| | — |
|
| Contributions to be made in 2018 | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
Contributions Made: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| 2017 | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 11 |
|
| 2016 | 155 |
| | 43 |
| | 43 |
| | 24 |
| | 20 |
| | 5 |
| | 9 |
| |
|
|
| 2015 | 302 |
| | 91 |
| | 83 |
| | 42 |
| | 40 |
| | 8 |
| | 19 |
| |
|
|
| |
| (a) | Piedmont contributed $10 million to its U.S. qualified defined benefit pension plan during the two months ended December 31, 2016, and for each of the years ended October 31, 2016, and 2015, respectively. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
QUALIFIED PENSION PLANS
Components of Net Periodic Pension Costs |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Service cost | $ | 159 |
| | $ | 48 |
| | $ | 45 |
| | $ | 26 |
| | $ | 19 |
| | $ | 4 |
| | $ | 9 |
| | $ | 10 |
|
| Interest cost on projected benefit obligation | 328 |
| | 79 |
| | 100 |
| | 47 |
| | 53 |
| | 18 |
| | 26 |
| | 14 |
|
| Expected return on plan assets | (545 | ) | | (142 | ) | | (167 | ) | | (82 | ) | | (85 | ) | | (27 | ) | | (42 | ) | | (24 | ) |
| Amortization of actuarial loss | 146 |
| | 31 |
| | 52 |
| | 23 |
| | 29 |
| | 5 |
| | 12 |
| | 11 |
|
| Amortization of prior service credit | (24 | ) | | (8 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
| Settlement charge | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
|
| Other | 8 |
| | 2 |
| | 2 |
| | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
|
Net periodic pension costs(a)(b) | $ | 84 |
|
| $ | 10 |
| | $ | 29 |
| | $ | 13 |
| | $ | 16 |
| | $ | (1 | ) | | $ | 4 |
| | $ | 22 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Service cost | $ | 147 |
| | $ | 48 |
| | $ | 42 |
| | $ | 24 |
| | $ | 19 |
| | $ | 4 |
| | $ | 9 |
|
| Interest cost on projected benefit obligation | 335 |
| | 86 |
| | 106 |
| | 49 |
| | 55 |
| | 19 |
| | 28 |
|
| Expected return on plan assets | (519 | ) | | (142 | ) | | (168 | ) | | (82 | ) | | (84 | ) | | (27 | ) | | (42 | ) |
| Amortization of actuarial loss | 134 |
| | 33 |
| | 51 |
| | 23 |
| | 29 |
| | 4 |
| | 11 |
|
| Amortization of prior service (credit) | (17 | ) | | (8 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | — |
| | (1 | ) |
| Settlement charge | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | 8 |
| | 2 |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
|
Net periodic pension costs(a)(b) | $ | 91 |
| | $ | 19 |
| | $ | 31 |
| | $ | 13 |
| | $ | 19 |
| | $ | 1 |
| | $ | 6 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Service cost | $ | 159 |
| | $ | 50 |
| | $ | 44 |
| | $ | 23 |
| | $ | 20 |
| | $ | 4 |
| | $ | 10 |
|
| Interest cost on projected benefit obligation | 324 |
| | 83 |
| | 104 |
| | 48 |
| | 54 |
| | 18 |
| | 27 |
|
| Expected return on plan assets | (516 | ) | | (139 | ) | | (171 | ) | | (79 | ) | | (87 | ) | | (26 | ) | | (42 | ) |
| Amortization of actuarial loss | 166 |
| | 39 |
| | 65 |
| | 33 |
| | 31 |
| | 7 |
| | 13 |
|
| Amortization of prior service (credit) cost | (15 | ) | | (7 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | — |
| | 1 |
|
| Other | 8 |
| | 2 |
| | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Net periodic pension costs(a)(b) | $ | 126 |
| | $ | 28 |
| | $ | 42 |
| | $ | 24 |
| | $ | 18 |
| | $ | 3 |
| | $ | 10 |
|
| |
| (a) | Duke Energy amounts exclude $7 million, $8 million and $9 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006. |
| |
| (b) | Duke Energy Ohio amounts exclude $3 million, $4 million and $4 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | |
| | Piedmont |
| | Two Months Ended | | Years Ended October 31, |
(in millions) | December 31, 2016 | | 2016 | | 2015 |
| Service cost | $ | 2 |
| | $ | 11 |
| | $ | 11 |
|
| Interest cost on projected benefit obligation | 2 |
| | 9 |
| | 12 |
|
| Expected return on plan assets | (4 | ) | | (24 | ) | | (24 | ) |
| Amortization of actuarial loss | 2 |
| | 8 |
| | 9 |
|
| Amortization of prior service credit | (1 | ) | | (2 | ) | | (2 | ) |
| Settlement charge | 3 |
| | — |
| | — |
|
| Net periodic pension costs | $ | 4 |
| | $ | 2 |
| | $ | 6 |
|
Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Regulatory assets, net (decrease) increase | $ | (212 | ) | | $ | (70 | ) | | $ | (49 | ) | | $ | (37 | ) | | $ | (11 | ) | | $ | 9 |
| | $ | (19 | ) | | $ | (64 | ) |
| Accumulated other comprehensive loss (income) | | | | | | | | | | | | | | | |
| Deferred income tax expense | $ | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Prior year service cost arising during the year | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of prior year actuarial losses | (7 | ) | | — |
| | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amount recognized in accumulated other comprehensive income | $ | (6 | ) | | $ | — |
| | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Regulatory assets, net increase | $ | 214 |
| | $ | 4 |
| | $ | 34 |
| | $ | 18 |
| | $ | 16 |
| | $ | 2 |
| | $ | 9 |
|
| Accumulated other comprehensive (income) loss | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Deferred income tax expense | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Prior year service credit arising during the year | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of prior year actuarial losses | (7 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Net amount recognized in accumulated other comprehensive income | $ | (5 | ) | | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Piedmont's regulatory asset net increase was $34 million, $35 million and $20 million for the two months ended December 31, 2016, and for the years ended October 31, 2016, and 2015, respectively.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Reconciliation of Funded Status to Net Amount Recognized |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Change in Projected Benefit Obligation | |
| | | | | | | | | | | | | | |
| Obligation at prior measurement date | $ | 8,131 |
| | $ | 1,952 |
| | $ | 2,512 |
| | $ | 1,158 |
| | $ | 1,323 |
| | $ | 447 |
| | $ | 658 |
| | $ | 344 |
|
| Service cost | 159 |
| | 48 |
| | 45 |
| | 26 |
| | 19 |
| | 4 |
| | 9 |
| | 10 |
|
| Interest cost | 328 |
| | 79 |
| | 100 |
| | 47 |
| | 53 |
| | 18 |
| | 26 |
| | 14 |
|
| Actuarial loss | 455 |
| | 68 |
| | 158 |
| | 57 |
| | 99 |
| | 35 |
| | 26 |
| | 38 |
|
| Transfers | — |
| | 27 |
| | (32 | ) | | (2 | ) | | (15 | ) | | 12 |
| | — |
| | — |
|
| Plan amendments | (61 | ) | | — |
| | — |
| | — |
| | — |
| |
|
| | — |
| | (61 | ) |
| Benefits paid | (537 | ) | | (145 | ) | | (146 | ) | | (75 | ) | | (69 | ) | | (37 | ) | | (50 | ) | | (5 | ) |
| Benefits paid - settlements | (27 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (27 | ) |
| Obligation at measurement date | $ | 8,448 |
|
| $ | 2,029 |
|
| $ | 2,637 |
|
| $ | 1,211 |
|
| $ | 1,410 |
|
| $ | 479 |
|
| $ | 669 |
| | $ | 313 |
|
| Accumulated Benefit Obligation at measurement date | $ | 8,369 |
| | $ | 2,029 |
| | $ | 2,601 |
| | $ | 1,211 |
| | $ | 1,375 |
| | $ | 468 |
| | $ | 652 |
| | $ | 313 |
|
Change in Fair Value of Plan Assets | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Plan assets at prior measurement date | $ | 8,531 |
| | $ | 2,225 |
| | $ | 2,675 |
| | $ | 1,290 |
| | $ | 1,352 |
| | $ | 428 |
| | $ | 657 |
| | $ | 346 |
|
| Employer contributions | 19 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 11 |
|
| Actual return on plan assets | 1,017 |
| | 265 |
| | 317 |
| | 153 |
| | 161 |
| | 51 |
| | 77 |
| | 43 |
|
| Benefits paid | (537 | ) | | (145 | ) | | (146 | ) | | (75 | ) |
| (69 | ) |
| (37 | ) |
| (50 | ) | | (5 | ) |
Benefits paid - settlements
| (27 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (27 | ) |
| Transfers | — |
| | 27 |
| | (32 | ) | | (2 | ) |
| (15 | ) |
| 12 |
|
| — |
| | — |
|
| Plan assets at measurement date | $ | 9,003 |
| | $ | 2,372 |
| | $ | 2,814 |
| | $ | 1,366 |
| | $ | 1,429 |
| | $ | 458 |
| | $ | 684 |
| | $ | 368 |
|
| Funded status of plan | $ | 555 |
| | $ | 343 |
| | $ | 177 |
| | $ | 155 |
| | $ | 19 |
| | $ | (21 | ) | | $ | 15 |
| | $ | 55 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
Change in Projected Benefit Obligation | | | | | | | | | | | | | |
| Obligation at prior measurement date | $ | 7,727 |
| | $ | 1,995 |
| | $ | 2,451 |
| | $ | 1,143 |
| | $ | 1,276 |
| | $ | 453 |
| | $ | 649 |
|
| Obligation assumed from acquisition | 352 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Service cost | 147 |
| | 48 |
| | 42 |
| | 24 |
| | 19 |
| | 4 |
| | 9 |
|
| Interest cost | 335 |
| | 86 |
| | 106 |
| | 49 |
| | 55 |
| | 19 |
| | 28 |
|
| Actuarial loss | 307 |
| | 46 |
| | 111 |
| | 52 |
| | 57 |
| | 13 |
| | 41 |
|
| Transfers | — |
| | 14 |
| | (3 | ) | | (3 | ) | | — |
| | (3 | ) | | — |
|
| Plan amendments | (52 | ) | | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) | | (15 | ) |
| Benefits paid | (679 | ) | | (234 | ) | | (195 | ) | | (107 | ) | | (84 | ) | | (36 | ) | | (54 | ) |
| Impact of settlements | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Obligation at measurement date | $ | 8,131 |
| | $ | 1,952 |
| | $ | 2,512 |
| | $ | 1,158 |
| | $ | 1,323 |
| | $ | 447 |
| | $ | 658 |
|
Accumulated Benefit Obligation at measurement date | $ | 8,006 |
| | $ | 1,952 |
| | $ | 2,479 |
| | $ | 1,158 |
| | $ | 1,290 |
| | $ | 436 |
| | $ | 649 |
|
Change in Fair Value of Plan Assets | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Plan assets at prior measurement date | $ | 8,136 |
| | $ | 2,243 |
| | $ | 2,640 |
| | $ | 1,284 |
| | $ | 1,321 |
| | $ | 433 |
| | $ | 655 |
|
| Assets received from acquisition | 343 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Employer contributions | 155 |
| | 43 |
| | 43 |
| | 24 |
| | 20 |
| | 5 |
| | 9 |
|
| Actual return on plan assets | 582 |
| | 159 |
| | 190 |
| | 92 |
| | 95 |
| | 29 |
| | 47 |
|
| Benefits paid | (679 | ) | | (234 | ) | | (195 | ) | | (107 | ) | | (84 | ) | | (36 | ) | | (54 | ) |
| Impact of settlements | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Transfers | — |
| | 14 |
| | (3 | ) | | (3 | ) | | — |
| | (3 | ) | | — |
|
| Plan assets at measurement date | $ | 8,531 |
| | $ | 2,225 |
| | $ | 2,675 |
| | $ | 1,290 |
| | $ | 1,352 |
| | $ | 428 |
| | $ | 657 |
|
| Funded status of plan | $ | 400 |
| | $ | 273 |
| | $ | 163 |
| | $ | 132 |
| | $ | 29 |
| | $ | (19 | ) | | $ | (1 | ) |
|
| | | | | | | |
| | Piedmont |
| | Two Months Ended | | Years Ended |
| (in millions) | December 31, 2016 | | October 31, 2016 |
Change in Projected Benefit Obligation | | | |
| Obligation at prior measurement date | $ | 352 |
| | $ | 312 |
|
| Service cost | 2 |
| | 11 |
|
| Interest cost | 2 |
| | 9 |
|
| Actuarial gain | (5 | ) | | 34 |
|
| Benefits paid | (1 | ) | | (14 | ) |
| Impact of settlements | (6 | ) | | — |
|
| Obligation at measurement date | $ | 344 |
| | $ | 352 |
|
Accumulated Benefit Obligation at measurement date | $ | 289 |
| | $ | 296 |
|
Change in Fair Value of Plan Assets | |
| | |
|
| Plan assets at prior measurement date | $ | 343 |
| | $ | 329 |
|
| Employer contributions | 10 |
| | 10 |
|
| Actual return on plan assets | — |
| | 18 |
|
| Benefits paid | (1 | ) | | (14 | ) |
| Impact of settlements | (6 | ) | | — |
|
| Plan assets at measurement date | $ | 346 |
| | $ | 343 |
|
| Funded status of plan | $ | 2 |
| | $ | (9 | ) |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Recognized in the Consolidated Balance Sheets |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Prefunded pension(a) | $ | 680 |
| | $ | 343 |
| | $ | 245 |
| | $ | 155 |
| | $ | 87 |
| | $ | 8 |
| | $ | 16 |
| | $ | 55 |
|
Noncurrent pension liability(b) | $ | 125 |
| | $ | — |
| | $ | 68 |
| | $ | — |
| | $ | 68 |
| | $ | 29 |
| | $ | 1 |
| | $ | — |
|
| Net asset (liability) recognized | $ | 555 |
|
| $ | 343 |
|
| $ | 177 |
|
| $ | 155 |
|
| $ | 19 |
|
| $ | (21 | ) |
| $ | 15 |
| | $ | 55 |
|
| Regulatory assets | $ | 1,886 |
| | $ | 406 |
| | $ | 756 |
| | $ | 341 |
| | $ | 415 |
| | $ | 90 |
| | $ | 152 |
| | $ | 73 |
|
| Accumulated other comprehensive (income) loss | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Deferred income tax benefit | $ | (41 | ) | | $ | — |
| | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Prior service credit | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net actuarial loss | 116 |
| | — |
| | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts recognized in accumulated other comprehensive loss | $ | 70 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Amounts to be recognized in net periodic pension costs in the next year | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Unrecognized net actuarial loss | $ | 132 |
| | $ | 29 |
| | $ | 44 |
| | $ | 21 |
| | $ | 23 |
| | $ | 5 |
| | $ | 7 |
| | $ | 11 |
|
Unrecognized prior service credit | (32 | ) | | (8 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | — |
| | (2 | ) | | (9 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Prefunded pension(a) | $ | 518 |
| | $ | 273 |
| | $ | 225 |
| | $ | 132 |
| | $ | 91 |
| | $ | 6 |
| | $ | — |
| | 3 |
|
Noncurrent pension liability(b) | $ | 118 |
| | $ | — |
| | $ | 62 |
| | $ | — |
| | $ | 62 |
| | $ | 25 |
| | $ | 1 |
| | — |
|
| Net asset recognized | $ | 400 |
| | $ | 273 |
| | $ | 163 |
| | $ | 132 |
| | $ | 29 |
| | $ | (19 | ) | | $ | (1 | ) | | $ | 3 |
|
| Regulatory assets | $ | 2,098 |
| | $ | 476 |
| | $ | 805 |
| | $ | 378 |
| | $ | 426 |
| | $ | 81 |
| | $ | 171 |
| | $ | 137 |
|
| Accumulated other comprehensive (income) loss | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Deferred income tax benefit | $ | (41 | ) | | $ | — |
| | $ | (6 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Prior service credit | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net actuarial loss | 123 |
| | — |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts recognized in accumulated other comprehensive loss | $ | 76 |
| | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Amounts to be recognized in net periodic pension costs in the next year | | | | | | | | | | | | | | | |
| Unrecognized net actuarial loss | $ | 147 |
| | $ | 31 |
| | $ | 52 |
| | $ | 23 |
| | $ | 29 |
| | $ | 5 |
| | $ | 8 |
| | $ | 13 |
|
| Unrecognized prior service credit | $ | (24 | ) | | $ | (8 | ) | | $ | (3 | ) | | $ | (2 | ) | | $ | (1 | ) | | $ | — |
| | $ | (2 | ) | | $ | (2 | ) |
| |
| (a) | Included in Other within Other Noncurrent Assets on the Consolidated Balance Sheets. |
| |
| (b) | Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets |
| | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| Duke |
|
| | Duke |
| Progress |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Energy |
| Florida |
| Ohio |
|
| Projected benefit obligation | $ | 1,386 |
| $ | 718 |
| $ | 718 |
| $ | 337 |
|
| Accumulated benefit obligation | 1,326 |
| 683 |
| 683 |
| 326 |
|
| Fair value of plan assets | 1,260 |
| 650 |
| 650 |
| 308 |
|
|
| | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| Duke |
|
| | Duke |
| Progress |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Energy |
| Florida |
| Ohio |
|
| Projected benefit obligation | $ | 1,299 |
| $ | 665 |
| $ | 665 |
| $ | 311 |
|
| Accumulated benefit obligation | 1,239 |
| 633 |
| 633 |
| 299 |
|
| Fair value of plan assets | 1,182 |
| 604 |
| 604 |
| 286 |
|
Assumptions Used for Pension Benefits Accounting
The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.
The average remaining service period of active covered employees is 13 years for Duke Energy and Duke Energy Progress, 12 years for Duke Energy Carolinas, Progress Energy, and Duke Energy Florida, 14 years for Duke Energy Ohio and Duke Energy Indiana, and nine years for Piedmont.
The following tables present the assumptions or range of assumptions used for pension benefit accounting. |
| | | | | | | | | | | | | | | |
| | | December 31, |
| | | 2017 | | 2016 | | 2015 |
| Benefit Obligations | | | | | | | | | | | | |
| Discount rate | | | | 3.60% | | | | 4.10% | | | | 4.40% |
| Salary increase | | 3.50 | % | – | 4.00% | | 4.00 | % | – | 4.50% | | 4.00 | % | – | 4.40% |
| Net Periodic Benefit Cost | | | | | | | | | | | | |
| Discount rate | | | | 4.10% | | | | 4.40% | |
|
| | 4.10% |
Salary increase | | 4.00 | % | – | 4.50% | | 4.00 | % | – | 4.40% | | 4.00 | % | – | 4.40% |
| Expected long-term rate of return on plan assets | | 6.50 | % | – | 6.75% | | 6.50 | % | – | 6.75% | |
|
| | 6.50% |
|
| | | | | | | | | |
| | | Piedmont |
| | | Two Months Ended | | Years Ended October 31, |
| | | December 31, 2016 | | 2016 | | 2015 |
| Benefit Obligations | | | | | | |
| Discount rate | | 4.10 | % | | 3.80 | % | | 4.34 | % |
| Salary increase | | 4.50 | % | | 4.05 | % | | 4.07 | % |
| Net Periodic Benefit Cost | | | | |
| | |
|
| Discount rate | | 3.80 | % | | 4.34 | % | | 4.13 | % |
Salary increase | | 4.05 | % | | 4.07 | % | | 3.68 | % |
| Expected long-term rate of return on plan assets | | 6.75 | % | | 7.25 | % | | 7.50 | % |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Expected Benefit Payments |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Years ending December 31, | | | | | | | | |
| 2018 | $ | 642 |
| $ | 185 |
| $ | 161 |
| $ | 85 |
| $ | 75 |
| $ | 36 |
| $ | 47 |
| $ | 29 |
|
| 2019 | 644 |
| 185 |
| 164 |
| 86 |
| 77 |
| 36 |
| 46 |
| 26 |
|
| 2020 | 661 |
| 195 |
| 172 |
| 90 |
| 80 |
| 36 |
| 44 |
| 24 |
|
| 2021 | 666 |
| 194 |
| 175 |
| 93 |
| 81 |
| 37 |
| 44 |
| 24 |
|
| 2022 | 672 |
| 197 |
| 176 |
| 92 |
| 83 |
| 36 |
| 44 |
| 23 |
|
| 2023-2027 | 3,099 |
| 865 |
| 888 |
| 449 |
| 435 |
| 166 |
| 210 |
| 103 |
|
NON-QUALIFIED PENSION PLANS
Components of Net Periodic Pension Costs |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Service cost | $ | 2 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Interest cost on projected benefit obligation | 13 |
| 1 |
| 5 |
| 1 |
| 2 |
| — |
| — |
| — |
|
| Amortization of actuarial loss | 8 |
| — |
| 2 |
| 1 |
| 1 |
| — |
| — |
| — |
|
| Amortization of prior service credit | (2 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Net periodic pension costs | $ | 21 |
| $ | 2 |
| $ | 7 |
| $ | 2 |
| $ | 3 |
| $ | — |
| $ | — |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Service cost | $ | 2 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Interest cost on projected benefit obligation | 14 |
| 1 |
| 5 |
| 1 |
| 2 |
| — |
| — |
|
| Amortization of actuarial loss | 8 |
| 1 |
| 1 |
| 1 |
| 1 |
| — |
| — |
|
| Amortization of prior service credit | (1 | ) | — |
| — |
| — |
| — |
| — |
| — |
|
| Net periodic pension costs | $ | 23 |
| $ | 2 |
| $ | 6 |
| $ | 2 |
| $ | 3 |
| $ | — |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Service cost | $ | 3 |
| $ | — |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Interest cost on projected benefit obligation | 13 |
| 1 |
| 4 |
| 1 |
| 2 |
| — |
| — |
|
| Amortization of actuarial loss | 6 |
| — |
| 2 |
| 1 |
| 2 |
| — |
| 1 |
|
| Amortization of prior service credit | (1 | ) | — |
| (1 | ) | — |
| — |
| — |
| — |
|
| Net periodic pension costs | $ | 21 |
| $ | 1 |
| $ | 6 |
| $ | 2 |
| $ | 4 |
| $ | — |
| $ | 1 |
|
|
| | | | | | |
| | Piedmont |
| | Years Ended October 31, |
(in millions) | 2016 | 2015 |
| Amortization of prior service cost | $ | — |
| $ | 1 |
|
| Settlement charge | 1 |
| — |
|
| Net periodic pension costs | $ | 1 |
| $ | 1 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Liabilities |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Regulatory assets, net (decrease) increase | $ | 5 |
| $ | (1 | ) | $ | 3 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | — |
|
| Accumulated other comprehensive (income) loss | |
| |
| |
| |
| |
| |
| |
| |
|
| Deferred income tax benefit | $ | (1 | ) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Actuarial loss arising during the year | 2 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Net amount recognized in accumulated other comprehensive loss (income) | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Regulatory assets, net (decrease) increase | $ | (3 | ) | $ | (2 | ) | $ | 2 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | (1 | ) |
| Accumulated other comprehensive (income) loss | | | | | | | |
| Prior service credit arising during the year | $ | (1 | ) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Actuarial gains arising during the year | 1 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Net amount recognized in accumulated other comprehensive loss (income) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Reconciliation of Funded Status to Net Amount Recognized |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
Change in Projected Benefit Obligation | |
| |
| |
| |
| |
| |
| |
| |
| Obligation at prior measurement date | $ | 332 |
| $ | 14 |
| $ | 114 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
| Service cost | 2 |
| 1 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Interest cost | 13 |
| 1 |
| 5 |
| 1 |
| 2 |
| — |
| — |
| — |
|
| Actuarial losses (gains) | 15 |
| — |
| 5 |
| 4 |
| 2 |
| — |
| — |
| — |
|
| Benefits paid | (31 | ) | (2 | ) | (8 | ) | (3 | ) | (3 | ) | — |
| — |
| — |
|
| Obligation at measurement date | $ | 331 |
| $ | 14 |
| $ | 116 |
| $ | 35 |
| $ | 47 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
Accumulated Benefit Obligation at measurement date | $ | 331 |
| $ | 14 |
| $ | 116 |
| $ | 35 |
| $ | 47 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
Change in Fair Value of Plan Assets | |
| |
| |
| |
| |
| |
| |
| |
|
| Benefits paid | $ | (31 | ) | $ | (2 | ) | $ | (8 | ) | $ | (3 | ) | $ | (3 | ) | $ | — |
| $ | — |
| $ | — |
|
| Employer contributions | 31 |
| 2 |
| 8 |
| 3 |
| 3 |
| — |
| — |
| — |
|
| Plan assets at measurement date | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
Change in Projected Benefit Obligation | | |
| |
| |
| |
| |
| |
|
| Obligation at prior measurement date | $ | 341 |
| $ | 16 |
| $ | 112 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 5 |
|
| Obligation assumed from acquisition | 5 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Service cost | 2 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Interest cost | 14 |
| 1 |
| 5 |
| 1 |
| 2 |
| — |
| — |
|
| Actuarial losses (gains) | 4 |
| (1 | ) | 5 |
| 2 |
| 1 |
| — |
| (2 | ) |
| Plan amendments | (2 | ) | — |
| — |
| — |
| — |
| — |
| |
| Benefits paid | (32 | ) | (2 | ) | (8 | ) | (3 | ) | (3 | ) | — |
| — |
|
| Obligation at measurement date | $ | 332 |
| $ | 14 |
| $ | 114 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 3 |
|
| Accumulated Benefit Obligation at measurement date | $ | 332 |
| $ | 14 |
| $ | 114 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 3 |
|
| Change in Fair Value of Plan Assets | |
| |
| |
| |
| |
| |
| |
|
| Benefits paid | $ | (32 | ) | $ | (2 | ) | $ | (8 | ) | $ | (3 | ) | $ | (3 | ) | — |
| — |
|
| Employer contributions | 32 |
| 2 |
| 8 |
| 3 |
| 3 |
| — |
| — |
|
| Plan assets at measurement date | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
|
| | | | | | | |
| | Piedmont |
| | Two Months Ended | | Years Ended |
| (in millions) | December 31, 2016 | | October 31, 2016 |
Change in Projected Benefit Obligation | | | |
| Obligation at prior measurement date | $ | 5 |
| | $ | 6 |
|
| Actuarial gain | (1 | ) | | — |
|
| Impact of settlements | — |
| | (1 | ) |
| Obligation at measurement date | $ | 4 |
| | $ | 5 |
|
Accumulated Benefit Obligation at measurement date | $ | — |
| | $ | 5 |
|
Change in Fair Value of Plan Assets | |
| | |
|
| Plan assets at prior measurement date | $ | — |
| | $ | 1 |
|
| Impact of settlements | — |
| | (1 | ) |
| Plan assets at measurement date | $ | — |
| | $ | — |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Recognized in the Consolidated Balance Sheets |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
Current pension liability(a) | $ | 23 |
| $ | 2 |
| $ | 8 |
| $ | 3 |
| $ | 3 |
| $ | — |
| $ | — |
| $ | — |
|
Noncurrent pension liability(b) | 308 |
| 12 |
| 108 |
| 32 |
| 44 |
| 4 |
| 3 |
| 4 |
|
| Total accrued pension liability | $ | 331 |
| $ | 14 |
| $ | 116 |
| $ | 35 |
| $ | 47 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
| Regulatory assets | $ | 78 |
| $ | 4 |
| $ | 21 |
| $ | 8 |
| $ | 13 |
| $ | 1 |
| $ | — |
| $ | 1 |
|
| Accumulated other comprehensive (income) loss | | |
| |
| |
| |
| |
| |
| |
|
| Deferred income tax benefit | $ | (4 | ) | $ | — |
| $ | (3 | ) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Prior service credit | (1 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Net actuarial loss | 12 |
| — |
| 9 |
| — |
| — |
| — |
| — |
| — |
|
| Net amounts recognized in accumulated other comprehensive loss | $ | 7 |
| $ | — |
| $ | 6 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Amounts to be recognized in net periodic pension expense in the next year | | |
| |
| |
| |
| |
| |
| |
|
| Unrecognized net actuarial loss | $ | 8 |
| $ | — |
| $ | 2 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
Unrecognized prior service credit | (2 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
Current pension liability(a) | $ | 28 |
| $ | 2 |
| $ | 8 |
| $ | 2 |
| $ | 3 |
| $ | — |
| $ | — |
| $ | — |
|
Noncurrent pension liability(b) | 304 |
| 12 |
| 106 |
| 31 |
| 43 |
| 4 |
| 3 |
| 4 |
|
| Total accrued pension liability | $ | 332 |
| $ | 14 |
| $ | 114 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
| Regulatory assets | $ | 73 |
| $ | 5 |
| $ | 18 |
| $ | 7 |
| $ | 11 |
| $ | 1 |
| $ | — |
| $ | 1 |
|
| Accumulated other comprehensive (income) loss | |
| |
| |
| |
| |
| |
| |
| |
|
| Deferred income tax benefit | $ | (3 | ) | $ | — |
| $ | (3 | ) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Prior service credit | (1 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Net actuarial loss | 10 |
| — |
| 9 |
| — |
| — |
| — |
| — |
| — |
|
| Net amounts recognized in accumulated other comprehensive loss | $ | 6 |
| $ | — |
| $ | 6 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Amounts to be recognized in net periodic pension expense in the next year | | | | | | | | |
| Unrecognized net actuarial loss | $ | 7 |
| $ | — |
| $ | 2 |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
|
| Unrecognized prior service credit | $ | (2 | ) | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
(a) Included in Other within Current Liabilities on the Consolidated Balance Sheets.
| |
| (b) | Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Projected benefit obligation | $ | 331 |
| $ | 14 |
| $ | 116 |
| $ | 35 |
| $ | 47 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
| Accumulated benefit obligation | 331 |
| 14 |
| 116 |
| 35 |
| 47 |
| 4 |
| 3 |
| 4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Projected benefit obligation | $ | 332 |
| $ | 14 |
| $ | 114 |
| $ | 33 |
| $ | 46 |
| $ | 4 |
| $ | 3 |
| $ | 4 |
|
| Accumulated benefit obligation | 332 |
| 14 |
| 114 |
| 33 |
| 46 |
| 4 |
| 3 |
| 4 |
|
Assumptions Used for Pension Benefits Accounting
The discount rate used to determine the current year pension obligation and following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected.
The average remaining service period of active covered employees is 11 years for Duke Energy and Duke Energy Progress, 14 years for Progress Energy, 15 years for Duke Energy Florida, eight years for Duke Energy Carolinas, Duke Energy Ohio, and Duke Energy Indiana, and nine years for Piedmont. The following tables present the assumptions used for pension benefit accounting. |
| | | | | | | | | | | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | 2015 |
|
Benefit Obligations | | | | |
| | |
| | �� |
|
| Discount rate | |
|
| | 3.60 | % | | 4.10 | % | | 4.40 | % |
| Salary increase | | 3.50 | % | – | 4.00 | % | | 4.40 | % | | 4.40 | % |
Net Periodic Benefit Cost | | | | |
| | |
| | |
|
| Discount rate | | | | 4.10 | % | | 4.40 | % | | 4.10 | % |
Salary increase | | | | 4.40 | % | | 4.40 | % | | 4.40 | % |
|
| | | | | | | | | |
| | | Piedmont |
| | | Two Months Ended | | Years Ended October 31, |
| | | December 31, 2016 | | 2016 | | 2015 |
| Benefit Obligations | | | | | | |
| Discount rate | | 4.10 | % | | 3.80 | % | | 3.85 | % |
| Net Periodic Benefit Cost | | | | |
| | |
|
| Discount rate | | 3.80 | % | | 3.85 | % | | 3.69 | % |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Expected Benefit Payments |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Years ending December 31, | | | | | | | | |
| 2018 | $ | 23 |
| $ | 2 |
| $ | 8 |
| $ | 3 |
| $ | 3 |
| $ | — |
| $ | — |
| $ | — |
|
| 2019 | 21 |
| 1 |
| 8 |
| 2 |
| 3 |
| — |
| — |
| — |
|
| 2020 | 21 |
| 1 |
| 8 |
| 2 |
| 3 |
| — |
| — |
| — |
|
| 2021 | 22 |
| 1 |
| 8 |
| 2 |
| 3 |
| — |
| — |
| — |
|
| 2022 | 25 |
| 1 |
| 8 |
| 2 |
| 3 |
| — |
| — |
| — |
|
| 2023-2027 | 117 |
| 6 |
| 36 |
| 11 |
| 15 |
| 1 |
| 1 |
| 2 |
|
OTHER POST-RETIREMENT BENEFIT PLANS
Duke Energy provides, and the Subsidiary Registrants participate in, some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. The health care benefits include medical, dental and prescription drug coverage and are subject to certain limitations, such as deductibles and copayments.
Duke Energy did not make any pre-funding contributions to its other post-retirement benefit plans during the years ended December 31, 2017, 2016 or 2015.
Components of Net Periodic Other Post-Retirement Benefit Costs |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Service cost | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Interest cost on accumulated post-retirement benefit obligation | 34 |
| | 8 |
| | 13 |
| | 7 |
| | 6 |
| | 1 |
| | 3 |
| | 1 |
|
| Expected return on plan assets | (14 | ) | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (2 | ) |
| Amortization of actuarial loss (gain) | 10 |
| | (2 | ) | | 21 |
| | 12 |
| | 9 |
| | (2 | ) | | (1 | ) | | 1 |
|
| Amortization of prior service credit | (115 | ) | | (10 | ) | | (84 | ) | | (54 | ) | | (30 | ) | | — |
| | (1 | ) | | — |
|
Curtailment credit (c) | $ | (30 | ) | | $ | (4 | ) | | $ | (16 | ) | | $ | — |
| | $ | (16 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | — |
|
Net periodic post-retirement benefit costs(a)(b) | $ | (111 | ) | | $ | (15 | ) | | $ | (66 | ) | | $ | (35 | ) | | $ | (31 | ) | | $ | (3 | ) | | $ | (2 | ) | | $ | 1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Service cost | $ | 3 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Interest cost on accumulated post-retirement benefit obligation | 35 |
| | 8 |
| | 15 |
| | 8 |
| | 7 |
| | 1 |
| | 4 |
|
| Expected return on plan assets | (12 | ) | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| Amortization of actuarial loss (gain) | 6 |
| | (3 | ) | | 22 |
| | 13 |
| | 9 |
| | (2 | ) | | (1 | ) |
| Amortization of prior service credit | (141 | ) | | (14 | ) | | (103 | ) | | (68 | ) | | (35 | ) | | — |
| | (1 | ) |
Net periodic post-retirement benefit costs(a)(b) | $ | (109 | ) | | $ | (16 | ) | | $ | (65 | ) | | $ | (47 | ) | | $ | (18 | ) | | $ | (1 | ) | | $ | 1 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost on accumulated post-retirement benefit obligation | 36 |
| | 9 |
| | 15 |
| | 8 |
| | 7 |
| | 2 |
| | 4 |
|
| Expected return on plan assets | (13 | ) | | (8 | ) | | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Amortization of actuarial loss (gain) | 16 |
| | (2 | ) | | 28 |
| | 18 |
| | 10 |
| | (2 | ) | | (2 | ) |
| Amortization of prior service credit | (140 | ) | | (14 | ) | | (102 | ) | | (68 | ) | | (35 | ) | | — |
| | — |
|
Net periodic post-retirement benefit costs(a)(b) | $ | (95 | ) | | $ | (14 | ) | | $ | (58 | ) | | $ | (41 | ) | | $ | (17 | ) | | $ | (1 | ) | | $ | 2 |
|
| |
| (a) | Duke Energy amounts exclude $7 million, $8 million and $10 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006. |
| |
| (b) | Duke Energy Ohio amounts exclude $2 million, $2 million and $3 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006. |
| |
| (c) | Curtailment credit resulted from a reduction in average future service of plan participants due to a plan amendment. |
|
| | | | | | |
| | Piedmont |
| | Years Ended October 31, |
(in millions) | 2016 | 2015 |
| Service cost | $ | 1 |
| $ | 1 |
|
| Interest cost on projected benefit obligation | 1 |
| 2 |
|
| Expected return on plan assets | (2 | ) | (2 | ) |
| Amortization of actuarial loss | 1 |
| — |
|
| Net periodic pension costs | $ | 1 |
| $ | 1 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Recognized in Accumulated Other Comprehensive Income and Regulatory Assets and Liabilities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
| Regulatory assets, net increase (decrease) | $ | 71 |
| | $ | — |
| | $ | 81 |
| | $ | 42 |
| | $ | 39 |
| | $ | — |
| | $ | (5 | ) | | $ | (11 | ) |
| Regulatory liabilities, net increase (decrease) | $ | (27 | ) | | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (3 | ) | | $ | (7 | ) | | $ | — |
|
| Accumulated other comprehensive (income) loss | | | | | | | | | | | | | | | |
| Deferred income tax benefit | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Amortization of prior year prior service credit | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amount recognized in accumulated other comprehensive income | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Regulatory assets, net increase (decrease) | $ | 53 |
| | $ | — |
| | $ | 47 |
| | $ | 38 |
| | $ | 9 |
| | $ | — |
| | $ | (6 | ) |
| Regulatory liabilities, net increase (decrease) | $ | (114 | ) | | $ | (22 | ) | | $ | (51 | ) | | $ | (25 | ) | | $ | (26 | ) | | $ | (2 | ) | | $ | (12 | ) |
| Accumulated other comprehensive (income) loss | | | | | | | | | | | | | |
| Deferred income tax benefit | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Actuarial losses arising during the year | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of prior year prior service credit | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Net amount recognized in accumulated other comprehensive income | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Piedmont's regulatory assets net decreased $1 million for the two months ended December 31, 2016, and increased $2 million and $1 million for the years ended October 31, 2016, and 2015, respectively.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Change in Projected Benefit Obligation | |
| | | | | | | | | | | | | | |
| Accumulated post-retirement benefit obligation at prior measurement date | $ | 868 |
| | $ | 201 |
| | $ | 357 |
| | $ | 191 |
| | $ | 164 |
| | $ | 32 |
| | $ | 83 |
| | $ | 39 |
|
| Service cost | 4 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Interest cost | 34 |
| | 8 |
| | 13 |
| | 7 |
| | 6 |
| | 1 |
| | 3 |
| | 1 |
|
| Plan participants' contributions | 17 |
| | 3 |
| | 6 |
| | 3 |
| | 3 |
| | 1 |
| | 2 |
| | — |
|
| Actuarial (gains) losses | 4 |
| | (3 | ) | | 4 |
| | 1 |
| | 3 |
| | — |
| | 3 |
| | 1 |
|
| Transfers | — |
| | 2 |
| | (1 | ) | | — |
| | (1 | ) | | 1 |
| | — |
| | — |
|
| Plan amendments | (28 | ) | | (5 | ) | | (3 | ) | | (1 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | (9 | ) |
| Benefits paid | (86 | ) | | (18 | ) | | (34 | ) | | (17 | ) | | (17 | ) | | (3 | ) | | (11 | ) | | (1 | ) |
| Accumulated post-retirement benefit obligation at measurement date | $ | 813 |
| | $ | 189 |
| | $ | 342 |
| | $ | 184 |
| | $ | 156 |
| | $ | 30 |
| | $ | 78 |
| | $ | 32 |
|
Change in Fair Value of Plan Assets | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Plan assets at prior measurement date | $ | 244 |
| | $ | 137 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 22 |
| | $ | 29 |
|
| Actual return on plan assets | 25 |
| | 15 |
| | 1 |
| | — |
| | — |
| | 2 |
| | 1 |
| | 3 |
|
| Benefits paid | (86 | ) | | (18 | ) | | (34 | ) | | (17 | ) | | (17 | ) | | (3 | ) | | (11 | ) | | (1 | ) |
| Employer contributions (reimbursements) | 25 |
| | (4 | ) | | 26 |
| | 14 |
| | 14 |
| | — |
| | (3 | ) | | — |
|
| Plan participants' contributions | 17 |
| | 3 |
| | 6 |
|
| 3 |
|
| 3 |
|
| 1 |
|
| 2 |
| | — |
|
| Plan assets at measurement date | $ | 225 |
| | $ | 133 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 11 |
| | $ | 31 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
Change in Projected Benefit Obligation | | | | | | | | | | | | | |
| Accumulated post-retirement benefit obligation at prior measurement date | $ | 828 |
| | $ | 200 |
| | $ | 354 |
| | $ | 188 |
| | $ | 164 |
| | $ | 35 |
| | $ | 87 |
|
| Obligation assumed from acquisition | 39 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Service cost | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
|
| Interest cost | 35 |
| | 8 |
| | 15 |
| | 8 |
| | 7 |
| | 1 |
| | 4 |
|
| Plan participants' contributions | 19 |
| | 3 |
| | 7 |
| | 4 |
| | 3 |
| | 1 |
| | 2 |
|
| Actuarial (gains) losses | 33 |
| | 5 |
| | 16 |
| | 8 |
| | 8 |
| | — |
| | 3 |
|
| Transfers | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Plan amendments | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
|
| Benefits paid | (88 | ) | | (17 | ) | | (36 | ) | | (17 | ) | | (19 | ) | | (4 | ) | | (13 | ) |
| Accumulated post-retirement benefit obligation at measurement date | $ | 868 |
| | $ | 201 |
| | $ | 357 |
| | $ | 191 |
| | $ | 164 |
| | $ | 32 |
| | $ | 83 |
|
Change in Fair Value of Plan Assets | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Plan assets at prior measurement date | $ | 208 |
| | $ | 134 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 8 |
| | $ | 19 |
|
| Assets received from acquisition | 29 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Actual return on plan assets | 14 |
| | 8 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 2 |
|
| Benefits paid | (88 | ) | | (17 | ) | | (36 | ) | | (17 | ) | | (19 | ) | | (4 | ) | | (13 | ) |
| Employer contributions | 62 |
| | 9 |
| | 29 |
| | 13 |
| | 15 |
| | 1 |
| | 12 |
|
| Plan participants' contributions | 19 |
| | 3 |
| | 7 |
| | 4 |
| | 3 |
| | 1 |
| | 2 |
|
| Plan assets at measurement date | $ | 244 |
| | $ | 137 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 22 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | |
| | Piedmont |
| | Two Months Ended | | Years Ended |
| (in millions) | December 31, 2016 | | October 31, 2016 |
Change in Projected Benefit Obligation | | | |
| Accumulated post-retirement benefit obligation at prior measurement date | $ | 39 |
| | $ | 38 |
|
| Service cost | — |
| | 1 |
|
| Interest cost | — |
| | 1 |
|
| Actuarial gain | — |
| | 2 |
|
| Benefits paid | — |
| | (3 | ) |
| Accumulated post-retirement benefit obligation at measurement date | $ | 39 |
| | $ | 39 |
|
Change in Fair Value of Plan Assets | |
| | |
|
| Plan assets at prior measurement date | $ | 29 |
| | $ | 28 |
|
| Employer contributions | — |
| | 3 |
|
| Actual return on plan assets | — |
| | 1 |
|
| Benefits paid | — |
| | (3 | ) |
| Plan assets at measurement date | $ | 29 |
| | $ | 29 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Amounts Recognized in the Consolidated Balance Sheets |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Current post-retirement liability(a) | $ | 36 |
| | $ | — |
| | $ | 29 |
| | $ | 15 |
| | $ | 14 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
Noncurrent post-retirement liability(b) | 552 |
| | 56 |
| | 313 |
| | 169 |
| | 142 |
| | 21 |
| | 67 |
| | 1 |
|
| Total accrued post-retirement liability | $ | 588 |
| | $ | 56 |
| | $ | 342 |
| | $ | 184 |
| | $ | 156 |
| | $ | 23 |
| | $ | 67 |
| | $ | 1 |
|
| Regulatory assets | $ | 125 |
| | $ | — |
| | $ | 129 |
| | $ | 80 |
| | $ | 49 |
| | $ | — |
| | $ | 46 |
| | $ | (4 | ) |
| Regulatory liabilities | $ | 147 |
| | $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 64 |
| | $ | — |
|
| Accumulated other comprehensive (income) loss | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Deferred income tax expense | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Prior service credit | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net actuarial gain | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts recognized in accumulated other comprehensive income | $ | (8 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Amounts to be recognized in net periodic pension expense in the next year | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Unrecognized net actuarial loss | $ | 5 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Unrecognized prior service credit | (19 | ) | | (5 | ) | | (7 | ) | | (1 | ) | | (6 | ) | | (1 | ) | | (1 | ) | | (2 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Current post-retirement liability(a) | $ | 38 |
| | $ | — |
| | $ | 31 |
| | $ | 17 |
| | $ | 15 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
Noncurrent post-retirement liability(b) | 586 |
| | 64 |
| | 325 |
| | 174 |
| | 149 |
| | 23 |
| | 63 |
| | 10 |
|
| Total accrued post-retirement liability | $ | 624 |
| | $ | 64 |
| | $ | 356 |
| | $ | 191 |
| | $ | 164 |
| | $ | 25 |
| | $ | 63 |
| | $ | 10 |
|
| Regulatory assets | $ | 54 |
| | $ | — |
| | $ | 48 |
| | $ | 38 |
| | $ | 10 |
| | $ | — |
| | $ | 51 |
| | $ | 7 |
|
| Regulatory liabilities | $ | 174 |
| | $ | 46 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 19 |
| | $ | 71 |
| | $ | — |
|
| Accumulated other comprehensive (income) loss | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Deferred income tax expense | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Prior service credit | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net actuarial gain | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts recognized in accumulated other comprehensive income | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Amounts to be recognized in net periodic pension expense in the next year | | | | | | | | | | | | | | | |
| Unrecognized net actuarial loss (gain) | $ | 10 |
| | $ | (2 | ) | | $ | 21 |
| | $ | 12 |
| | $ | 9 |
| | $ | (2 | ) | | $ | (6 | ) | | $ | — |
|
| Unrecognized prior service credit | (115 | ) | | (10 | ) | | (85 | ) | | (55 | ) | | (30 | ) | | — |
| | (1 | ) | | — |
|
| |
| (a) | Included in Other within Current Liabilities on the Consolidated Balance Sheets. |
| |
| (b) | Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Assumptions Used for Other Post-Retirement Benefits Accounting
The discount rate used to determine the current year other post-retirement benefits obligation and following year’s other post-retirement benefits expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flow to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The average remaining service period of active covered employees is nine years for Duke Energy, eight years for Duke Energy Carolinas, seven years for Duke Energy Florida, Duke Energy Ohio, and Piedmont, and six years for Progress Energy, Duke Energy Progress, and Duke Energy Indiana.
The following tables present the assumptions used for other post-retirement benefits accounting. |
| | | | | | | | | |
| | | December 31, |
| | | 2017 |
| | 2016 |
| | 2015 |
|
Benefit Obligations | | |
| | |
| | |
| Discount rate | | 3.60 | % | | 4.10 | % | | 4.40 | % |
Net Periodic Benefit Cost | | |
| | |
| | |
| Discount rate | | 4.10 | % | | 4.40 | % | | 4.10 | % |
| Expected long-term rate of return on plan assets | | 6.50 | % | | 6.50 | % | | 6.50 | % |
| Assumed tax rate | | 35 | % | | 35 | % | | 35 | % |
|
| | | | | | | | | |
| | | Piedmont |
| | | Two Months Ended | | Years Ended October 31, |
| | | December 31, 2016 | | 2016 | | 2015 |
| Benefit Obligations | | | | | | |
| Discount rate | | 4.10 | % | | 3.80 | % | | 4.38 | % |
| Net Periodic Benefit Cost | | | | |
| | |
|
| Discount rate | | 3.80 | % | | 4.38 | % | | 4.03 | % |
| Expected long-term rate of return on plan assets | | 6.75 | % | | 7.25 | % | | 7.50 | % |
Assumed Health Care Cost Trend Rate |
| | | | | |
| | December 31, |
| | 2017 |
| | 2016 |
|
| Health care cost trend rate assumed for next year | 7.00 | % | | 7.00 | % |
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.75 | % | | 4.75 | % |
| Year that rate reaches ultimate trend | 2024 |
| | 2023 |
|
Sensitivity to Changes in Assumed Health Care Cost Trend Rates |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
1-Percentage Point Increase | | | | | |
| | | |
| Effect on total service and interest costs | $ | 1 |
| $ | — |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Effect on post-retirement benefit obligation | 27 |
| 6 |
| 11 |
| 6 |
| 5 |
| 1 |
| 3 |
| 1 |
|
| 1-Percentage Point Decrease | | | | | | | | |
| Effect on total service and interest costs | (1 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Effect on post-retirement benefit obligation | (24 | ) | (6 | ) | (10 | ) | (5 | ) | (5 | ) | (1 | ) | (2 | ) | (1 | ) |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Expected Benefit Payments |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Years ending December 31, | | | | | | |
| | |
| 2018 | $ | 78 |
| $ | 17 |
| $ | 30 |
| $ | 16 |
| $ | 14 |
| $ | 3 |
| $ | 9 |
| $ | 2 |
|
| 2019 | 76 |
| 17 |
| 29 |
| 15 |
| 14 |
| 3 |
| 9 |
| 2 |
|
| 2020 | 73 |
| 17 |
| 29 |
| 15 |
| 14 |
| 3 |
| 8 |
| 2 |
|
| 2021 | 71 |
| 17 |
| 28 |
| 15 |
| 13 |
| 3 |
| 7 |
| 3 |
|
| 2022 | 68 |
| 17 |
| 27 |
| 14 |
| 13 |
| 3 |
| 7 |
| 3 |
|
| 2023 – 2027 | 290 |
| 70 |
| 117 |
| 63 |
| 54 |
| 12 |
| 29 |
| 13 |
|
PLAN ASSETS
Description and Allocations
Duke Energy Master Retirement Trust
Assets for both the qualified pension and other post-retirement benefits are maintained in the Duke Energy Master Retirement Trust. Qualified pension and other post-retirement assets related to Piedmont were transferred into the Duke Energy Master Retirement Trust during 2017. Approximately 98 percent of the Duke Energy Master Retirement Trust assets were allocated to qualified pension plans and approximately 2 percent were allocated to other post-retirement plans (comprised of 401(h) accounts), as of December 31, 2017, and 2016. The investment objective of the Duke Energy Master Retirement Trust is to achieve reasonable returns, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants.
As of December 31, 2017, Duke Energy assumes pension and other post-retirement plan assets will generate a long-term rate of return of 6.50 percent. The expected long-term rate of return was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers, where applicable. The asset allocation targets were set after considering the investment objective and the risk profile. Equity securities are held for their higher expected returns. Debt securities are primarily held to hedge the qualified pension plan liability. Hedge funds, real estate and other global securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the impact of individual managers or investments.
In 2013, Duke Energy adopted a de-risking investment strategy for the Duke Energy Master Retirement Trust. As the funded status of the pension plans increase, the targeted allocation to fixed-income assets may be increased to better manage Duke Energy’s pension liability and reduce funded status volatility. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.
The Duke Energy Master Retirement Trust is authorized to engage in the lending of certain plan assets. Securities lending is an investment management enhancement that utilizes certain existing securities of the Duke Energy Master Retirement Trust to earn additional income. Securities lending involves the loaning of securities to approved parties. In return for the loaned securities, the Duke Energy Master Retirement Trust receives collateral in the form of cash and securities as a safeguard against possible default of any borrower on the return of the loan under terms that permit the Duke Energy Master Retirement Trust to sell the securities. The Duke Energy Master Retirement Trust mitigates credit risk associated with securities lending arrangements by monitoring the fair value of the securities loaned, with additional collateral obtained or refunded as necessary. The fair value of securities on loan was approximately $195 million and $156 million at December 31, 2017, and 2016, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned at December 31, 2017, and 2016, respectively. Securities lending income earned by the Duke Energy Master Retirement Trust was immaterial for the years ended December 31, 2017, 2016 and 2015, respectively.
Qualified pension and other post-retirement benefits for the Subsidiary Registrants are derived from the Duke Energy Master Retirement Trust, as such, each are allocated their proportionate share of the assets discussed below.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table includes the target asset allocations by asset class at December 31, 2017, and the actual asset allocations for the Duke Energy Master Retirement Trust. |
| | | | | | | | |
| | | | Actual Allocation at |
| | Target |
| | December 31, |
| | Allocation |
| | 2017 |
| | 2016(a) |
|
| U.S. equity securities | 10 | % | | 11 | % | | 11 | % |
| Non-U.S. equity securities | 8 | % | | 8 | % | | 8 | % |
| Global equity securities | 10 | % | | 10 | % | | 10 | % |
| Global private equity securities | 3 | % | | 2 | % | | 2 | % |
| Debt securities | 63 | % | | 63 | % | | 63 | % |
| Hedge funds | 2 | % | | 2 | % | | 2 | % |
| Real estate and cash | 2 | % | | 2 | % | | 2 | % |
| Other global securities | 2 | % | | 2 | % | | 2 | % |
| Total | 100 | % | | 100 | % | | 100 | % |
| |
| (a) | Excludes Piedmont Pension Assets, which had a targeted asset allocation of 60 percent return-seeking and 40 percent liability hedging fixed-income. Actual asset allocations were 61 percent return-seeking and 39 percent liability hedging fixed-income at December 31, 2016. |
Other post-retirement assets
Duke Energy's other post-retirement assets are comprised of Voluntary Employees' Beneficiary Association (VEBA) trusts and 401(h) accounts held within the Duke Energy Master Retirement Trust. Duke Energy's investment objective is to achieve sufficient returns, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants.
The following table presents target and actual asset allocations for the VEBA trusts at December 31, 2017. |
| | | | | | | | |
| | | | Actual Allocation at |
| | Target |
| | December 31, |
| | Allocation |
| | 2017 |
| | 2016 |
|
| U.S. equity securities | 32 | % | | 41 | % | | 39 | % |
| Non-US equity securities | 6 | % | | 8 | % | | — | % |
| Real estate | 2 | % | | 2 | % | | 2 | % |
| Debt securities | 45 | % | | 36 | % | | 37 | % |
| Cash | 15 | % | | 13 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % |
Fair Value Measurements
Duke Energy classifies recurring and non-recurring fair value measurements based on the fair value hierarchy as discussed in Note 16.
Valuation methods of the primary fair value measurements disclosed below are as follows:
Investments in equity securities
Investments in equity securities are typically valued at the closing price in the principal active market as of the last business day of the reporting period. Principal active markets for equity prices include published exchanges such as NASDAQ and NYSE. Foreign equity prices are translated from their trading currency using the currency exchange rate in effect at the close of the principal active market. Prices have not been adjusted to reflect after-hours market activity. The majority of investments in equity securities are valued using Level 1 measurements. When the price of an institutional commingled fund is unpublished, it is not categorized in the fair value hierarchy, even though the funds are readily available at the fair value.
Investments in corporate debt securities and U.S. government securities
Most debt investments are valued based on a calculation using interest rate curves and credit spreads applied to the terms of the debt instrument (maturity and coupon interest rate) and consider the counterparty credit rating. Most debt valuations are Level 2 measurements. If the market for a particular fixed-income security is relatively inactive or illiquid, the measurement is Level 3. U.S. Treasury debt is typically Level 2.
Investments in short-term investment funds
Investments in short-term investment funds are valued at the net asset value of units held at year end and are readily redeemable at the measurement date. Investments in short-term investment funds with published prices are valued as Level 1. Investments in short-term investment funds with unpublished prices are valued as Level 2.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Investments in real estate limited partnerships
Investments in real estate limited partnerships are valued by the trustee at each valuation date (monthly). As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis, conducted by reputable, independent appraisal firms, and signed by appraisers that are members of the Appraisal Institute, with the professional designation MAI. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three valuation techniques that can be used to value investments in real estate assets: the market, income or cost approach. The appropriateness of each valuation technique depends on the type of asset or business being valued. In addition, the trustee may cause additional appraisals to be performed as warranted by specific asset or market conditions. Property valuations and the salient valuation-sensitive assumptions of each direct investment property are reviewed by the trustee quarterly and values are adjusted if there has been a significant change in whichcircumstances related to the entity transacts. We classifyinvestment property since the last valuation. Value adjustments for interim capital expenditures are only recognized to the extent that the valuation process acknowledges a corresponding increase in fair value. An independent firm is hired to review and approve quarterly direct real estate valuations. Key inputs and assumptions used to determine fair value balances based on the observanceincludes among others, rental revenue and expense amounts and related revenue and expense growth rates, terminal capitalization rates and discount rates. Development investments are valued using cost incurred to date as a primary input until substantive progress is achieved in terms of mitigating construction and leasing risk at which point a discounted cash flow approach is more heavily weighted. Key inputs and assumptions in addition to those inputs intonoted above used to determine the fair value hierarchy levels as set forthof development investments include construction costs and the status of construction completion and leasing. Investments in real estate limited partnerships are valued at net asset value of units held at year end and are not readily redeemable at the measurement date. Investments in real estate limited partnerships are not categorized within the fair value accounting guidancehierarchy.
Duke Energy Master Retirement Trust
The following tables provide the fair value measurement amounts for the Duke Energy Master Retirement Trust qualified pension and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.other post-retirement assets. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | Total Fair |
| | | | | | | | Not |
|
| (in millions) | Value |
| | Level 1 |
| | Level 2 |
| | Level 3 |
| | Categorized(b) |
|
| Equity securities | $ | 2,823 |
| | $ | 1,976 |
| | $ | — |
| | $ | — |
| | 847 |
|
| Corporate debt securities | 4,694 |
| | — |
| | 4,694 |
| | — |
| | — |
|
| Short-term investment funds | 246 |
| | 192 |
| | 54 |
| | — |
| | — |
|
| Partnership interests | 137 |
| | — |
| | — |
| | — |
| | 137 |
|
| Hedge funds | 226 |
| | — |
| | — |
| | — |
| | 226 |
|
| Real estate limited partnerships | 135 |
| | — |
| | — |
| | — |
| | 135 |
|
| U.S. government securities | 762 |
| | — |
| | 762 |
| | — |
| | — |
|
| Guaranteed investment contracts | 28 |
| | — |
| | — |
| | 28 |
| | — |
|
| Governments bonds – foreign | 38 |
| | — |
| | 38 |
| | — |
| | — |
|
| Cash | 6 |
| | 6 |
| | — |
| | — |
| | — |
|
| Government and commercial mortgage backed securities | 2 |
| | — |
| | 2 |
| | — |
| | — |
|
| Net pending transactions and other investments | 17 |
| | 15 |
| | 2 |
| | — |
| | — |
|
Total assets(a) | $ | 9,114 |
| | $ | 2,189 |
| | $ | 5,552 |
| | $ | 28 |
|
| $ | 1,345 |
|
| |
| (a) | Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana, and Piedmont were allocated approximately 27 percent, 30 percent, 15 percent, 15 percent, 5 percent, 8 percent, and 4 percent, respectively, of the Duke Energy Master Retirement Trust at December 31, 2017. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages. |
| |
| (b) | Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | Total Fair |
| | | | | | | | Not |
|
| (in millions) | Value |
| | Level 1 |
| | Level 2 |
| | Level 3 |
| | Categorized(b) |
|
| Equity securities | $ | 2,472 |
| | $ | 1,677 |
| | $ | 27 |
| | $ | 9 |
| | 759 |
|
| Corporate debt securities | 4,330 |
| | 8 |
| | 4,322 |
| | — |
| | — |
|
| Short-term investment funds | 476 |
| | 211 |
| | 265 |
| | — |
| | — |
|
| Partnership interests | 157 |
| | — |
| | — |
| | — |
| | 157 |
|
| Hedge funds | 232 |
| | — |
| | — |
| | — |
| | 232 |
|
| Real estate limited partnerships | 144 |
| | 17 |
| | — |
| | — |
| | 127 |
|
| U.S. government securities | 734 |
| | — |
| | 734 |
| | — |
| | — |
|
| Guaranteed investment contracts | 29 |
| | — |
| | — |
| | 29 |
| | — |
|
| Governments bonds – foreign | 32 |
| | — |
| | 32 |
| | — |
| | — |
|
| Cash | 17 |
| | 15 |
| | 2 |
| | — |
| | — |
|
| Net pending transactions and other investments | 32 |
| | 1 |
| | 6 |
| | — |
| | 25 |
|
Total assets(a) | $ | 8,655 |
| | $ | 1,929 |
| | $ | 5,388 |
| | $ | 38 |
| | $ | 1,300 |
|
| |
| (a) | Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana were allocated approximately 27 percent, 30 percent, 15 percent, 15 percent, 5 percent and 8 percent, respectively, of the Duke Energy Master Retirement Trust and Piedmont's Pension assets at December 31, 2016. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages. |
| |
| (b) | Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy. |
The following table sets forth, by levelprovides a reconciliation of the fair value hierarchy, our financialbeginning and ending balances of Duke Energy Master Retirement Trust qualified pension and other post-retirement assets that were accounted forand Piedmont Pension Assets at fair value on a recurring basis aswhere the determination of October 31, 2014 and 2013. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input toincludes significant unobservable inputs (Level 3). |
| | | | | | | |
| (in millions) | 2017 |
| | 2016 |
|
| Balance at January 1 | $ | 38 |
| | $ | 31 |
|
| Combination of Piedmont Pension Assets | — |
| | 9 |
|
| Sales | (2 | ) | | (2 | ) |
| Total gains (losses) and other, net | 1 |
| | — |
|
| Transfer of Level 3 assets to other classifications | (9 | ) | | — |
|
| Balance at December 31 | $ | 28 |
| | $ | 38 |
|
Other post-retirement assets
The following tables provide the fair value measurement requires judgmentamounts for VEBA trust assets. |
| | | | | | | |
| | December 31, 2017 |
| | Total Fair |
| | |
| (in millions) | Value |
| | Level 2 |
|
| Cash and cash equivalents | $ | 8 |
| | $ | 8 |
|
| Real estate | 1 |
| | 1 |
|
| Equity securities | 28 |
| | 28 |
|
| Debt securities | 21 |
| | 21 |
|
| Total assets | $ | 58 |
| | $ | 58 |
|
|
| | | | | | | |
| | December 31, 2016 |
| | Total Fair |
| | |
| (in millions) | Value |
| | Level 2 |
|
| Cash and cash equivalents | $ | 14 |
| | $ | 14 |
|
| Real estate | 1 |
| | 1 |
|
| Equity securities | 26 |
| | 26 |
|
| Debt securities | 25 |
| | 25 |
|
| Total assets | $ | 66 |
| | $ | 66 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
EMPLOYEE SAVINGS PLANS
Retirement Savings Plan
Duke Energy or its affiliates sponsor, and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2014 and 2013. We present our derivative positions at fair value on a gross basis and have only asset positions forSubsidiary Registrants participate in, employee savings plans that cover substantially all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contractsU.S. employees. Most employees participate in a liability position,matching contribution formula where Duke Energy provides a matching contribution generally equal to 100 percent of employee before-tax and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosuresRoth 401(k) contributions of up to 6 percent of eligible pay per pay period (5 percent for financial assets or liabilities for our derivativesPiedmont employees). Dividends on Duke Energy shares held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.
|
| | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2014 |
| | | | | | | | | | | |
| | | | | Significant | | | | Effects of | | |
| | | Quoted Prices | | Other | | Significant | | Netting and | | |
| | | in Active | | Observable | | Unobservable | | Cash Collateral | | Total |
| | | Markets | | Inputs | | Inputs | | Receivables/ | | Carrying |
| In thousands | | (Level 1) | | (Level 2) | | (Level 3) | | Payables | | Value |
| Assets: | | | | | | | | | | |
| Derivatives held for distribution operations | | $ | 4,898 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,898 |
|
| Debt and equity securities held as trading securities: | | | | | | | | | | |
| Money markets | | 469 |
| | — |
| | — |
| | — |
| | 469 |
|
| Mutual funds | | 3,472 |
| | — |
| | — |
| | — |
| | 3,472 |
|
| Total fair value assets | | $ | 8,839 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8,839 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements as of October 31, 2013 |
| | | | | | | | | | | |
| | | | | Significant | | | | Effects of | | |
| | | Quoted Prices | | Other | | Significant | | Netting and | | |
| | | in Active | | Observable | | Unobservable | | Cash Collateral | | Total |
| | | Markets | | Inputs | | Inputs | | Receivables/ | | Carrying |
| In thousands | | (Level 1) | | (Level 2) | | (Level 3) | | Payables | | Value |
| Assets: | | | | | | | | | | |
| Derivatives held for distribution operations | | $ | 1,834 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,834 |
|
| Debt and equity securities held as trading securities: | | | | | |
| | | | |
| Money markets | | 380 |
| | — |
| | — |
| | — |
| | 380 |
|
| Mutual funds | | 2,814 |
| | — |
| | — |
| | — |
| | 2,814 |
|
| Total fair value assets | | $ | 5,028 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5,028 |
|
Our regulated utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSCsavings plans are charged to retained earnings when declared and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 1 to the consolidated financial statements. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.
Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets”shares held in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds whichplans are highly liquid and are actively traded on the exchanges.
Our long-term debt is recorded at unamortized cost. In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
|
| | | | | | | | |
| | | Carrying | | |
| In thousands | | Amount * | | Fair Value |
| As of October 31, 2014 | | $ | 1,425,000 |
| | $ | 1,617,453 |
|
| As of October 31, 2013 | | 1,275,000 |
| | 1,409,892 |
|
* Excludes discount on issuance of notes of $570 and $143 as of October 31, 2014 and 2013, respectively.
Quantitative and Qualitative Disclosures
The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.
The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2014 and 2013.
|
| | | | | | | | |
| Fair Value of Derivative Instruments |
| | | | | |
| In thousands | | 2014 | | 2013 |
| Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards: |
| Asset Financial Instruments: | | | | |
| Current Assets - Gas purchase derivative assets (December 2014 - November 2015) | | $ | 4,898 |
| | |
| Current Assets - Gas purchase derivative assets (December 2013 - October 2014) | | | | $ | 1,834 |
|
We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to reduce gas cost volatility for our customers. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the consolidated financial statements and recognizedconsidered outstanding in the Consolidated Statementscalculation of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.
The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the twelve months ended October 31, 2014basic and 2013, absent the regulatory treatment under our approved PGA procedures.
|
| | | | | | | | | | | | | | | | | | |
| | | Amount of | | Amount of | | Location of Gain (Loss) |
| | | Gain (Loss) Recognized | | Gain (Loss) Deferred | | Recognized through |
| | | on Derivative Instruments | | Under PGA Procedures | | PGA Procedures |
| | | | | | | |
| | | Twelve Months Ended | | Twelve Months Ended | | |
| | | October 31 | | October 31 | | |
| In thousands | | 2014 | | 2013 | | 2014 | | 2013 | | |
| Gas purchase options | | $ | 6,162 |
| | $ | (6,303 | ) | | $ | 6,162 |
| | $ | (6,303 | ) | | Cost of Gas |
In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.
Credit and Counterparty Risk
We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.
We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $3.5 million, or approximately 5% of our gross trade accounts receivable at October 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of October 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.
Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.
Risk Management
Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.
We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management (ERM) program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.
8. Commitments and Contingent Liabilities
Leases
We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.
Operating lease payments for the years ended October 31, 2014, 2013 and 2012 are as follows.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
Operating lease payments (1) |
| $ | 4,701 |
| | $ | 4,729 |
| | $ | 3,712 |
|
(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
|
| | | |
| In thousands | |
| 2015 | $ | 4,600 |
|
| 2016 | 4,491 |
|
| 2017 | 4,297 |
|
| 2018 | 4,225 |
|
| 2019 | 4,137 |
|
| Thereafter | 27,359 |
|
| Total | $ | 49,109 |
|
Long-term contracts
We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to twenty-one years. The time periods for fixed payments under gas supply contracts are up to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”
diluted EPS.
As of October 31,January 1, 2014, future unconditional purchase obligations for the next five years ending October 31new and thereafterrehired non-union and certain unionized employees (excludes Piedmont employees until 2018 plan year, discussed below) who are as follows.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Pipeline | | Gas Supply | | Telecommunications | | | | |
| | | Storage | | Reservation | | and Information | | | | |
| In thousands | | Capacity | | Fees | | Technology | | Other | | Total |
| 2015 | | $ | 158,984 |
| | $ | 8,657 |
| | $ | 14,601 |
| | $ | 41,008 |
| | $ | 223,250 |
|
| 2016 | | 149,412 |
| | 137 |
| | 4,786 |
| | — |
| | 154,335 |
|
| 2017 | | 145,579 |
| | 135 |
| | 736 |
| | — |
| | 146,450 |
|
| 2018 | | 142,433 |
| | — |
| | 126 |
| | — |
| | 142,559 |
|
| 2019 | | 132,186 |
| | — |
| | 80 |
| | — |
| | 132,266 |
|
| Thereafter | | 627,602 |
| | — |
| | — |
| | — |
| | 627,602 |
|
| Total | | $ | 1,356,196 |
| | $ | 8,929 |
| | $ | 20,329 |
| | $ | 41,008 |
| | $ | 1,426,462 |
|
Legal
We have only routine litigationnot eligible to participate in the normal courseDuke Energy’s defined benefit plans, an additional employer contribution of business. We do not expect any4 percent of these routine litigation matterseligible pay per pay period, which is subject to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.
Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.8 million in letters of credit that were issued and outstanding at October 31, 2014. Additional information concerning letters of creditthree-year vesting schedule, is included in Note 5provided to the consolidated financial statements.
Surety Bonds
In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of October 31, 2014, we had open surety bonds with a total contingent obligation of $4.8 million.
Environmental Matters
Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded for manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).
In 1997, we entered into a settlement with a third-party with respect to nine MGP sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.
In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly-owned subsidiary of Progress Energy, Inc. (Progress), now a subsidiary of Duke Energy Corporation (Duke Energy), prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.
employee’s savings plan account.
The following table summarizes information regarding our environmental sites as of October 31, 2014.includes pretax employer matching contributions made by Duke Energy and expensed by the Subsidiary Registrants. |
| | | | | | | | | | | | |
| | | | | | | Costs | | Undiscounted |
| | | Site | | | | Incurred | | Environmental |
| In thousands | | Type | | Site Status | | to Date | | Liability * |
| Anderson, SC | | MGP | | Site Investigation Work Plan submitted to the South Carolina Department of Health and Environmental Control. | | $ | 7 |
| | $ | 890 |
|
| Hickory, NC | | MGP | | Remediation complete. Land use restrictions in progress. | | 1,494 |
| | 18 |
|
| Reidsville, NC | | MGP | | Remediation complete. Land use restrictions filed. | | 641 |
| | 199 |
|
| Huntersville, NC | | LNG | | Soil remediation complete. Quarterly and semi-annual groundwater sampling in progress. Lead-based paint remediation complete. | | 4,738 |
| | 81 |
|
| Charlotte, NC | | UST | | USTs removed. Tank closure process in progress with the North Carolina Department of Environment and Natural Resources. | | 32 |
| | 33 |
|
| Clemmons, NC | | UST | | Potential responsible party for propane tank | | — |
| | 38 |
|
| Totals | | | | | | $ | 6,912 |
| | $ | 1,259 |
|
| | | | | | | | | |
| * Estimated based on assumptions using actual costs incurred, the timing of future payments and inflation factors, among others. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont(a) |
|
| Years ended December 31, | | | | | | | | | | | | | | | |
| 2017 | $ | 179 |
| | $ | 61 |
| | $ | 53 |
| | $ | 37 |
| | $ | 16 |
| | $ | 3 |
| | $ | 9 |
| | $ | 7 |
|
| 2016 | 169 |
| | 57 |
| | 50 |
| | 35 |
| | 15 |
| | 3 |
| | 8 |
| | — |
|
| 2015 | 159 |
| | 54 |
| | 48 |
| | 34 |
| | 13 |
| | 3 |
| | 7 |
| | — |
|
We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline.
As of October 31, 2014, our regulatory assets for unamortized environmental costs in our three-state territory totaled $8 million. We received approval from the TRA to recover $2 | |
| (a) | Piedmont's pretax employer matching contributions were $1 million, $7 million and $7 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of $6.3 million of our deferred North Carolina environmental costs over a five-year period beginning January 2014. We received approval from the PSCSC to recover $.1 million of our deferred South Carolina environmental costs over a one-year period beginning November 2014, pursuant to the annual rate stabilization order issued in October 2014.
Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.
9. Employee Benefit Plans
Under accounting guidance, we are required to recognize all obligations related to defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability. Our plans’ assets are required to be accounted for at fair value.
Pension Benefits
We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.
The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.
Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:
Achieve full funding over the longer term, and
Control year-to-year fluctuations in pension expense that is created by asset and liability volatility.
We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.
The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield debt, asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus 10% of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.
Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the two months ended December 31, 2016 and for the years ended October 31, 2016 and 2015, respectively.
|
Money Purchase Pension (MPP)Plan
Piedmont sponsors the MPP plan, which is a defined contribution pension plan that allows the employeeemployees to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, wePiedmont annually depositdeposits a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4%4 percent of the participant’s eligible compensation plus an additional 4%4 percent of eligible compensation above the social securitySocial Security wage base up to the Internal Revenue Service (IRS)IRS compensation limit. The participant is vested in thisMPP plan after three years of service. DuringNo contributions were made to the yearMPP plan during the two months ended OctoberDecember 31, 2014, we2016. Piedmont contributed $.9$2 million to the MPP plan.plan during each of the years ended December 31, 2017, October 31, 2016 and 2015. Effective December 31, 2017, the MPP Plan was merged into the Retirement Savings Plan and the money purchase plan formula was discontinued. Beginning with the 2018 plan year, the former MPP Plan participants are eligible to receive the additional employer contribution under the Retirement Savings Plan, discussed above.
22. INCOME TAXES
Tax Act
On December 22, 2017, President Trump signed the Tax Act into law. Among other provisions, the Tax Act lowers the corporate federal income tax rate from 35 percent to 21 percent and eliminates bonus depreciation for regulated utilities, effective January 1, 2018. The Tax Act also could be amended or subject to technical correction, which could change the financial impacts that were recorded at December 31, 2017, or are expected to be recorded in future periods. The FERC and state utility commissions will determine the regulatory treatment of the impacts of the Tax Act for the Subsidiary Registrants. The Duke Energy Registrants’ future results of operations, financial condition and cash flows could be adversely impacted by the Tax Act, subsequent amendments or corrections or the actions of the FERC, state utility commissions or credit rating agencies related to the Tax Act. Duke Energy is reviewing orders to address the rate treatment of the Tax Act by each state utility commission in which the Subsidiary Registrants operate. See Note 4 for additional information. Beginning in January 2018, the Subsidiary Registrants will defer the estimated ongoing impacts of the Tax Act that are expected to be returned to customers.
As a result of the Tax Act, Duke Energy revalued its existing deferred tax assets and deferred tax liabilities as of December 31, 2017, to account for the estimated future impact of lower corporate tax rates on these deferred tax amounts. For Duke Energy's regulated operations, where the reduction in the net accumulated deferred income tax (ADIT) liability is expected to be returned to customers in future rates, the net remeasurement has been deferred as a regulatory liability. The regulatory liability for income taxes includes the effect of the reduction of the net deferred tax liability including the tax gross-up of the excess accumulated deferred tax liabilities and the effect of the new tax rate on the previous regulatory asset for income taxes. Excess accumulated deferred income taxes are generally classified as either “protected” or “unprotected” under IRS rules. Protected excess ADIT, resulting from accumulated tax depreciation of public utility property, are required to utilize the average rate assumption method under the IRS normalization rules for determining the timing of the return to customers. The majority of the excess ADIT is related to protected amounts associated with public utility property. See Note 4 for additional information on the Tax Act's impact to the regulatory asset and liability accounts.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
We provideOn December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which provides guidance on accounting for the Tax Act’s impact. SAB 118 provides a measurement period, which in no case should extend beyond one year from the Tax Act enactment date, during which a company acting in good faith may complete the accounting for the impacts of the Tax Act under ASC Topic 740. In accordance with SAB 118, a company must reflect the income tax effects of the Tax Act in the reporting period in which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain postretirement health careincome tax effects of the Tax Act is incomplete, a company can determine a reasonable estimate for those effects and life insurance benefitsrecord a provisional estimate in the financial statements in the first reporting period in which a reasonable estimate can be determined.
Duke Energy recorded a provisional net tax benefit of $112 million related to eligible retirees.the Tax Act in the period ending December 31, 2017. This net benefit primarily consists of a net benefit of $534 million due to the remeasurement of deferred tax accounts to reflect the corporate rate reduction impact to net deferred tax balances, a net expense for the establishment of a valuation allowance related to foreign tax credits of $406 million and a transition tax on previously untaxed earnings and profits on foreign subsidiaries of $10 million. The liabilitymajority of Duke Energy’s operations are regulated and it is expected that the Subsidiary Registrants will ultimately pass on the savings associated with such benefitsthe amount representing the remeasurement of deferred tax balances related to regulated operations to customers. Duke Energy recorded a regulatory liability of $8,313 million, representing the revaluation of those deferred tax balances. The Subsidiary Registrants continue to respond to requests from regulators in various jurisdictions to determine the timing and magnitude of savings they will pass on to customers.
The net provisional charge from deferred tax remeasurement and assessment of valuation allowance is funded in irrevocable trust funds that can only be usedbased on currently available information and interpretations which are continuing to pay the benefits. Employees are first eligibleevolve. Duke Energy continues to retireanalyze additional information and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired priorguidance related to 1993 are in a “grandfathered” group for whom we pay the full costcertain aspects of the retiree’s coverage. Retirees notTax Act, such as limitations on the deductibility of interest and executive compensation, conformity or decoupling by state legislatures in response to the Tax Act, and the final determination of the net deferred tax liabilities subject to the remeasurement. The prospects of supplemental legislation or regulatory processes to address questions that arise because of the Tax Act, or evolving technical interpretations of the tax law, may also cause the final impact from the Tax Act to differ from the estimated amounts. Duke Energy continues to appropriately refine such amounts within the measurement period allowed by SAB 118, which will be completed no later than the fourth quarter of 2018.
Income Tax Expense
Components of Income Tax Expense |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Current income taxes | | | | | | | | |
| Federal | $ | (247 | ) | $ | 221 |
| $ | (436 | ) | $ | (95 | ) | $ | (188 | ) | $ | (37 | ) | $ | 128 |
| $ | (90 | ) |
| State | 4 |
| 20 |
| (5 | ) | 2 |
| (11 | ) | 2 |
| 21 |
| (3 | ) |
| Foreign | 3 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Total current income taxes | (240 | ) | 241 |
| (441 | ) | (93 | ) | (199 | ) | (35 | ) | 149 |
| (93 | ) |
| Deferred income taxes | | | | | | | | |
| Federal | 1,344 |
| 381 |
| 664 |
| 378 |
| 194 |
| 99 |
| 138 |
| 147 |
|
| State | 102 |
| 35 |
| 44 |
| 10 |
| 51 |
| (4 | ) | 14 |
| 8 |
|
Total deferred income taxes(a) (b) | 1,446 |
| 416 |
| 708 |
| 388 |
| 245 |
| 95 |
| 152 |
| 155 |
|
| Investment tax credit amortization | (10 | ) | (5 | ) | (3 | ) | (3 | ) | — |
| (1 | ) | — |
| — |
|
| Income tax expense from continuing operations | 1,196 |
| 652 |
| 264 |
| 292 |
| 46 |
| 59 |
| 301 |
| 62 |
|
| Tax benefit from discontinued operations | (6 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Total income tax expense included in Consolidated Statements of Operations | $ | 1,190 |
| $ | 652 |
| $ | 264 |
| $ | 292 |
| $ | 46 |
| $ | 59 |
| $ | 301 |
| $ | 62 |
|
| |
| (a) | Includes utilization of NOL (Net operating loss) carryforwards and tax credit carryforwards of $428 million at Duke Energy, $74 million at Progress Energy, $36 million at Duke Energy Florida, $17 million at Duke Energy Ohio, $42 million at Duke Energy Indiana and $79 million at Piedmont. In addition the total deferred income taxes Includes benefits of NOL carryforwards and tax credit carryforwards of $10 million at Duke Energy Carolinas and $1 million at Duke Energy Progress. |
| |
| (b) | As a result of the Tax Act, Duke Energy's deferred tax assets and liabilities were revalued as of December 31, 2017. See the Statutory Rate Reconciliation section below for additional information on the Tax Act's impact on income tax expense. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
| (in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Current income taxes | | | | | | | |
| Federal | $ | — |
| $ | 139 |
| $ | 15 |
| $ | (59 | ) | $ | 76 |
| $ | (7 | ) | $ | 7 |
|
| State | (15 | ) | 25 |
| (19 | ) | (25 | ) | 22 |
| (13 | ) | 6 |
|
| Foreign | 2 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Total current income taxes | (13 | ) | 164 |
| (4 | ) | (84 | ) | 98 |
| (20 | ) | 13 |
|
| Deferred income taxes | | | | | | | |
| Federal | 1,064 |
| 430 |
| 486 |
| 350 |
| 199 |
| 88 |
| 202 |
|
| State | 117 |
| 45 |
| 50 |
| 40 |
| 25 |
| 11 |
| 11 |
|
Total deferred income taxes(a) | 1,181 |
| 475 |
| 536 |
| 390 |
| 224 |
| 99 |
| 213 |
|
| Investment tax credit amortization | (12 | ) | (5 | ) | (5 | ) | (5 | ) | — |
| (1 | ) | (1 | ) |
| Income tax expense from continuing operations | 1,156 |
| 634 |
| 527 |
| 301 |
| 322 |
| 78 |
| 225 |
|
| Tax (benefit) expense from discontinued operations | (30 | ) | — |
| 1 |
| — |
| — |
| (36 | ) | — |
|
| Total income tax expense included in Consolidated Statements of Operations | $ | 1,126 |
| $ | 634 |
| $ | 528 |
| $ | 301 |
| $ | 322 |
| $ | 42 |
| $ | 225 |
|
| |
| (a) | Includes benefits of NOL carryforwards and utilization of NOL and tax credit carryforwards of $648 million at Duke Energy, $4 million at Duke Energy Carolinas, $190 million at Progress Energy, $60 million at Duke Energy Progress, $49 million at Duke Energy Florida, $26 million at Duke Energy Ohio and $58 million at Duke Energy Indiana. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Current income taxes | | | | | | | |
| Federal | $ | — |
| $ | 216 |
| $ | (193 | ) | $ | (56 | ) | $ | 1 |
| $ | (18 | ) | $ | (86 | ) |
| State | (12 | ) | 14 |
| 1 |
| (4 | ) | (7 | ) | (1 | ) | (12 | ) |
| Foreign | 4 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Total current income taxes | (8 | ) | 230 |
| (192 | ) | (60 | ) | (6 | ) | (19 | ) | (98 | ) |
| Deferred income taxes | | | | | | | |
| Federal | 1,097 |
| 345 |
| 694 |
| 334 |
| 290 |
| 96 |
| 245 |
|
| State | 181 |
| 57 |
| 27 |
| 27 |
| 58 |
| 5 |
| 17 |
|
Total deferred income taxes(a) | 1,278 |
| 402 |
| 721 |
| 361 |
| 348 |
| 101 |
| 262 |
|
| Investment tax credit amortization | (14 | ) | (5 | ) | (7 | ) | (7 | ) | — |
| (1 | ) | (1 | ) |
| Income tax expense from continuing operations | 1,256 |
| 627 |
| 522 |
| 294 |
| 342 |
| 81 |
| 163 |
|
| Tax expense (benefit) from discontinued operations | 89 |
| — |
| (1 | ) | — |
| — |
| 22 |
| — |
|
| Total income tax expense included in Consolidated Statements of Operations | $ | 1,345 |
| $ | 627 |
| $ | 521 |
| $ | 294 |
| $ | 342 |
| $ | 103 |
| $ | 163 |
|
| |
| (a) | Includes utilization of NOL carryforwards and tax credit carryforwards of $264 million at Duke Energy, $15 million at Duke Energy Carolinas, $119 million at Progress Energy, $21 million at Duke Energy Progress, $84 million at Duke Energy Florida, $3 million at Duke Energy Ohio and $45 million at Duke Energy Indiana. |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | |
| | Piedmont |
| | Two Months Ended |
| Years Ended October 31, |
(in millions) | December 31, 2016 | 2016 | 2015 |
| Current income taxes | | | |
| Federal | $ | 4 |
| $ | 27 |
| $ | (1 | ) |
| State | (2 | ) | 12 |
| 1 |
|
| Total current income taxes | 2 |
| 39 |
| — |
|
| Deferred income taxes | | | |
| Federal | 24 |
| 79 |
| 78 |
|
| State | 6 |
| 6 |
| 12 |
|
Total deferred income taxes(a)(b) | 30 |
| 85 |
| 90 |
|
| Total income tax expense from continuing operations included in Consolidated Statements of Operations | $ | 32 |
| $ | 124 |
| $ | 90 |
|
| |
| (a) | Includes benefits of NOL and tax carryforwards of $17 million and $91 million for the two months ended December 31, 2016, and the year ended October 31, 2016, respectively. |
| |
| (b) | Includes benefits and utilization of NOL carryforwards of $46 million for the year ended October 31, 2015. |
Duke Energy Income from Continuing Operations before Income Taxes |
| | | | | | | | | | | |
| | Years Ended December 31, |
| (in millions) | 2017 | | 2016 | | 2015 |
Domestic(a) | $ | 4,207 |
| | $ | 3,689 |
| | $ | 3,831 |
|
| Foreign | 59 |
| | 45 |
| | 79 |
|
| Income from continuing operations before income taxes | $ | 4,266 |
| | $ | 3,734 |
| | $ | 3,910 |
|
| |
| (a) | Includes a $16 million expense in 2017 related to the Tax Act impact on equity earnings included within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations. |
Taxes on Foreign Earnings
In February 2016, Duke Energy announced it had initiated a process to divest the International Disposal Group and, accordingly, no longer intended to indefinitely reinvest post-2014 undistributed foreign earnings. This change in the grandfathered group have a portioncompany's intent, combined with the extension of bonus depreciation by Congress in late 2015, allowed Duke Energy to more efficiently utilize foreign tax credits and reduce U.S. deferred tax liabilities associated with the historical unremitted foreign earnings by approximately $95 million during the year ended December 31, 2016.
Due to the classification of the costInternational Disposal Group as discontinued operations beginning in the fourth quarter of retiree coverage paid by us, subject2016, income tax amounts related to the International Disposal Group's foreign earnings are presented within (Loss) Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations. In December 2016, Duke Energy closed on the sale of the International Disposal Group in two separate transactions to execute the divestiture. See Note 2 for additional information on the sale.
Statutory Rate Reconciliation
The following tables present a reconciliation of income tax expense at the U.S. federal statutory tax rate to the actual tax expense from continuing operations. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Income tax expense, computed at the statutory rate of 35 percent | $ | 1,493 |
| $ | 653 |
| $ | 536 |
| $ | 353 |
| $ | 265 |
| $ | 88 |
| $ | 229 |
| $ | 70 |
|
| State income tax, net of federal income tax effect | 69 |
| 36 |
| 25 |
| 8 |
| 26 |
| (1 | ) | 23 |
| 3 |
|
| AFUDC equity income | (81 | ) | (37 | ) | (32 | ) | (17 | ) | (16 | ) | (4 | ) | (8 | ) | — |
|
| Renewable energy production tax credits | (132 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Tax Act(a) | (112 | ) | 15 |
| (246 | ) | (40 | ) | (226 | ) | (23 | ) | 55 |
| (12 | ) |
| Tax true-up | (52 | ) | (24 | ) | (19 | ) | (13 | ) | (7 | ) | (5 | ) | (6 | ) | — |
|
| Other items, net | 11 |
| 9 |
| — |
| 1 |
| 4 |
| 4 |
| 8 |
| 1 |
|
| Income tax expense from continuing operations | $ | 1,196 |
| $ | 652 |
| $ | 264 |
| $ | 292 |
| $ | 46 |
| $ | 59 |
| $ | 301 |
| $ | 62 |
|
| Effective tax rate | 28.0 | % | 34.9 | % | 17.2 | % | 29.0 | % | 6.1 | % | 23.4 | % | 46.0 | % | 30.8 | % |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | Amounts primarily include but are not limited to items that are excluded for ratemaking purposes related to abandoned or impaired assets, certain wholesale fixed rate contracts, remeasurement of nonregulated net deferred tax liabilities, Federal net operating losses, and valuation allowance on foreign tax credits. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Income tax expense, computed at the statutory rate of 35 percent | $ | 1,307 |
| $ | 630 |
| $ | 548 |
| $ | 315 |
| $ | 306 |
| $ | 95 |
| $ | 212 |
|
| State income tax, net of federal income tax effect | 64 |
| 46 |
| 20 |
| 10 |
| 30 |
| (2 | ) | 11 |
|
| AFUDC equity income | (70 | ) | (36 | ) | (26 | ) | (17 | ) | (9 | ) | (2 | ) | (6 | ) |
| Renewable energy production tax credits | (97 | ) | — |
| — |
| — |
| — |
| — |
| — |
|
| Audit adjustment | 5 |
| 3 |
| — |
| — |
| — |
| — |
| — |
|
| Tax true-up | (14 | ) | (14 | ) | (11 | ) | (3 | ) | (9 | ) | (16 | ) | 2 |
|
| Other items, net | (39 | ) | 5 |
| (4 | ) | (4 | ) | 4 |
| 3 |
| 6 |
|
| Income tax expense from continuing operations | $ | 1,156 |
| $ | 634 |
| $ | 527 |
| $ | 301 |
| $ | 322 |
| $ | 78 |
| $ | 225 |
|
| Effective tax rate | 31.0 | % | 35.2 | % | 33.7 | % | 33.4 | % | 36.9 | % | 28.9 | % | 37.1 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Income tax expense, computed at the statutory rate of 35 percent | $ | 1,369 |
| $ | 598 |
| $ | 555 |
| $ | 302 |
| $ | 330 |
| $ | 81 |
| $ | 168 |
|
| State income tax, net of federal income tax effect | 109 |
| 46 |
| 18 |
| 15 |
| 33 |
| 2 |
| 2 |
|
| AFUDC equity income | (58 | ) | (34 | ) | (19 | ) | (17 | ) | (3 | ) | (1 | ) | (4 | ) |
| Renewable energy production tax credits | (72 | ) | — |
| (1 | ) | — |
| — |
| — |
| — |
|
| Audit adjustment | (22 | ) | — |
| (23 | ) | 1 |
| (24 | ) | — |
| — |
|
| Tax true-up | 2 |
| 2 |
| (3 | ) | (4 | ) | 2 |
| (5 | ) | (9 | ) |
| Other items, net | (72 | ) | 15 |
| (5 | ) | (3 | ) | 4 |
| 4 |
| 6 |
|
| Income tax expense from continuing operations | $ | 1,256 |
| $ | 627 |
| $ | 522 |
| $ | 294 |
| $ | 342 |
| $ | 81 |
| $ | 163 |
|
| Effective tax rate | 32.1 | % | 36.7 | % | 32.9 | % | 34.2 | % | 36.3 | % | 35.2 | % | 34.0 | % |
|
| | | | | | | | | |
| | Piedmont |
| | Two Months Ended |
| Years Ended October 31, |
(in millions) | December 31, 2016 | 2016 | 2015 |
| Income tax expense, computed at the statutory rate of 35 percent | $ | 30 |
| $ | 111 |
| $ | 79 |
|
| State income tax, net of federal income tax effect | 1 |
| 11 |
| 9 |
|
| Other items, net | 1 |
| 2 |
| 2 |
|
| Income tax expense from continuing operations | $ | 32 |
| $ | 124 |
| $ | 90 |
|
| Effective tax rate | 37.2 | % | 39.1 | % | 39.7 | % |
Valuation allowances have been established for certain annual contribution limits. Retirees are responsiblestate NOL carryforwards and state income tax credits that reduce deferred tax assets to an amount that will be realized on a more-likely-than-not basis. The net change in the total valuation allowance is included in the State income tax, net of federal income tax effect in the above tables.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
DEFERRED TAXES
Net Deferred Income Tax Liability Components |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Deferred credits and other liabilities | $ | 143 |
| $ | 33 |
| $ | 78 |
| $ | 23 |
| $ | 49 |
| $ | 11 |
| $ | 6 |
| $ | (5 | ) |
| Capital lease obligations | 49 |
| 14 |
| — |
| — |
| — |
| — |
| 2 |
| — |
|
| Pension, post-retirement and other employee benefits | 295 |
| (17 | ) | 111 |
| 44 |
| 60 |
| 14 |
| 18 |
| (4 | ) |
Progress Energy merger purchase accounting adjustments(a) | 536 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Tax credits and NOL carryforwards | 4,527 |
| 234 |
| 402 |
| 156 |
| 143 |
| 25 |
| 216 |
| 70 |
|
| Regulatory liabilities and deferred credits | — |
| 222 |
| — |
| — |
| — |
| 65 |
| — |
| 61 |
|
| Investments and other assets | — |
| — |
| — |
| — |
| — |
| — |
| 1 |
| 18 |
|
| Other | 73 |
| 10 |
| 1 |
| 4 |
| — |
| — |
| — |
| — |
|
| Valuation allowance | (519 | ) | — |
| (14 | ) | — |
| — |
| — |
| — |
| — |
|
| Total deferred income tax assets | 5,104 |
| 496 |
| 578 |
| 227 |
| 252 |
| 115 |
| 243 |
| 140 |
|
| Investments and other assets | (1,419 | ) | (849 | ) | (470 | ) | (289 | ) | (187 | ) | — |
| (14 | ) | — |
|
| Accelerated depreciation rates | (9,216 | ) | (3,060 | ) | (2,803 | ) | (1,583 | ) | (1,257 | ) | (896 | ) | (966 | ) | (697 | ) |
| Regulatory assets and deferred debits, net | (1,090 | ) | — |
| (807 | ) | (238 | ) | (569 | ) | — |
| (188 | ) | — |
|
| Other | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (7 | ) |
| Total deferred income tax liabilities | (11,725 | ) | (3,909 | ) | (4,080 | ) | (2,110 | ) | (2,013 | ) | (896 | ) | (1,168 | ) | (704 | ) |
| Net deferred income tax liabilities | $ | (6,621 | ) | $ | (3,413 | ) | $ | (3,502 | ) | $ | (1,883 | ) | $ | (1,761 | ) | $ | (781 | ) | $ | (925 | ) | $ | (564 | ) |
| |
| (a) | Primarily related to capital lease obligations and debt fair value adjustments. |
As noted above, as a result of the Tax Act, Duke Energy revalued its existing deferred tax assets and liabilities as of December 31, 2017, to account for the full costestimated future impact of dependent coverage. Effectivelower corporate tax rates on these deferred amounts. The following table shows the decrease reflected in the net deferred income tax liabilities balance above: |
| | | |
| (in millions) | December 31, 2017 |
| Duke Energy | $ | 8,982 |
|
| Duke Energy Carolinas | 3,454 |
|
| Progress Energy | 3,282 |
|
| Duke Energy Progress | 1,882 |
|
| Duke Energy Florida | 1,420 |
|
| Duke Energy Ohio | 771 |
|
| Duke Energy Indiana | 1,053 |
|
| Piedmont | 521 |
|
The following table presents the expiration of tax credits and NOL carryforwards. |
| | | | | | | | | |
| | December 31, 2017 |
(in millions) | Amount |
| | Expiration Year |
| Investment tax credits | $ | 1,406 |
| | 2024 | | — | | 2037 |
| Alternative minimum tax credits | 1,147 |
| | Refundable by 2021 |
| Federal NOL carryforwards | 393 |
| | 2022 | | — | | 2036 |
State NOL carryforwards and credits(a) | 296 |
| | 2018 | | — | | 2037 |
Foreign NOL carryforwards(b) | 13 |
| | 2027 | | — | | 2036 |
Foreign Tax Credits(c) | 1,272 |
| | 2024 | | — | | 2027 |
| Total tax credits and NOL carryforwards | 4,527 |
| | | | | | |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
| |
| (a) | A valuation allowance of $90 million has been recorded on the state NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table. |
| |
| (b) | A valuation allowance of $13 million has been recorded on the foreign NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table. |
| |
| (c) | A valuation allowance of $416 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Deferred credits and other liabilities | $ | 382 |
| $ | 66 |
| $ | 126 |
| $ | 40 |
| $ | 93 |
| $ | 21 |
| $ | 4 |
| $ | 71 |
|
| Capital lease obligations | 60 |
| 8 |
| — |
| — |
| — |
| — |
| 1 |
| — |
|
| Pension, post-retirement and other employee benefits | 561 |
| 16 |
| 199 |
| 91 |
| 96 |
| 22 |
| 37 |
| 10 |
|
Progress Energy merger purchase accounting adjustments(a) | 918 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Tax credits and NOL carryforwards | 4,682 |
| 192 |
| 1,165 |
| 222 |
| 232 |
| 49 |
| 278 |
| 192 |
|
| Investments and other assets | — |
| — |
| — |
| — |
| — |
| 3 |
| — |
| — |
|
| Other | 205 |
| 16 |
| 35 |
| 8 |
| — |
| 5 |
| 9 |
| 45 |
|
| Valuation allowance | (96 | ) | — |
| (12 | ) | — |
| — |
| — |
| — |
| (1 | ) |
| Total deferred income tax assets | 6,712 |
| 298 |
| 1,513 |
| 361 |
| 421 |
| 100 |
| 329 |
| 317 |
|
| Investments and other assets | (1,892 | ) | (1,149 | ) | (597 | ) | (313 | ) | (297 | ) | — |
| (21 | ) | (21 | ) |
| Accelerated depreciation rates | (14,872 | ) | (4,664 | ) | (4,490 | ) | (2,479 | ) | (2,038 | ) | (1,404 | ) | (1,938 | ) | (1,080 | ) |
| Regulatory assets and deferred debits, net | (4,103 | ) | (1,029 | ) | (1,672 | ) | (892 | ) | (780 | ) | (139 | ) | (270 | ) | (147 | ) |
| Total deferred income tax liabilities | (20,867 | ) | (6,842 | ) | (6,759 | ) | (3,684 | ) | (3,115 | ) | (1,543 | ) | (2,229 | ) | (1,248 | ) |
| Net deferred income tax liabilities | $ | (14,155 | ) | $ | (6,544 | ) | $ | (5,246 | ) | $ | (3,323 | ) | $ | (2,694 | ) | $ | (1,443 | ) | $ | (1,900 | ) | $ | (931 | ) |
| |
| (a) | Primarily related to capital lease obligations and debt fair value adjustments. |
On August 6, 2015, pursuant to N.C. Gen. Stat. 105-130.3C, the North Carolina Department of Revenue announced the North Carolina corporate income tax rate would be reduced from a statutory rate of 5.0 percent to 4.0 percent beginning January 1, 2008, new employees have2016. Duke Energy and Piedmont recorded net reductions of approximately $95 million and $18 million to complete ten yearstheir North Carolina deferred tax liabilities in the third quarter of service after age 502015. The significant majority of these deferred tax liability reductions were offset by recording a regulatory liability pending NCUC determination of the disposition of amounts related to be eligible for benefits,Duke Energy Carolinas, Duke Energy Progress and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000.Piedmont. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.
OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We doimpact did not have a concentrationsignificant impact on the financial position, results of assetsoperation, or cash flows of Duke Energy, Duke Energy Carolinas, Progress Energy or Duke Energy Progress.
On August 4, 2016, pursuant to N.C. Gen. Stat. 105-130.3C, the North Carolina Department of Revenue announced the North Carolina corporate income tax rate would be reduced from a statutory rate of 4.0 percent to 3.0 percent beginning January 1, 2017. Duke Energy and Piedmont recorded net reductions of approximately $80 million and $16 million to their North Carolina deferred tax liabilities in the third quarter of 2016. The significant majority of this deferred tax liability reduction was offset by recording a single entity, industry, country, commodity or classregulatory liability pending NCUC determination of investment fund.
Supplemental Executive Retirement Plans
We have pension liabilitiesthe disposition of amounts related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directorsDuke Energy Carolinas, Duke Energy Progress and Piedmont. The impact did not have a significant impact on the financial position, results of operation, or surviving spouses. There are no assetscash flows of Duke Energy, Duke Energy Carolinas, Progress Energy or Duke Energy Progress.
On June 28, 2017, the North Carolina General Assembly amended N.C. Gen. Stat. 105-130.3, reducing the North Carolina corporate income tax rate from a statutory rate of 3.0 percent to 2.5 percent beginning January 1, 2019. Duke Energy recorded a net reduction of approximately $55 million to their North Carolina deferred tax liabilities in the second quarter of 2017. The significant majority of this deferred tax liability reduction was offset by recording a regulatory liability pending NCUC determination of the disposition of amounts related to these SERPs,Duke Energy Carolinas, Duke Energy Progress and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.
WePiedmont. The impact did not have a non-qualified defined contribution restoration plan (DCR plan) for all officers atsignificant impact on the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute 13%financial position, results of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption of the plan on January 1, 2009, of annual company contributions, and prospective five-year cliff vesting for the one-time opening balances of four Vice Presidents to compensate them for the loss of future benefits under this DCR plan as compared with a terminated SERP.
Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of serviceoperation or death of the participant.
We have a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we make no contributions to this plan. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded monthly through a rabbi trust with a bank as the trustee. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.
The funding to the DCR plan accounts for the years ended October 31, 2014 and 2013, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2014 and 2013 are presented below.
|
| | | | | | | | |
| In thousands | | 2014 | | 2013 |
| Funding | | $ | 524 |
| | $ | 434 |
|
| Liability: | | | | |
| Current | | 214 |
| | 199 |
|
| Noncurrent | | 4,248 |
| | 3,328 |
|
We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Term life policies of certain officers at the vice president level and above | | $ | 30 |
| | $ | 27 |
| | $ | 43 |
|
| Officers and director-level employees | | 32 |
| | 28 |
| | 25 |
|
Actuarial Plan Information
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2014 and 2013, and a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2014 and 2013 are presented below.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| In thousands | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 |
| Accumulated benefit obligation at year end | | $ | 252,706 |
| | $ | 230,175 |
| | $ | 5,925 |
| | $ | 4,736 |
| | N/A |
| | N/A |
|
| | | | | | | | | | | | | |
| Change in projected benefit obligation: | |
| | | |
| | | |
| | |
| Obligation at beginning of year | | $ | 272,403 |
| | $ | 293,327 |
| | $ | 4,736 |
| | $ | 5,569 |
| | $ | 33,678 |
| | $ | 34,830 |
|
| Service cost | | 10,865 |
| | 12,005 |
| | — |
| | — |
| | 1,109 |
| | 1,327 |
|
| Interest cost | | 11,781 |
| | 9,946 |
| | 200 |
| | 157 |
| | 1,448 |
| | 1,130 |
|
| Plan amendments | | — |
| | — |
| | 485 |
| | — |
| | — |
| | — |
|
| Actuarial (gain) loss | | 23,646 |
| | (24,859 | ) | | 956 |
| | (540 | ) | | 3,734 |
| | (1,094 | ) |
| Participant contributions | | — |
| | — |
| | — |
| | — |
| | 805 |
| | 641 |
|
| Administrative expenses | | (465 | ) | | (534 | ) | | — |
| | — |
| | — |
| | — |
|
| Benefit payments | | (15,544 | ) | | (17,482 | ) | | (452 | ) | | (450 | ) | | (2,957 | ) | | (3,156 | ) |
| Obligation at end of year | | 302,686 |
| | 272,403 |
| | 5,925 |
| | 4,736 |
| | 37,817 |
| | 33,678 |
|
| Change in fair value of plan assets: | |
| | | |
| | | |
| | |
| Fair value at beginning of year | | 300,661 |
| | 272,337 |
| | — |
| | — |
| | 25,961 |
| | 23,663 |
|
| Actual return on plan assets | | 31,791 |
| | 26,340 |
| | — |
| | — |
| | 1,874 |
| | 2,848 |
|
| Employer contributions | | 20,000 |
| | 20,000 |
| | 452 |
| | 450 |
| | 2,064 |
| | 1,965 |
|
| Participant contributions | | — |
| | — |
| | — |
| | — |
| | 805 |
| | 641 |
|
| Administrative expenses | | (465 | ) | | (534 | ) | | — |
| | — |
| | — |
| | — |
|
| Benefit payments | | (15,544 | ) | | (17,482 | ) | | (452 | ) | | (450 | ) | | (2,957 | ) | | (3,156 | ) |
| Fair value at end of year | | 336,443 |
| | 300,661 |
| | — |
| | — |
| | 27,747 |
| | 25,961 |
|
| Funded status at year end - over (under) | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
| | | | | | | | | | | | | |
| Noncurrent assets | | $ | 33,757 |
| | $ | 28,258 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Current liabilities | | — |
| | — |
| | (521 | ) | | (445 | ) | | — |
| | — |
|
| Noncurrent liabilities | | — |
| | — |
| | (5,404 | ) | | (4,291 | ) | | (10,070 | ) | | (7,717 | ) |
| Net amount recognized | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
| | | | | | �� | | | | | | | |
| Amounts Not Yet Recognized as a Component | | | | | | | | | | | | |
| of Cost and Recognized in a Deferred | | | | | | | | | | | | |
| Regulatory Account: | | | | | | | | | | | | |
| Unrecognized transition obligation | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Unrecognized prior service credit (cost) | | 15,046 |
| | 17,243 |
| | (439 | ) | | (196 | ) | | — |
| | — |
|
| Unrecognized actuarial loss | | (103,038 | ) | | (96,338 | ) | | (1,745 | ) | | (820 | ) | | (3,995 | ) | | (354 | ) |
| Regulatory asset | | (87,992 | ) | | (79,095 | ) | | (2,184 | ) | | (1,016 | ) | | (3,995 | ) | | (354 | ) |
| Cumulative employer contributions in | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| excess of cost | | 121,749 |
| | 107,353 |
| | (3,741 | ) | | (3,720 | ) | | (6,075 | ) | | (7,363 | ) |
| Net amount recognized | | $ | 33,757 |
| | $ | 28,258 |
| | $ | (5,925 | ) | | $ | (4,736 | ) | | $ | (10,070 | ) | | $ | (7,717 | ) |
In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCIL as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.
Net periodic benefit cost for the years ended October 31, 2014, 2013 and 2012 includes the following components.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| In thousands | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 |
| Service cost | | $ | 10,865 |
| | $ | 12,005 |
| | $ | 9,573 |
| | $ | — |
| | $ | — |
| | $ | 39 |
| | $ | 1,109 |
| | $ | 1,327 |
| | $ | 1,387 |
|
| Interest cost | | 11,781 |
| | 9,946 |
| | 10,640 |
| | 200 |
| | 157 |
| | 203 |
| | 1,448 |
| | 1,130 |
| | 1,347 |
|
| Expected return on plan assets | | (22,530 | ) | | (21,105 | ) | | (20,289 | ) | | — |
| | — |
| | — |
| | (1,782 | ) | | (1,663 | ) | | (1,551 | ) |
| Amortization of transition obligation | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 667 |
| | 667 |
|
| Amortization of prior service cost | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| (credit) | | (2,198 | ) | | (2,198 | ) | | (2,198 | ) | | 243 |
| | 81 |
| | 81 |
| | — |
| | — |
| | — |
|
| Amortization of net loss | | 7,685 |
| | 11,202 |
| | 5,966 |
| | 31 |
| | 161 |
| | 49 |
| | — |
| | — |
| | — |
|
| Net periodic benefit cost | | 5,603 |
| | 9,850 |
| | 3,692 |
| | 474 |
| | 399 |
| | 372 |
| | 775 |
| | 1,461 |
| | 1,850 |
|
| Other changes in plan assets and benefit | |
| | | | | |
| | | | | |
| | | | |
| obligation recognized through | |
| | | | | |
| | | | | |
| | | | |
| regulatory asset or liability: | |
| | | | | |
| | | | | |
| | | | |
| Prior service cost | | — |
| | — |
| | — |
| | 485 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net loss (gain) | | 14,385 |
| | (30,094 | ) | | 43,945 |
| | 956 |
| | (540 | ) | | 629 |
| | 3,641 |
| | (2,278 | ) | | 2,209 |
|
| Amounts recognized as a component of | |
| | | | | |
| | | | | |
| | | | |
| net periodic benefit cost: | |
| | | | | |
| | | | | |
| | | | |
| Transition obligation | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (667 | ) | | (667 | ) |
| Amortization of net loss | | (7,685 | ) | | (11,202 | ) | | (5,966 | ) | | (31 | ) | | (161 | ) | | (49 | ) | | — |
| | — |
| | — |
|
| Prior service (cost) credit | | 2,198 |
| | 2,198 |
| | 2,198 |
| | (243 | ) | | (81 | ) | | (81 | ) | | — |
| | — |
| | — |
|
| Total recognized in regulatory asset | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| (liability) | | 8,898 |
| | (39,098 | ) | | 40,177 |
| | 1,167 |
| | (782 | ) | | 499 |
| | 3,641 |
| | (2,945 | ) | | 1,542 |
|
| Total recognized in net periodic benefit | |
|
| | | | | |
|
| | | | | |
|
| | | | |
| and regulatory asset (liability) | | $ | 14,501 |
| | $ | (29,248 | ) | | $ | 43,869 |
| | $ | 1,641 |
| | $ | (383 | ) | | $ | 871 |
| | $ | 4,416 |
| | $ | (1,484 | ) | | $ | 3,392 |
|
The 2015 estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
|
| | | | | | | | | | | | |
| | | Qualified | | Nonqualified | | Other |
| In thousands | | Pension | | Pension | | Benefits |
| Amortization of unrecognized prior service (credit) cost | | $ | (2,198 | ) | | $ | 231 |
| | $ | — |
|
| Amortization of unrecognized actuarial loss | | 8,121 |
| | 85 |
| | 29 |
|
The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and non-callable bonds rated AAof Duke Energy, Duke Energy Carolinas, Progress Energy or better by either Moody’s Investors Service’s or Standard & Poor’s Ratings Services that have a yield higher than the regression mean yield curve. The discount rate can vary from plan year to plan year. As of October 31, 2014, the benchmark by plan was as follows.Duke Energy Progress.
|
| | |
Pension plan | 4.13 | % |
NCNG SERP | 3.64 | % |
Directors’ SERP | 3.74 | % |
Piedmont SERP | 3.10 | % |
OPEB | 4.03 | % |
Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.
We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2014 and 2013 are presented below.
|
| | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension | | Other Benefits |
| | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 |
| Discount rate | | 4.13 | % | | 4.55 | % | | 3.69 | % | | 3.98 | % | | 4.03 | % | | 4.44 | % |
| Rate of compensation increase | | 3.68 | % | | 3.72 | % | | N/A |
| | N/A |
| | N/A |
| | N/A |
|
In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. As of October 31, 2014, we updated our assumed mortality rates to incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014.
The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2014, 2013 and 2012 are presented below.
|
| | | | | | | | | | | | | | | | | | |
| | | Qualified Pension | | Nonqualified Pension |
| | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 |
| Discount rate | | 4.55 | % | | 3.51 | % | | 4.67 | % | | 3.98 | % | | 2.95 | % | | 4.10 | % |
| Expected long-term rate of return on plan assets | | 7.75 | % | | 8.00 | % | | 8.00 | % | | N/A |
| | N/A |
| | N/A |
|
| Rate of compensation increase | | 3.72 | % | | 3.76 | % | | 3.78 | % | | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | | | | |
| | | Other Benefits | | |
| | | 2014 | | 2013 | | 2012 | |
| Discount rate | | 4.44 | % | | 3.34 | % | | 4.36 | % | |
| Expected long-term rate of return on plan assets | | 7.75 | % | | 8.00 | % | | 8.00 | % | |
| Rate of compensation increase | | N/A |
| | N/A |
| | N/A |
| |
We anticipate that we will contribute the following amounts to our plans in 2015.
|
| | | |
| In thousands | |
| Qualified pension plan * | $ | 10,000 |
|
| Nonqualified pension plans | 521 |
|
| MPP plan | 1,300 |
|
| OPEB plan | 1,500 |
|
* Funded in November 2014.
The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.
Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.
|
| | | | | | | | | | | | |
| | | Qualified | | Nonqualified | | Other |
| In thousands | | Pension | | Pension | | Benefits |
| 2015 | | $ | 29,946 |
| | $ | 521 |
| | $ | 2,409 |
|
| 2016 | | 16,794 |
| | 507 |
| | 2,449 |
|
| 2017 | | 16,332 |
| | 491 |
| | 2,527 |
|
| 2018 | | 19,197 |
| | 472 |
| | 2,606 |
|
| 2019 | | 20,685 |
| | 490 |
| | 2,682 |
|
| 2020 - 2024 | | 110,459 |
| | 2,149 |
| | 14,179 |
|
The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2014 and 2013 are presented below.
|
| | | | | | |
| | | 2014 | | 2013 |
| Health care cost trend rate assumed for next year | | 7.40 | % | | 7.40 | % |
| Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 5.00 | % | | 5.00 | % |
| Year that the rate reaches the ultimate trend rate | | 2027 |
| | 2027 |
|
The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.
|
| | | | | | | | |
| In thousands | | 1% Increase | | 1% Decrease |
| Effect on total of service and interest cost components of net periodic | | | | |
| postretirement health care benefit cost for the year ended October 31, 2014 | | $ | 31 |
| | $ | (32 | ) |
| Effect on the health care cost component of the accumulated postretirement | | | | |
| benefit obligation as of October 31, 2014 | | 829 |
| | (841 | ) |
Fair Value Measurements
Mutual funds are valued at the quoted NAV per share, which is computed as of the close of business on our balance sheet date. Mutual funds with a publicly quoted NAV per share are classified as Level 1; mutual funds with a NAV per share that is not publicly available are classified as Level 2.
Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.
Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets have been valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.
U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.
Long duration bonds – These are Level 2 assets in an actively managed private series long duration fixed income fund valued using pricing models that consider various observable inputs, such as benchmark yields, reported trades, broker quotes and issuer spreads.
Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.
High yield bonds – These are Level 1 assets valued at the quoted NAV of high yield fixed income mutual fund shares.
Derivatives – The Level 1 assets were valued using a compilation of observable market information on an active market. The Level 2 assets were valued using broker quotes on a non-active market.
Large cap core index – These are Level 1 assets valued at the quoted NAV of the low-cost equity index mutual fund that tracks the Standard & Poor’s 500 Stock Index (S&P 500 Index).
Large cap value and small cap value – These are Level 1 assets valued at the market price of the active market on which the individual security is traded.
Large cap growth and global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed equity funds.
Common trust funds – International growth and bank loans (and for 2013, international value) – These are Level 2 assets held in common trust funds in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently there are no restrictions on redemptions for the funds.
Hedge fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the underlying holdings in the portfolio at a NAV. These investments are across a variety of markets through investment funds or managed accounts that invest in equities, equity-related instruments, fixed income and other debt-related instruments. Currently there are no restrictions on redemptions for the fund.
Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is 3.5% but is still being funded through capital calls; $5.4 million of the original $12 million subscription remains unfunded. Until a 3.5% allocation can be achieved, the balance of the 3.5% allocation is invested in a low-cost equity index fund that tracks the S&P 500 Index. Our investment is in various funds that invests in North American companies; allocate capital to private equity funds; invest in venture capital partnerships; and private equity partnerships in emerging markets.
Commodities fund of funds – This is a Level 2 asset with the value of our investment based on the estimated fair value of the various holdings in the portfolio as reported in the financial statements at a NAV. Currently there are no restrictions on redemptions for the fund. These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers.
As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
|
| | | | | | |
| | | | | | | Redemptions |
| | Redemption | | | | Notice |
Investment | | Frequency | | Other Redemption Restrictions | | Period |
Common trust fund -
International growth
| | Monthly | | None | | 30 days |
| | | |
Hedge fund of funds | | Quarterly | | Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on “first in first out” basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2014. | | 65 days |
| | | |
Private equity fund of funds | | Limited | | Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval. | | (1) |
| | | |
Commodities fund of funds | | Monthly | | Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete. | | 35 days |
| | | | | | | |
Bank loans | | Daily | | None | | 30 days |
(1) The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next 10 to 12 years.250
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
UNRECOGNIZED TAX BENEFITS
The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2014 and 2013 are presented below. Our assessment of the significance of a particular inputfollowing tables present changes to the fair value measurement requires judgment
unrecognized tax benefits.
and may affect the valuation of fair value assets and their consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
| Unrecognized tax benefits – January 1 | $ | 17 |
| $ | 1 |
| $ | 2 |
| $ | 2 |
| $ | 4 |
| $ | 4 |
| $ | — |
| $ | — |
|
| Unrecognized tax benefits increases (decreases) | | | | | | | | |
| Gross increases – tax positions in prior periods | 12 |
| 4 |
| 3 |
| 3 |
| 1 |
| 1 |
| 1 |
| 3 |
|
| Gross decreases – tax positions in prior periods | (4 | ) | — |
| — |
| — |
| — |
| (4 | ) | — |
| — |
|
| Total changes | 8 |
| 4 |
| 3 |
| 3 |
| 1 |
| (3 | ) | 1 |
| 3 |
|
| Unrecognized tax benefits – December 31 | $ | 25 |
| $ | 5 |
| $ | 5 |
| $ | 5 |
| $ | 5 |
| $ | 1 |
| $ | 1 |
| $ | 3 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2014 |
| | | |
| Significant Other Observable Inputs(Level 2) |
|
|
|
|
|
|
| | | Quoted Prices In Active Markets (Level 1) |
|
| Significant Unobservable Inputs (Level 3) |
|
|
|
|
| | |
|
|
|
|
|
|
| | |
|
|
| Total Carrying Value |
| % of Total |
| In thousands | |
|
|
|
|
| Cash and cash equivalents | | $ | 27,932 |
| | $ | 435 |
| | $ | — |
| | $ | 28,367 |
| | 8 | % |
| Fixed Income Securities: | | | | | | | | | | 45 | % |
| U.S. treasuries | | — |
| | 27,224 |
| | — |
| | 27,224 |
| | 8 | % |
| Long duration bonds | | — |
| | 48,049 |
| | — |
| | 48,049 |
| | 14 | % |
| Corporate bonds | | — |
| | 49,816 |
| | — |
| | 49,816 |
| | 15 | % |
| High yield bonds | | 8,100 |
| | — |
| | — |
| | 8,100 |
| | 3 | % |
| Common trust fund - Bank loans | | — |
| | 16,187 |
| | — |
| | 16,187 |
| | 5 | % |
| Collateralized mortgage | | | | | | | | | | |
| obligations | | — |
| | 1,035 |
| | — |
| | 1,035 |
| | — | % |
| Derivatives | | 48 |
| | (49 | ) | | — |
| | (1 | ) | | — | % |
| Equity Securities: | | | | | | | | | | 31 | % |
| Large cap core index | | 9,982 |
| | — |
| | — |
| | 9,982 |
| | 3 | % |
| Large cap value | | 19,937 |
| | — |
| | — |
| | 19,937 |
| | 6 | % |
| Large cap growth | | 19,745 |
| | — |
| | — |
| | 19,745 |
| | 6 | % |
| Small cap value | | 31,329 |
| | — |
| | — |
| | 31,329 |
| | 9 | % |
| Common trust fund - International | | | | | | | | | | |
| growth | | — |
| | 22,877 |
| | — |
| | 22,877 |
| | 7 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 16,675 |
| | — |
| | — |
| | 16,675 |
| | 5 | % |
| Other Investments: | | | | | | | | | | 11 | % |
| Hedge fund of funds | | — |
| | 19,829 |
| | — |
| | 19,829 |
| | 6 | % |
| Private equity fund of funds | | — |
| | — |
| | 7,158 |
| | 7,158 |
| | 2 | % |
| Commodities fund of funds | | — |
| | 10,134 |
| | — |
| | 10,134 |
| | 3 | % |
| Total assets at fair value | | $ | 133,748 |
| | $ | 195,537 |
| | $ | 7,158 |
| | $ | 336,443 |
| | 100 | % |
| Percent of fair value hierarchy | | 40 | % | | 58 | % | | 2 | % | | 100 | % | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
|
| Unrecognized tax benefits – January 1 | $ | 88 |
| $ | 72 |
| $ | 1 |
| $ | 3 |
| $ | — |
| $ | — |
| $ | 1 |
|
| Unrecognized tax benefits increases (decreases) | | | | | | | |
| Gross increases – tax positions in prior periods | — |
| — |
| — |
| — |
| 4 |
| 4 |
| — |
|
| Gross decreases – tax positions in prior periods | (4 | ) | (4 | ) | (1 | ) | (1 | ) | — |
| — |
| — |
|
| Decreases due to settlements | (68 | ) | (67 | ) | — |
| — |
| — |
| — |
| (1 | ) |
| Reduction due to lapse of statute of limitations | 1 |
| — |
| 2 |
| — |
| — |
| — |
| — |
|
| Total changes | (71 | ) | (71 | ) | 1 |
| (1 | ) | 4 |
| 4 |
| (1 | ) |
| Unrecognized tax benefits – December 31 | $ | 17 |
| $ | 1 |
| $ | 2 |
| $ | 2 |
| $ | 4 |
| $ | 4 |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | Qualified Pension Plan as of October 31, 2013 |
| | | | | Significant Other Observable Inputs(Level 2) | | | | | | |
| | | Quoted Prices In Active Markets (Level 1) | | | Significant Unobservable Inputs (Level 3) | | | | |
| | | | | | | | |
| | | | | | Total Carrying Value | | % of Total |
| In thousands | | | | | |
| Cash and cash equivalents | | $ | 5,566 |
| | $ | 156 |
| | $ | — |
| | $ | 5,722 |
| | 2 | % |
| Fixed Income Securities: | | | | | | | | | | 38 | % |
| U.S. treasuries | | — |
| | 24,078 |
| | — |
| | 24,078 |
| | 8 | % |
| Long duration bonds | | — |
| | 34,041 |
| | — |
| | 34,041 |
| | 11 | % |
| Corporate bonds | | — |
| | 42,701 |
| | — |
| | 42,701 |
| | 14 | % |
| High yield bonds | | 14,680 |
| | — |
| | — |
| | 14,680 |
| | 5 | % |
| Collateralized mortgage | | | | | | | | | | |
| obligations | | — |
| | 1,098 |
| | — |
| | 1,098 |
| | — | % |
| Derivatives | | 6 |
| | (17 | ) | | — |
| | (11 | ) | | — | % |
| Equity Securities: | | | | | | | | | | 43 | % |
| Large cap core index | | 12,023 |
| | — |
| | — |
| | 12,023 |
| | 4 | % |
| Large cap value | | 16,908 |
| | — |
| | — |
| | 16,908 |
| | 6 | % |
| Large cap growth | | 17,823 |
| | — |
| | — |
| | 17,823 |
| | 6 | % |
| Small cap value | | 30,831 |
| | — |
| | — |
| | 30,831 |
| | 10 | % |
| Common trust fund - International | | | | | | | | | | |
| value | | — |
| | 24,460 |
| | — |
| | 24,460 |
| | 8 | % |
| Common trust fund - International | | | | | | | | | | |
| growth | | — |
| | 27,270 |
| | — |
| | 27,270 |
| | 9 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 15,042 |
| | — |
| | — |
| | 15,042 |
| | 5 | % |
| Other Investments: | | | | | | | | | | 12 | % |
| Hedge fund of funds | | — |
| | 18,571 |
| | — |
| | 18,571 |
| | 6 | % |
| Private equity fund of funds | | — |
| | — |
| | 4,659 |
| | 4,659 |
| | 2 | % |
| Commodities fund of funds | | — |
| | 10,765 |
| | — |
| | 10,765 |
| | 4 | % |
| Total assets at fair value | | $ | 112,879 |
| | $ | 183,123 |
| | $ | 4,659 |
| | $ | 300,661 |
| | 100 | % |
| Percent of fair value hierarchy | | 37 | % | | 61 | % | | 2 | % | | 100 | % | | |
The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy. |
| | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Indiana |
|
| Unrecognized tax benefits – January 1 | $ | 213 |
| $ | 160 |
| $ | 32 |
| $ | 23 |
| $ | 8 |
| $ | 1 |
|
| Unrecognized tax benefits increases (decreases) | | | | | | |
| Gross increases – tax positions in prior periods | — |
| — |
| 1 |
| 1 |
| — |
| — |
|
| Gross decreases – tax positions in prior periods | (48 | ) | (45 | ) | — |
| — |
| — |
| — |
|
| Decreases due to settlements | (45 | ) | (43 | ) | — |
| — |
| — |
| — |
|
| Reduction due to lapse of statute of limitations | (32 | ) | — |
| (32 | ) | (21 | ) | (8 | ) | — |
|
| Total changes | (125 | ) | (88 | ) | (31 | ) | (20 | ) | (8 | ) | — |
|
| Unrecognized tax benefits – December 31 | $ | 88 |
| $ | 72 |
| $ | 1 |
| $ | 3 |
| $ | — |
| $ | 1 |
|
|
| | | | |
| | | Private |
| | | Equity Fund |
| In thousands | | of Funds |
| Balance, October 31, 2012 | | $ | 3,522 |
|
| Actual return on plan assets: | | |
| Relating to assets still held at the reporting date | | 116 |
|
| Relating to assets sold during the period | | 61 |
|
| Purchases, sales and settlements (net) | | 960 |
|
| Transfer in/out of Level 3 | | — |
|
| Balance, October 31, 2013 | | 4,659 |
|
| Actual return on plan assets: | | |
| Relating to assets still held at the reporting date | | 1,031 |
|
| Relating to assets sold during the period | | 113 |
|
| Purchases, sales and settlements (net) | | 1,355 |
|
| Transfer in/out of Level 3 | | — |
|
| Balance, October 31, 2014 | | $ | 7,158 |
|
During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.
There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.
Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan with all of the OPEB plan’s assets invested in mutual funds.PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
Cash and cash equivalentsDUKE ENERGY PROGRESS, LLC – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
U.S. treasuriesCombined Notes To Consolidated Financial Statements – These are Level 1 assets in an actively managed mutual fund measured at NAV.(Continued)
Corporate bonds/Other fixed income securities – These are Level 1 assets valued at the quoted NAV of mutual fund investments that are primarily invested in investment grade securities that mature within ten years. The OPEB plan maintains a 5% target allocation to high yield fixed income.
Large cap value, large cap growth, small cap growth, small cap value – These are Level 1 assets valued at the quoted NAV as invested in mutual funds that invest by a specific style.
Large cap index – These are Level 1 assets valued at the NAV as invested in a low-cost equity index mutual fund that tracks the S&P 500 Index.
International blend – These are Level 1 assets valued at the quoted NAV of mutual fund shares in managed global equity funds outside of the United States whose styles include both growth and value investments.
Global REIT – These are Level 1 assets valued at the quoted NAV of mutual fund shares in a managed equity fund that invests globally but primarily in the United States.
The OPEB plan’s asset allocations by level withinfollowing table includes additional information regarding the fair value hierarchyDuke Energy Registrants' unrecognized tax benefits at OctoberDecember 31, 20142017. During the first quarter of 2018, Duke Energy recognized an approximate $8 million reduction and 2013Duke Energy Carolinas recognized an approximate $1 million reduction in unrecognized tax benefits. No additional material reductions are presented below. Our assessment ofexpected in the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1next 12 months. to the consolidated financial statements.
|
| | | | | | | | | | | | | | | | | | | |
| | | Other Benefits as of October 31, 2014 |
| | | |
| Significant Other Observable Inputs(Level 2) |
|
|
|
|
|
|
| | | Quoted Prices In Active Markets (Level 1) |
|
| Significant Unobservable Inputs (Level 3) |
|
|
|
|
| | |
|
|
|
|
|
|
| | |
|
|
| Total Carrying Value |
| % of Total |
| In thousands | |
|
|
|
|
| Cash and cash equivalents | | $ | 2,590 |
| | $ | — |
| | $ | — |
| | $ | 2,590 |
| | 9 | % |
| Fixed Income Securities: | | | | | | | | | | 44 | % |
| U.S. treasuries | | 2,013 |
| | — |
| | — |
| | 2,013 |
| | 7 | % |
| Corporate bonds / Other fixed income | | | | | | | | | | |
| securities | | 10,187 |
| | — |
| | — |
| | 10,187 |
| | 37 | % |
| Equity Securities: | | | | | | | | | | 42 | % |
| Large cap value | | 1,269 |
| | — |
| | — |
| | 1,269 |
| | 4 | % |
| Large cap growth | | 1,310 |
| | — |
| | — |
| | 1,310 |
| | 5 | % |
| Small cap value | | 1,336 |
| | — |
| | — |
| | 1,336 |
| | 5 | % |
| Small cap growth | | 1,319 |
| | — |
| | — |
| | 1,319 |
| | 5 | % |
| Large cap index | | 2,532 |
| | — |
| | — |
| | 2,532 |
| | 9 | % |
| International blend | | 3,846 |
| | — |
| | — |
| | 3,846 |
| | 14 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 1,345 |
| | — |
| | — |
| | 1,345 |
| | 5 | % |
| Total assets at fair value | | $ | 27,747 |
| | $ | — |
| | $ | — |
| | $ | 27,747 |
| | 100 | % |
| Percent of fair value hierarchy | | 100 | % | | — | % | | — | % | | 100 | % | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
| Duke |
| |
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
| Energy |
| |
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Ohio |
| Indiana |
| Piedmont |
|
Amount that if recognized, would affect the effective tax rate or regulatory liability(a) | $ | 15 |
| $ | 4 |
| $ | 7 |
| $ | 5 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 3 |
|
Amount that if recognized, would be recorded as a component of discontinued operations | 7 |
| — |
| — |
| — |
| — |
| 2 |
| — |
| — |
|
| |
| (a) | Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Indiana and Piedmont are unable to estimate the specific amounts that would affect the effective tax rate versus the regulatory liability. |
OTHER TAX MATTERS
|
| | | | | | | | | | | | | | | | | | | |
| | | Other Benefits as of October 31, 2013 |
| | | | | Significant Other Observable Inputs(Level 2) | | | | | | |
| | | Quoted Prices In Active Markets (Level 1) | | | Significant Unobservable Inputs (Level 3) | | | | |
| | | | | | | | |
| | | | | | Total Carrying Value | | % of Total |
| In thousands | | | | | |
| Cash and cash equivalents | | $ | 982 |
| | $ | — |
| | $ | — |
| | $ | 982 |
| | 4 | % |
| Fixed Income Securities: | | | | | | | | | | 46 | % |
| U.S. treasuries | | 2,582 |
| | — |
| | — |
| | 2,582 |
| | 10 | % |
| Corporate bonds / Other fixed income | | | | | | | | | | |
| securities | | 9,232 |
| | — |
| | — |
| | 9,232 |
| | 36 | % |
| Equity Securities: | | | | | | | | | | 45 | % |
| Large cap value | | 1,327 |
| | — |
| | — |
| | 1,327 |
| | 5 | % |
| Large cap growth | | 1,352 |
| | — |
| | — |
| | 1,352 |
| | 5 | % |
| Small cap value | | 1,331 |
| | — |
| | — |
| | 1,331 |
| | 5 | % |
| Small cap growth | | 1,313 |
| | — |
| | — |
| | 1,313 |
| | 5 | % |
| Large cap index | | 2,384 |
| | — |
| | — |
| | 2,384 |
| | 9 | % |
| International blend | | 4,206 |
| | — |
| | — |
| | 4,206 |
| | 16 | % |
| Real Estate: | | | | | | | | | | 5 | % |
| Global REIT | | 1,252 |
| | — |
| | — |
| | 1,252 |
| | 5 | % |
| Total assets at fair value | | $ | 25,961 |
| | $ | — |
| | $ | — |
| | $ | 25,961 |
| | 100 | % |
| Percent of fair value hierarchy | | 100 | % | | — | % | | — | % | | 100 | % | | |
401(k) Plan
We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.
Employees receive a company match of 100% up to the first 5% of eligible pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution and compensation limits. We automatically enroll all eligible non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2014, 2013 and 2012, we made matching contributions to participant accounts as follows.
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| 401(k) matching contributions | | $ | 6,134 |
| | $ | 5,688 |
| | $ | 5,400 |
|
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the Consolidated Statement of Stockholders’ Equity as an increase in retained earnings.
10. Employee Share-Based Plans
Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2014, 2013 and 2012, we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.
We have granted three series of awards under approved incentive compensation plans, each with a three-year performance period (ending October 31, 2014, October 31, 2015 and October 31, 2016). For each of these performance periods, awards will be based on achievement relative to a target annual compounded increase in basic EPS and the achievement of total shareholder returns relative to a group of peer companies that are domiciled in the United States, publicly traded in the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours, with each measure being weighted at 50%. The plans with performance periods ending October 31, 2015 (2015 plan) and October 31, 2016 (2016 plan) have an additional performance measure of actual average return on equity compared to the weighted average return on equity allowed by our regulatory commissions. The weighting of the units awarded under the 2015 plan and the 2016 plan is based on EPS at 37.5%, total shareholder return at 37.5% and return on equity at 25% of the total units awarded.
In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award vested for participants who met the retention requirements at the end of the three-year period ending in December 2013 and settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors had the discretion to accelerate the vesting of all or a portion of a participant’s units. For the twelve months ended October 31, 2013 and 2012, we recorded compensation expense and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, was re-measured to market value in December 2013, the settlement date.
Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the twelve months ended October 31, 2014, 2013 and 2012,we recorded compensation expense, and as of October 31, 2014 and 2013, we accrued a liability for this award based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.
The award which vested on December 15, 2014 covered 20% of the grant, including accrued dividends, for a total of 14,461 shares of common stock. After the withholding of $.3 million for federal and state income taxes, our President and Chief Executive Officer received 7,231 shares at the New York Stock Exchange composite closing price on December 12, 2014 of $37.89 per share.
At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issuedfollowing tables include interest recognized in the Consolidated Statements of
Stockholders’ EquityOperations and
the Consolidated Balance Sheets. |
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | Duke |
| | Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
|
| Net interest income recognized related to income taxes | $ | — |
| $ | — |
| $ | 1 |
| $ | — |
| $ | 1 |
|
| Net interest expense recognized related to income taxes | — |
| 2 |
| — |
| — |
| — |
|
| Interest payable related to income taxes | 5 |
| 25 |
| 1 |
| 1 |
| — |
|
|
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | Duke |
| | Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
|
| Net interest income recognized related to income taxes | $ | — |
| $ | — |
| $ | 1 |
| $ | — |
| $ | 2 |
|
| Net interest expense recognized related to income taxes | — |
| 7 |
| — |
| — |
| — |
|
| Interest payable related to income taxes | 4 |
| 23 |
| 1 |
| 1 |
| — |
|
|
| | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | Duke |
| | Duke |
| Duke |
| Duke |
|
| | Duke |
| Energy |
| Progress |
| Energy |
| Energy |
| Energy |
|
(in millions) | Energy |
| Carolinas |
| Energy |
| Progress |
| Florida |
| Indiana |
|
| Net interest income recognized related to income taxes | $ | 12 |
| $ | — |
| $ | 2 |
| $ | 2 |
| $ | 1 |
| $ | 1 |
|
| Net interest expense recognized related to income taxes | — |
| 1 |
| — |
| — |
| — |
| — |
|
| Interest receivable related to income taxes | 3 |
| — |
| — |
| — |
| — |
| 3 |
|
| Interest payable related to income taxes | — |
| 14 |
| — |
| 1 |
| — |
| — |
|
Piedmont recognized $1 million in Note 6 to the consolidated financial statements.
The compensation expensenet interest income recognized related to the incentive compensation plans for the years ended October 31, 2014, 2013 and 2012, and the amounts recorded as liabilities in "Other noncurrent liabilities" in "Noncurrent Liabilities" with the current portion recorded in "Other current liabilities" in "Current Liabilities"income taxes in the Consolidated Balance Sheets asStatements of October 31, 2014 and 2013 are presented below.
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Compensation expense | | $ | 8,496 |
| | $ | 4,526 |
| | $ | 5,730 |
|
| Tax benefit | | 2,476 |
| | 1,538 |
| | 2,080 |
|
| Liability | | 15,130 |
| | 11,098 |
| | |
Based on current accrual assumptions as of October 31, 2014, the expected payout for the approved incentive compensation awards at target will occur in the following fiscal years.
|
| | | | | | | | | | | | |
| In thousands |
| 2015 |
| 2016 |
| 2017 |
| Amount of payout |
| $ | 7,204 |
| | $ | 4,980 |
| | $ | 2,946 |
|
On a quarterly basis, we issue shares of common stock under the ESPP and account for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.
11. Income Taxes
The components of income tax expense for the years ended October 31, 2014, 2013 and 2012 are presented below.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| 2014 |
| 2013 |
| 2012 |
| In thousands |
| Federal |
| State |
| Federal |
| State |
| Federal |
| State |
| Charged (Credited) to operating | | | | | | | | | | | | |
| income: |
|
|
|
|
|
|
|
|
|
|
|
|
Current (1) |
| $ | (1,653 | ) |
| $ | 950 |
|
| $ | (3,032 | ) |
| $ | 919 |
|
| $ | (29,062 | ) |
| $ | 1,857 |
|
Deferred (1) |
| 70,654 |
|
| 13,434 |
|
| 67,885 |
|
| 11,829 |
|
| 86,496 |
|
| 10,144 |
|
| Tax Credits: |
|
|
|
| |
| |
| |
| |
|
| Amortization |
| (209 | ) | | — |
| | (267 | ) | | — |
| | (334 | ) | | — |
|
| Total |
| 68,792 |
| | 14,384 |
| | 64,586 |
| | 12,748 |
| | 57,100 |
| | 12,001 |
|
| | | | | | | | | | | | | |
| Charged (Credited) to other income | | | | | | | | | | | | |
| (expense): |
|
| |
| |
| |
| |
| |
|
| Current |
| 4,233 |
| | 870 |
| | 6,049 |
| | 984 |
| | 5,636 |
| | 1,027 |
|
| Deferred |
| 5,811 |
| | 728 |
| | 2,225 |
| | (646 | ) | | 2,214 |
| | 239 |
|
| Total |
| 10,044 |
| | 1,598 |
| | 8,274 |
| | 338 |
| | 7,850 |
| | 1,266 |
|
| Total |
| $ | 78,836 |
| | $ | 15,982 |
| | $ | 72,860 |
| | $ | 13,086 |
| | $ | 64,950 |
| | $ | 13,267 |
|
(1) Includes utilization of federal NOL carryforward benefit of $28.6 millionOperations for the year ended October 31, 20142016.
Duke Energy and the generation of a NOL carryforward benefit of $62.3 million for the year ended October 31, 2013.
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Federal taxes at 35% |
| $ | 83,517 |
| | $ | 77,127 |
| | $ | 69,322 |
|
| State income taxes, net of federal benefit |
| 10,389 |
| | 8,506 |
| | 8,624 |
|
| Amortization of investment tax credits |
| (209 | ) | | (267 | ) | | (334 | ) |
| Other, net |
| 1,121 |
| | 580 |
| | 605 |
|
| Total |
| $ | 94,818 |
| | $ | 85,946 |
| | $ | 78,217 |
|
As of October 31, 2014 and 2013, deferred income taxes consisted of the following temporary differences.
|
| | | | | | | | |
| In thousands |
| 2014 |
| 2013 |
| Deferred tax assets: |
|
| |
|
| Benefit of loss carryforwards |
| $ | 39,532 |
| | $ | 66,087 |
|
| Revenues and cost of gas | | 4,960 |
| | — |
|
| Employee benefits and compensation |
| 16,547 |
| | 13,834 |
|
| Revenue requirement |
| 20,320 |
| | 19,062 |
|
| Utility plant |
| 5,631 |
| | 10,386 |
|
| Other |
| 12,869 |
| | 12,796 |
|
| Total deferred tax assets |
| 99,859 |
| | 122,165 |
|
| Valuation allowance |
| (505 | ) | | (505 | ) |
| Total deferred tax assets, net |
| 99,354 |
| | 121,660 |
|
| Deferred tax liabilities: |
| | | |
| Utility plant |
| 724,172 |
| | 652,822 |
|
| Revenues and cost of gas |
| 4,340 |
| | 21,257 |
|
| Equity method investments |
| 42,998 |
| | 38,710 |
|
| Deferred costs |
| 65,828 |
| | 59,221 |
|
| Other |
| 18,065 |
| | 18,324 |
|
| Total deferred tax liabilities |
| 855,403 |
| | 790,334 |
|
| Net deferred income tax liabilities |
| $ | 756,049 |
| | $ | 668,674 |
|
As of October 31, 2014 and 2013, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly-ownedits subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2014 and 2013, we have federal NOL carryforwards of $97 million and $178.1 million, respectively, which expire in 2033. We also have $5.9 million of federal NOL carryforwards as of October 31, 2014 and 2013 that expire in 2021 through 2025 and are subject to an annual limitation of $.3 million. As of October 31, 2014, we have a $2.4 million alternative minimum tax credit carryforward.
As of October 31, 2014 and 2013, we have state NOL carryforwards of $7.2 million and $6.4 million, respectively, that expire from 2020 through 2028. We may use the carryforwards to offset taxable income.
We are no longer subject to U.S. federal income tax examinationsexamination for tax years ending before and including October 31, 2009, and with2015. With few exceptions, Duke Energy and its subsidiaries are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years ended before and including October 31, 2009. The IRS is currently auditing the federal income tax returns for years ended October 31, 2010, 2011 and 2012.2015.
A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Balance at beginning of year |
| $ | 505 |
| | $ | 505 |
| | $ | 505 |
|
| Credited to income tax expense |
| — |
| | — |
| | — |
|
| Balance at end of year |
| $ | 505 |
| | $ | 505 |
| | $ | 505 |
|
There were no unrecognized tax benefits for the years ended October 31, 2014 and 2013.
In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduced the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provided for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at October 31, 2013 by approximately $25 million for temporary differences expected to reverse at a lower rate than
under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our regulated non-utility activities segment, with the balance of approximately $24 million recorded in deferred income taxes in “Regulatory Liabilities” as presented in Note 1 to the consolidated financial statements, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3 million for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. This increased our deferred income taxes recorded in “Regulatory Liabilities” to approximately $27 million. Our state regulatory commissions will determine the refund period of this regulatory liability in future proceedings.
12. Equity Method Investments
23. OTHER INCOME AND EXPENSES, NET
The consolidated financial statements include the accountscomponents of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” inOther income and expenses, net on the Consolidated Statements of Comprehensive Income.Operations are as follows. Amounts for Piedmont were not material.
As of October 31, 2014, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.252
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
Cardinal Pipeline Company, L.L.C. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Interest income | $ | 13 |
| | $ | 2 |
| | $ | 6 |
| | $ | 2 |
| | $ | 5 |
| | $ | 6 |
| | $ | 8 |
|
| AFUDC equity | 237 |
| | 106 |
| | 92 |
| | 47 |
| | 45 |
| | 11 |
| | 28 |
|
| Post in-service equity returns | 40 |
| | 28 |
| | 12 |
| | 12 |
| | — |
| | — |
| | — |
|
| Nonoperating income, other | 62 |
| | 3 |
| | 18 |
| | 4 |
| | 11 |
| | — |
| | 1 |
|
| Other income and expense, net | $ | 352 |
| | $ | 139 |
| | $ | 128 |
| | $ | 65 |
| | $ | 61 |
| | $ | 17 |
| | $ | 37 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Interest income | $ | 21 |
| | $ | 4 |
| | $ | 4 |
| | $ | 3 |
| | $ | 2 |
| | $ | 5 |
| | $ | 6 |
|
| AFUDC equity | 200 |
| | 102 |
| | 76 |
| | 50 |
| | 26 |
| | 6 |
| | 16 |
|
| Post in-service equity returns | 67 |
| | 55 |
| | 12 |
| | 12 |
| | — |
| | — |
| | — |
|
| Nonoperating income (expense), other | 36 |
| | 1 |
| | 22 |
| | 6 |
| | 16 |
| | (2 | ) | | — |
|
| Other income and expense, net | $ | 324 |
| | $ | 162 |
| | $ | 114 |
| | $ | 71 |
| | $ | 44 |
| | $ | 9 |
| | $ | 22 |
|
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm, long-term service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 53%. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.
Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.
We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each of the years ended October 31, 2014, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
| (in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
| Interest income | $ | 20 |
| | $ | 2 |
| | $ | 4 |
| | $ | 2 |
| | $ | 2 |
| | $ | 4 |
| | $ | 6 |
|
| AFUDC equity | 164 |
| | 96 |
| | 54 |
| | 47 |
| | 7 |
| | 3 |
| | 11 |
|
| Post in-service equity returns | 73 |
| | 60 |
| | 13 |
| | 13 |
| | — |
| | — |
| | — |
|
| Nonoperating income (expense), other | 33 |
| | 2 |
| | 26 |
| | 9 |
| | 15 |
| | (1 | ) | | (6 | ) |
| Other income and expense, net | $ | 290 |
| | $ | 160 |
| | $ | 97 |
| | $ | 71 |
| | $ | 24 |
| | $ | 6 |
| | $ | 11 |
|
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Transportation costs |
| $ | 8,825 |
| | $ | 8,775 |
| | $ | 6,613 |
|
| Trade accounts payable |
| 747 |
| | 755 |
| | |
24. SUBSEQUENT EVENTS
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 8,856 |
| | $ | 15,179 |
| | |
| Noncurrent assets |
| 111,881 |
| | 116,414 |
| | |
| Current liabilities |
| 1,468 |
| | 2,637 |
| | |
| Noncurrent liabilities |
| 45,402 |
| | 45,273 |
| | |
| Revenues |
| 16,705 |
| | 17,649 |
| | $ | 16,165 |
|
| Gross profit |
| 16,705 |
| | 17,649 |
| | 16,165 |
|
| Income before income taxes |
| 8,042 |
| | 9,361 |
| | 10,433 |
|
Pine Needle LNG Company, L.L.C.
We own 45% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company that owns an interstate LNG storage facility in North Carolina regulated by the FERC. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. Effective July 1, 2013, we acquired Hess Corporation’s 5% membership interest in Pine Needle for $2.9 million,which increased our membership interest from 40% to 45%. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc. and SCANA Corporation.
Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.
We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Gas storage costs |
| $ | 11,364 |
| | $ | 11,098 |
| | $ | 10,410 |
|
| Trade accounts payable |
| 989 |
| | 940 |
| | |
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 8,812 |
| | $ | 9,225 |
| | |
| Noncurrent assets |
| 70,837 |
| | 74,710 |
| | |
| Current liabilities |
| 38,029 |
| | 3,531 |
| | |
| Noncurrent liabilities |
| — |
| | 35,391 |
| | |
| Revenues |
| 18,025 |
| | 16,810 |
| | $ | 16,390 |
|
| Gross profit |
| 18,025 |
| | 16,810 |
| | 16,390 |
|
| Income before income taxes |
| 6,011 |
| | 5,804 |
| | 5,832 |
|
SouthStar Energy Services LLC
We own 15% of the membership interests in SouthStar, a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. (AGL). SouthStar primarily sells natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
In September 2013, GNGC contributed its retail natural gas marketing assets and customer accounts located in Illinois. AGL acquired these retail assets and customers from Nicor Inc. in December 2011 and additional retail natural gas assets and customer accounts in a separate transaction in June 2013. We made an additional $22.5 million capital contribution to SouthStar, maintaining our 15% equity ownership, related to this transaction.
SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.
These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Beginning in 2014, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these derivative contracts are recorded as a hedge and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.
We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Operating revenues |
| $ | 3,541 |
| | $ | 3,291 |
| | $ | 2,442 |
|
| Trade accounts receivable |
| 460 |
| | 441 |
| | |
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013* | | 2012 |
| Current assets |
| $ | 196,286 |
| | $ | 199,425 |
| | |
| Noncurrent assets |
| 143,420 |
| | 147,571 |
| | |
| Current liabilities |
| 51,435 |
| | 76,346 |
| | |
| Noncurrent liabilities |
| 83 |
| | 31 |
| | |
| Revenues |
| 845,695 |
| | 639,426 |
| | $ | 585,291 |
|
| Gross profit |
| 234,581 |
| | 174,993 |
| | 161,122 |
|
| Income before income taxes |
| 136,569 |
| | 102,805 |
| | 94,631 |
|
* Amounts have been changed to reflect restatement of AGL's Form 10-K for the year ended December 31, 2013. The restatement had an immaterial impact on SouthStar's results.
Hardy Storage Company, LLC
We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.
We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For the years ended October 31, 2014, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Gas storage costs |
| $ | 9,461 |
| | $ | 9,702 |
| | $ | 9,702 |
|
| Trade accounts payable |
| 774 |
| | 808 |
| | |
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2014 and 2013, and for the twelve months ended October 31, 2014, 2013 and 2012 is presented below.
|
| | | | | | | | | | | | |
| In thousands |
| 2014 | | 2013 | | 2012 |
| Current assets |
| $ | 12,644 |
| | $ | 7,641 |
| | |
| Noncurrent assets |
| 157,861 |
| | 161,282 |
| | |
| Current liabilities |
| 17,316 |
| | 12,378 |
| | |
| Noncurrent liabilities |
| 78,830 |
| | 87,184 |
| | |
| Revenues |
| 23,804 |
| | 24,375 |
| | $ | 24,359 |
|
| Gross profit |
| 23,804 |
| | 24,375 |
| | 24,359 |
|
| Income before income taxes |
| 10,497 |
| | 10,582 |
| | 9,939 |
|
Constitution Pipeline Company, LLC
We own 24% of the membership interests of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $730 million at the project level. As of October 31, 2014, our fiscal year contributions were $37.6 million, with our total equity contributions for the project totaling $53.5 million to date. On December 2, 2014, the FERC issued a certificate of public convenience and necessity approving construction of the Constitution pipeline. The target in-service date of the project is late 2015 or 2016. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2014 and 2013, and for the twelve months ended September 30, 2014 and 2013 is presented below.
|
| | | | | | | | |
| In thousands |
| 2014 | | 2013 (1) |
| Current assets |
| $ | 11,273 |
| | $ | 10,944 |
|
| Noncurrent assets |
| 219,208 |
| | 62,438 |
|
| Current liabilities |
| 7,667 |
| | 7,960 |
|
| Noncurrent liabilities |
| — |
| | — |
|
| Revenues |
| — |
| | — |
|
| Gross profit |
| — |
| | — |
|
| Income before income taxes |
| 10,091 |
| | 3,459 |
|
| | | | | |
(1) Presented in the period in which we have a membership interest in Constitution, and not prior periods when we had no membership interest in Constitution. Our membership in Constitution began in November 2012. |
Atlantic Coast Pipeline, LLC
On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline is proposed to provide interstate natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which is regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.
We entered into an agreement through a wholly-owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion,
excluding financing costs. Members anticipate obtaining project financing for 70% of the total costs during the construction period. As of October 31, 2014, we have made no contributions to ACP.
In October 2014, ACP requested approval from the FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline will commence. ACP expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016 and begin construction thereafter. The project is subject to FERC, state and other federal approvals.
13. Variable Interest Entities
Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor, or the primary beneficiary, is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
On a quarterly basis, we reassess whether we have a controlling financial interest in and are the primary beneficiary of a VIE. The quarterly reassessment process considers whether we have acquired or divested the power to direct the activities of the VIE through changes in governing documents or other circumstances. The reassessment also considers whether we have acquired or disposed of a financial interest that could be significant to the VIE, or whether an interest in the VIE has become significant or is no longer significant. The consolidation status of the VIEs with which we are involved may change as a result of such reassessments. Changes in consolidation status are applied prospectively, with assets and liabilities of a newly consolidated VIE initially recorded at fair value. A gain or loss may be recognized upon deconsolidation of a VIE depending on the carrying values of deconsolidated assets and liabilities compared to the fair value of retained interests and ongoing contractual arrangements.
As of October 31, 2014, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2014 and 2013, our investment balances are as follows.
|
| | | | | | | | |
| | | October 31, | | October 31, |
| In thousands | | 2014 | | 2013 |
| Cardinal | | $ | 16,073 |
| | $ | 18,207 |
|
| Pine Needle | | 18,689 |
| | 20,270 |
|
| SouthStar | | 40,965 |
| | 38,372 |
|
| Hardy Storage | | 37,179 |
| | 34,681 |
|
| Constitution | | 57,255 |
| | 16,939 |
|
| ACP | | 10 |
| | |
| Total equity method investments in non-utility activities | | $ | 170,171 |
| | $ | 128,469 |
|
We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
14. Business Segments
We have three reportable business segments, regulated utility, regulated non-utility activities and unregulated non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one company.
Prior to this fiscal year ended October 31, 2014, we aggregated the regulated non-utility activities and unregulated non-utility activities into one segment, the non-utility activities segment. These activities shared a majority of characteristics that permitted aggregation under relevant accounting guidance. Based on this accounting guidance, the unaggregated operating activities individually have never met the quantitative thresholds for separate disclosure. In September 2014 with the formation of ACP and our equity membership in the venture, our current and future commitment to fund construction of regulated pipelines through our equity method investments became more significant and, as a result, we have changed our segment presentation to separately disclose our non-utility activities into regulated non-utility and unregulated non-utility activities. The effect on our company's risk profile of regulation versus non-regulation of our equity method investments and management’s view that this segmentation will provide disclosures that will help users of our financial statements to better understand how management assesses organizational performance and makes decisions about the allocation of resources were key factors in our decision to modify our reportable segments. We anticipate significant growth in our regulated non-utility activities as compared to our unregulated non-utility activities. This is especially so given our equity ownership in Constitution and ACP, both FERC regulated pipelines. Once these pipelines are in operation, the earnings contribution is expected to increase for this segment.
Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.
Operations of the regulated utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.
Operations by segment for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014, 2013 and 2012 are presented below. The information provided for fiscal years 2013 and 2012 have been restated to align with management's view of the non-utility activities.
|
| | | | | | | | | | | | | | | | |
| | | | | Regulated |
| Unregulated | | |
| | | Regulated | | Non-Utility |
| Non-Utility | | |
| In thousands | | Utility | | Activities |
| Activities | | Total |
| 2014 | | | | | | | | |
| Revenues from external customers | | $ | 1,469,988 |
|
| $ | — |
| | $ | — |
|
| $ | 1,469,988 |
|
| Margin | | 690,208 |
|
| — |
| | — |
|
| 690,208 |
|
| Operations and maintenance expenses | | 270,877 |
|
| 132 |
| | 92 |
|
| 271,101 |
|
| Depreciation | | 118,996 |
|
| — |
| | 18 |
|
| 119,014 |
|
| Operating income (loss) before income taxes | | 263,041 |
|
| (183 | ) | | (203 | ) |
| 262,655 |
|
| Income from equity method investments | | — |
|
| 12,318 |
| | 20,435 |
|
| 32,753 |
|
| Interest expense | | 54,686 |
|
| — |
| | — |
|
| 54,686 |
|
| Income before income taxes | | 206,253 |
|
| 12,135 |
| | 20,231 |
|
| 238,619 |
|
| Total assets | | 4,442,185 |
|
| 129,206 |
| | 41,309 |
|
| 4,612,700 |
|
| Equity method investments in non-utility activities | | — |
|
| 129,206 |
| | 40,965 |
|
| 170,171 |
|
| Construction expenditures | | 460,444 |
|
| — |
| | — |
|
| 460,444 |
|
| | | | | | | | | |
| | |
|
| Regulated |
| Unregulated | | |
| | | Regulated |
| Non-Utility |
| Non-Utility | | |
| In thousands | | Utility |
| Activities |
| Activities | | Total |
| 2013 | | | | | | | | |
| Revenues from external customers | | $ | 1,278,229 |
| | $ | — |
| | $ | — |
| | $ | 1,278,229 |
|
| Margin | | 621,490 |
| | — |
| | — |
| | 621,490 |
|
| Operations and maintenance expenses | | 253,120 |
| | 103 |
| | 78 |
| | 253,301 |
|
| Depreciation | | 112,207 |
| | — |
| | 18 |
| | 112,225 |
|
| Operating income (loss) before income taxes | | 221,528 |
| | (150 | ) | | (202 | ) | | 221,176 |
|
| Income from equity method investments | | — |
| | 10,584 |
| | 15,472 |
| | 26,056 |
|
| Interest expense | | 24,938 |
| | — |
| | — |
| | 24,938 |
|
| Income before income taxes | | 194,659 |
| | 10,434 |
| | 15,270 |
| | 220,363 |
|
| Total assets | | 4,053,591 |
| | 90,097 |
| | 38,735 |
| | 4,182,423 |
|
| Equity method investments in non-utility activities | | — |
| | 90,097 |
| | 38,372 |
| | 128,469 |
|
| Construction expenditures | | 599,999 |
| | — |
| | — |
| | 599,999 |
|
| | | | | | | | | |
| | | | | Regulated | | Unregulated | | |
| | | Regulated | | Non-Utility | | Non-Utility | | |
| In thousands | | Utility | | Activities | | Activities | | Total |
| 2012 | | | | | | | | |
| Revenues from external customers | | $ | 1,122,780 |
| | $ | — |
| | $ | — |
| | $ | 1,122,780 |
|
| Margin | | 575,446 |
| | — |
| | — |
| | 575,446 |
|
| Operations and maintenance expenses | | 242,599 |
| | 31 |
| | 71 |
| | 242,701 |
|
| Depreciation | | 103,192 |
| | — |
| | 18 |
| | 103,210 |
|
| Operating income (loss) before income taxes | | 194,824 |
| | (78 | ) | | (186 | ) | | 194,560 |
|
| Income from equity method investments | | — |
| | 9,709 |
| | 14,195 |
| | 23,904 |
|
| Interest expense | | 20,097 |
| | — |
| | — |
| | 20,097 |
|
| Income before income taxes | | 174,424 |
| | 9,631 |
| | 14,009 |
| | 198,064 |
|
| Total assets | | 3,475,640 |
| | 69,749 |
| | 18,498 |
| | 3,563,887 |
|
| Equity method investments in non-utility activities | | — |
| | 69,749 |
| | 18,118 |
| | 87,867 |
|
| Construction expenditures | | 529,576 |
| | — |
| | — |
| | 529,576 |
|
Reconciliations to the consolidated financial statements for the years ended October 31, 2014, 2013 and 2012, and as of October 31, 2014 and 2013 are as follows.
|
| | | | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | 2012 |
| Operating Income: | |
| | | | |
| Segment operating income before income taxes | | $ | 262,655 |
| | $ | 221,176 |
| | $ | 194,560 |
|
| Utility income taxes | | (83,176 | ) | | (77,334 | ) | | (69,101 | ) |
| Regulated non-utility activities operating loss before income taxes | | 183 |
| | 150 |
| | 78 |
|
| Unregulated non-utility activities operating loss before income taxes | | 203 |
| | 202 |
| | 186 |
|
| Total | | $ | 179,865 |
| | $ | 144,194 |
| | $ | 125,723 |
|
| | |
| | | | |
| Net Income: | |
| | | | |
| Income before income taxes for reportable segments | | $ | 238,619 |
| | $ | 220,363 |
| | $ | 198,064 |
|
| Income taxes | | (94,818 | ) | | (85,946 | ) | | (78,217 | ) |
| Total | | $ | 143,801 |
| | $ | 134,417 |
| | $ | 119,847 |
|
|
| | | | | | | | | | |
| In thousands | | 2014 | | 2013 | | |
| | | | | | |
| Consolidated Assets: | | | | | |
| Total assets for reportable segments | | $ | 4,612,700 |
| | $ | 4,182,423 |
| |
| Eliminations/Adjustments | | 171,553 |
| | 186,186 |
| |
| Total | | $ | 4,784,253 |
| | $ | 4,368,609 |
| |
15. Subsequent Events
We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure itemsevents related to regulatory matters, commitments and employee share-based plans,contingencies, debt and credit facilities, investments in unconsolidated affiliates, variable interest entities and common stock see Note 2Notes 4, 5, 6, 12, 17 and Note 10, respectively,18, respectively.
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
25. QUARTERLY FINANCIAL DATA (UNAUDITED)
DUKE ENERGY
Quarterly EPS amounts may not sum to the consolidated financial statements.
16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Earnings (Loss) |
| | | | | | |
| | Net | | Per Share of |
| | | Operating | | | | Operating | | Income | | Common Stock |
| | | Revenues | | Margin | | Income | | (Loss) | | Basic | | Diluted |
| Fiscal Year 2014 | | | | | | | | | | | | |
| January 31 | | $ | 657,733 |
| | $ | 261,512 |
| | $ | 102,319 |
| | $ | 97,572 |
| | $ | 1.27 |
| | $ | 1.26 |
|
| April 30 | | 462,247 |
| | 211,523 |
| | 67,299 |
| | 62,540 |
| | 0.80 |
| | 0.80 |
|
| July 31 | | 164,187 |
| | 104,847 |
| | 3,254 |
| | (7,344 | ) | | (0.09 | ) | | (0.09 | ) |
| October 31 | | 185,821 |
| | 112,326 |
| | 6,993 |
| | (8,967 | ) | | (0.11 | ) | | (0.11 | ) |
| | | | | | | | | | | | | |
| Fiscal Year 2013 | | | | | | | | | | | | |
| January 31 | | $ | 515,875 |
| | $ | 231,623 |
| | $ | 86,213 |
| | $ | 85,923 |
| | $ | 1.19 |
| | $ | 1.18 |
|
| April 30 | | 399,411 |
| | 183,856 |
| | 51,504 |
| | 55,790 |
| | 0.74 |
| | 0.74 |
|
| July 31 | | 162,943 |
| | 97,000 |
| | 591 |
| | (2,293 | ) | | (0.03 | ) | | (0.03 | ) |
| October 31 | | 200,000 |
| | 109,011 |
| | 5,886 |
| | (5,003 | ) | | (0.07 | ) | | (0.07 | ) |
The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variationsfull-year total due to changes in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings
per share are calculated using the weighted average number of
common shares outstanding
and rounding. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
| (in millions, except per share data) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 5,729 |
| | $ | 5,555 |
| | $ | 6,482 |
| | $ | 5,799 |
| | $ | 23,565 |
|
| Operating income | 1,437 |
| | 1,387 |
| | 1,695 |
| | 1,262 |
| | 5,781 |
|
| Income from continuing operations | 717 |
| | 691 |
| | 957 |
| | 705 |
| | 3,070 |
|
| Loss from discontinued operations, net of tax | — |
| | (2 | ) | | (2 | ) | | (2 | ) | | (6 | ) |
| Net income | 717 |
| | 689 |
| | 955 |
| | 703 |
| | 3,064 |
|
| Net income attributable to Duke Energy Corporation | 716 |
| | 686 |
| | 954 |
| | 703 |
| | 3,059 |
|
| Earnings per share: | | | | | | | | | |
| Income from continuing operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 1.02 |
| | $ | 0.98 |
| | $ | 1.36 |
| | $ | 1.00 |
| | $ | 4.37 |
|
| Diluted | $ | 1.02 |
| | $ | 0.98 |
| | $ | 1.36 |
| | $ | 1.00 |
| | $ | 4.37 |
|
| Loss from discontinued operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (0.01 | ) |
| Diluted | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (0.01 | ) |
| Net income attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 1.02 |
| | $ | 0.98 |
| | $ | 1.36 |
| | $ | 1.00 |
| | $ | 4.36 |
|
| Diluted | $ | 1.02 |
| | $ | 0.98 |
| | $ | 1.36 |
| | $ | 1.00 |
| | $ | 4.36 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 5,377 |
| | $ | 5,213 |
| | $ | 6,576 |
| | $ | 5,577 |
| | $ | 22,743 |
|
| Operating income | 1,240 |
| | 1,259 |
| | 1,954 |
| | 888 |
| | 5,341 |
|
| Income from continuing operations | 577 |
| | 624 |
| | 1,001 |
| | 376 |
| | 2,578 |
|
| Income (Loss) from discontinued operations, net of tax | 122 |
| | (112 | ) | | 180 |
| | (598 | ) | | (408 | ) |
| Net income (loss) | 699 |
| | 512 |
| | 1,181 |
| | (222 | ) | | 2,170 |
|
| Net income (loss) attributable to Duke Energy Corporation | 694 |
| | 509 |
| | 1,176 |
| | (227 | ) | | 2,152 |
|
| Earnings per share: | | | | | | | | | |
| Income from continuing operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 0.83 |
| | $ | 0.90 |
| | $ | 1.44 |
| | $ | 0.53 |
| | $ | 3.71 |
|
| Diluted | $ | 0.83 |
| | $ | 0.90 |
| | $ | 1.44 |
| | $ | 0.53 |
| | $ | 3.71 |
|
| Income (Loss) from discontinued operations attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 0.18 |
| | $ | (0.16 | ) | | $ | 0.26 |
| | $ | (0.86 | ) | | $ | (0.60 | ) |
| Diluted | $ | 0.18 |
| | $ | (0.16 | ) | | $ | 0.26 |
| | $ | (0.86 | ) | | $ | (0.60 | ) |
| Net income (loss) attributable to Duke Energy Corporation common stockholders | | | | | | | | | |
| Basic | $ | 1.01 |
| | $ | 0.74 |
| | $ | 1.70 |
| | $ | (0.33 | ) | | $ | 3.11 |
|
| Diluted | $ | 1.01 |
| | $ | 0.74 |
| | $ | 1.70 |
| | $ | (0.33 | ) | | $ | 3.11 |
|
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
The following table includes unusual or infrequently occurring items in each quarter during the quarter. two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (16 | ) | | $ | (30 | ) | | $ | (23 | ) | | $ | (34 | ) | | $ | (103 | ) |
| Regulatory Settlements (see Note 4) | — |
| | — |
| | (135 | ) | | (23 | ) | | (158 | ) |
| Commercial Renewables Impairments (see Notes 10 and 11) | — |
| | — |
| | (84 | ) | | (18 | ) | | (102 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 102 |
| | 102 |
|
| Total | $ | (16 | ) | | $ | (30 | ) | | $ | (242 | ) | | $ | 27 |
| | $ | (261 | ) |
| 2016 | | | | | | | | | |
|
| Costs to Achieve Mergers (see Note 2) | $ | (120 | ) | | $ | (111 | ) | | $ | (84 | ) | | $ | (208 | ) | | $ | (523 | ) |
| Commercial Renewables Impairment (see Note 12) | — |
| | — |
| | (71 | ) | | — |
| | (71 | ) |
| Loss on Sale of International Disposal Group (see Note 2) | — |
| | — |
| | — |
| | (514 | ) | | (514 | ) |
| Impairment of Assets in Central America (see Note 2) | — |
| | (194 | ) | | — |
| | — |
| | (194 | ) |
| Cost Savings Initiatives (see Note 19) | (20 | ) | | (24 | ) | | (19 | ) | | (29 | ) | | (92 | ) |
| Total | $ | (140 | ) | | $ | (329 | ) | | $ | (174 | ) | | $ | (751 | ) | | $ | (1,394 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
| (in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 1,716 |
| | $ | 1,729 |
| | $ | 2,136 |
| | $ | 1,721 |
| | $ | 7,302 |
|
| Operating income | 484 |
| | 485 |
| | 777 |
| | 403 |
| | 2,149 |
|
| Net income | 270 |
| | 273 |
| | 466 |
| | 205 |
| | 1,214 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 1,740 |
| | $ | 1,675 |
| | $ | 2,226 |
| | $ | 1,681 |
| | $ | 7,322 |
|
| Operating income | 481 |
| | 464 |
| | 815 |
| | 302 |
| | 2,062 |
|
| Net income | 271 |
| | 261 |
| | 494 |
| | 140 |
| | 1,166 |
|
The annual amount may differ from the total of the quarterly amounts due to changesfollowing table includes unusual or infrequently occurring items in the number of shares outstandingeach quarter during the year.two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (4 | ) | | $ | (6 | ) | | $ | (5 | ) |
| $ | (5 | ) | | $ | (20 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | (15 | ) | | (15 | ) |
| Total | $ | (4 | ) | | $ | (6 | ) | | $ | (5 | ) | | $ | (20 | ) | | $ | (35 | ) |
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (11 | ) | | $ | (12 | ) | | $ | (13 | ) | | $ | (68 | ) | | $ | (104 | ) |
| Cost Savings Initiatives (see Note 19) | (10 | ) | | (10 | ) | | (8 | ) | | (11 | ) | | (39 | ) |
| Total | $ | (21 | ) | | $ | (22 | ) | | $ | (21 | ) | | $ | (79 | ) | | $ | (143 | ) |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC �� DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
| (in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 2,179 |
| | $ | 2,392 |
| | $ | 2,864 |
| | $ | 2,348 |
| | $ | 9,783 |
|
| Operating income | 487 |
| | 591 |
| | 657 |
| | 493 |
| | 2,228 |
|
| Net income | 201 |
| | 277 |
| | 343 |
| | 447 |
| | 1,268 |
|
| Net income attributable to Parent | 199 |
| | 274 |
| | 341 |
| | 444 |
| | 1,258 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 2,332 |
| | $ | 2,348 |
| | $ | 2,965 |
| | $ | 2,208 |
| | $ | 9,853 |
|
| Operating income | 475 |
| | 560 |
| | 814 |
| | 292 |
| | 2,141 |
|
| Income from continuing operations | 212 |
| | 274 |
| | 449 |
| | 104 |
| | 1,039 |
|
| Net income | 212 |
| | 274 |
| | 449 |
| | 106 |
| | 1,041 |
|
| Net income attributable to Parent | 209 |
| | 272 |
| | 446 |
| | 104 |
| | 1,031 |
|
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (4 | ) | | $ | (7 | ) | | $ | (6 | ) | | $ | (6 | ) | | $ | (23 | ) |
| Regulatory Settlements (see Note 4) | — |
| | — |
| | (135 | ) | | (23 | ) | | (158 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 246 |
| | 246 |
|
| Total | $ | (4 | ) | | $ | (7 | ) | | $ | (141 | ) | | $ | 217 |
| | $ | 65 |
|
| 2016 | | | | | | | | | |
|
| Costs to Achieve Mergers | $ | (7 | ) | | $ | (8 | ) | | $ | (10 | ) | | $ | (44 | ) | | $ | (69 | ) |
| Cost Savings Initiatives (see Note 19) | (8 | ) | | (8 | ) | | (10 | ) | | (14 | ) | | (40 | ) |
| Total | $ | (15 | ) | | $ | (16 | ) | | $ | (20 | ) | | $ | (58 | ) | | $ | (109 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 1,219 |
| | $ | 1,199 |
| | $ | 1,460 |
| | $ | 1,251 |
| | $ | 5,129 |
|
| Operating income | 286 |
| | 282 |
| | 411 |
| | 256 |
| | 1,235 |
|
| Net income | 147 |
| | 154 |
| | 246 |
| | 168 |
| | 715 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 1,307 |
| | $ | 1,213 |
| | $ | 1,583 |
| | $ | 1,174 |
| | $ | 5,277 |
|
| Operating income | 258 |
| | 255 |
| | 438 |
| | 135 |
| | 1,086 |
|
| Net income | 137 |
| | 131 |
| | 271 |
| | 60 |
| | 599 |
|
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (2 | ) | | $ | (4 | ) | | $ | (4 | ) | | $ | (4 | ) | | $ | (14 | ) |
| Regulatory Settlements (see Note 4) | — |
| | — |
| | — |
| | (23 | ) | | (23 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 40 |
| | 40 |
|
| Total | $ | (2 | ) |
| $ | (4 | ) |
| $ | (4 | ) |
| $ | 13 |
|
| $ | 3 |
|
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (5 | ) | | $ | (5 | ) | | $ | (6 | ) | | $ | (40 | ) | | $ | (56 | ) |
| Cost Savings Initiatives (see Note 19) | (5 | ) | | (5 | ) | | (7 | ) | | (6 | ) | | (23 | ) |
| Total | $ | (10 | ) | | $ | (10 | ) | | $ | (13 | ) | | $ | (46 | ) | | $ | (79 | ) |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 959 |
| | $ | 1,191 |
| | $ | 1,401 |
| | $ | 1,095 |
| | $ | 4,646 |
|
| Operating income | 196 |
| | 306 |
| | 240 |
| | 234 |
| | 976 |
|
| Net income | 90 |
| | 158 |
| | 120 |
| | 344 |
| | 712 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 1,024 |
| | $ | 1,133 |
| | $ | 1,381 |
| | $ | 1,030 |
| | $ | 4,568 |
|
| Operating income | 213 |
| | 300 |
| | 373 |
| | 155 |
| | 1,041 |
|
| Net income | 110 |
| | 171 |
| | 206 |
| | 64 |
| | 551 |
|
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (2 | ) | | $ | (3 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (9 | ) |
| Regulatory Settlements (see Note 4) | — |
| | — |
| | (135 | ) | | — |
| | (135 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 226 |
| | 226 |
|
| Total | $ | (2 | ) | | $ | (3 | ) | | $ | (137 | ) | | $ | 224 |
| | $ | 82 |
|
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (2 | ) | | $ | (3 | ) | | $ | (4 | ) | | $ | (4 | ) | | $ | (13 | ) |
| Cost Savings Initiatives (see Note 19) | (2 | ) | | (3 | ) | | (3 | ) | | (9 | ) | | (17 | ) |
| Total | $ | (4 | ) | | $ | (6 | ) | | $ | (7 | ) | | $ | (13 | ) | | $ | (30 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 518 |
| | $ | 437 |
| | $ | 471 |
| | $ | 497 |
| | $ | 1,923 |
|
| Operating income | 83 |
| | 65 |
| | 102 |
| | 76 |
| | 326 |
|
| Loss from discontinued operations, net of tax | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Net income | 42 |
| | 30 |
| | 55 |
| | 65 |
| | 192 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 516 |
| | $ | 428 |
| | $ | 489 |
| | $ | 511 |
| | $ | 1,944 |
|
| Operating income | 96 |
| | 55 |
| | 106 |
| | 90 |
| | 347 |
|
| Income from discontinued operations, net of tax | 2 |
| | — |
| | 34 |
| | — |
| | 36 |
|
| Net income | 59 |
| | 23 |
| | 89 |
| | 57 |
| | 228 |
|
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (1 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (6 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 23 |
| | 23 |
|
| Total | $ | (1 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | 21 |
| | $ | 17 |
|
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (1 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (6 | ) |
| Cost Savings Initiatives (see Note 19) | (1 | ) | | (1 | ) | | — |
| | (1 | ) | | (3 | ) |
| Total | $ | (2 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (3 | ) | | $ | (9 | ) |
PART II
DUKE ENERGY CORPORATION – DUKE ENERGY CAROLINAS, LLC – PROGRESS ENERGY, INC. –
DUKE ENERGY PROGRESS, LLC – DUKE ENERGY FLORIDA, LLC – DUKE ENERGY OHIO, INC. – DUKE ENERGY INDIANA, LLC– PIEDMONT NATURAL GAS COMPANY, INC.
Combined Notes To Consolidated Financial Statements – (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 758 |
| | $ | 742 |
| | $ | 802 |
| | $ | 745 |
| | $ | 3,047 |
|
| Operating income | 186 |
| | 210 |
| | 230 |
| | 170 |
| | 796 |
|
| Net income | 91 |
| | 106 |
| | 121 |
| | 36 |
| | 354 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 714 |
| | $ | 702 |
| | $ | 809 |
| | $ | 733 |
| | $ | 2,958 |
|
| Operating income | 176 |
| | 174 |
| | 239 |
| | 176 |
| | 765 |
|
| Net income | 95 |
| | 85 |
| | 129 |
| | 72 |
| | 381 |
|
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
(in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (1 | ) | | $ | (6 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | (55 | ) | | (55 | ) |
| Total | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (56 | ) | | $ | (61 | ) |
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (1 | ) | | $ | (2 | ) | | $ | (3 | ) | | $ | (3 | ) | | $ | (9 | ) |
| Cost Savings Initiatives (see Note 19) | (1 | ) | | (4 | ) | | (1 | ) | | (1 | ) | | (7 | ) |
| Total | $ | (2 | ) | | $ | (6 | ) | | $ | (4 | ) | | $ | (4 | ) | | $ | (16 | ) |
PIEDMONT
The following tables include data for Piedmont's fiscal years ending December 31, 2017, and October 31, 2016. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
| (in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Operating revenues | $ | 500 |
| | $ | 201 |
| | $ | 183 |
| | $ | 444 |
| | $ | 1,328 |
|
| Operating income (loss) | 170 |
| | 5 |
| | (4 | ) | | 115 |
| | 286 |
|
| Net income (loss) | 95 |
| | (8 | ) | | (11 | ) | | 63 |
| | 139 |
|
| 2016 | | | | | | | | | |
| Operating revenues | $ | 464 |
| | $ | 353 |
| | $ | 160 |
| | $ | 172 |
| | $ | 1,149 |
|
| Operating income (loss) | 171 |
| | 104 |
| | — |
| | (50 | ) | | 225 |
|
| Net income (loss) | 98 |
| | 63 |
| | (7 | ) | | 39 |
| | 193 |
|
For the two months ended December 31, 2016, Piedmont's operating revenues, operating income, and net income were $322 million, $96 million and $54 million, respectively.
The following table includes unusual or infrequently occurring items in each quarter during the two most recently completed fiscal years. All amounts discussed below are pretax. |
| | | | | | | | | | | | | | | | | | | |
| | First |
| | Second |
| | Third |
| | Fourth |
| | |
| (in millions) | Quarter |
| | Quarter |
| | Quarter |
| | Quarter |
| | Total |
|
| 2017 | | | | | | | | | |
| Costs to Achieve Piedmont Merger (see Note 2) | $ | (6 | ) | | $ | (13 | ) | | $ | (8 | ) | | $ | (19 | ) | | $ | (46 | ) |
| Impacts of the Tax Act (see Note 22) | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
| Total | $ | (6 | ) | | $ | (13 | ) | | $ | (8 | ) | | $ | (17 | ) | | $ | (44 | ) |
| 2016 | | | | | | | | | |
| Costs to Achieve Mergers | $ | (6 | ) | | $ | (2 | ) | | $ | (1 | ) | | $ | (53 | ) | | $ | (62 | ) |
For the two months ended December 31, 2016, Piedmont's costs to achieve merger were $7 million.
ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial DisclosureCHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
Item 9A. Controls and Procedures
PART II
Management’s Evaluation of ITEM 9A. CONTROLS AND PROCEDURESDisclosure Controls and Procedures
Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-K. Such disclosureDisclosure controls and procedures are controls and other procedures that are designed to provide reasonable assuranceensure that the information we are required to disclosebe disclosed by the Duke Energy Registrants in the reports wethey file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported, within the time periods requiredspecified by the United States Securities and Exchange Commission’sSEC rules and formsforms.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that such information required to be disclosed by the Duke Energy Registrants in the reports they file or submit under the Exchange Act is accumulated and communicated to our management, including ourthe Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation,
Under the Presidentsupervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Senior Vice PresidentDuke Energy Registrants have evaluated the effectiveness of their disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that as of the end of the period covered by this Form 10-K, our disclosurethese controls and procedures wereare effective at thein providing reasonable assurance level.of compliance.
Changes in Internal Control Over Financial Reporting
We routinely review ourUnder the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Duke Energy Registrants have evaluated changes in internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as(as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange ActAct) that occurred during the fourthfiscal quarter of fiscal 2014 thatended December 31, 2017, and have concluded no change has materially affected, or areis reasonably likely to materially affect, our internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGManagement’s Annual Report On Internal Control Over Financial Reporting
December 23, 2014
OurThe Duke Energy Registrants’ management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Internal control over financial reporting, as thatsuch term is defined in Exchange Act Rules 13a-15(f) under the Securities Exchange Act of 1934 isand 15d-15(f). The Duke Energy Registrants’ internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. The Company’sprinciples in the United States. Due to inherent limitations, internal control over financial reporting is supported by a programmay not prevent or detect misstatements. Also, projections of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and trainingany evaluation of qualified personnel and a written Codeeffectiveness of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.
Because of the inherent limitations, any system of internal control over financial reporting no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.
We haveThe Duke Energy Registrants’ management, including their Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of ourtheir internal control over financial reporting as of December 31, 2017, based uponon the framework in “Internal Control—the Internal Control – Integrated Framework” (1992)Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon suchon that evaluation, our management concluded that as of October 31, 2014, ourits internal controlcontrols over financial reporting was effective.were effective as of December 31, 2017.
The Company’sDeloitte & Touche LLP, Duke Energy’s independent registered public accounting firm, Deloitte & Touche LLP, has issued itsan attestation report on the effectiveness of the Company’sDuke Energy’s internal control over financial reportingreporting. This attestation report is included in Part II, Item 8 of this Form 10-K. This report is not applicable to the Subsidiary Registrants as of October 31, 2014.these companies are not accelerated or large accelerated filers.
|
| | | | |
| | | Piedmont Natural Gas Company, Inc. |
| | | | |
| | | | /s/ Thomas E. Skains |
| | | |
PART II Chairman, President and Chief Executive Officer
|
| |
| | | | /s/ Karl W. Newlin |
| | | | Karl W. Newlin
Senior Vice President and Chief Financial Officer
|
| |
| | | | /s/ Jose M. Simon |
| | | | Jose M. Simon
Vice President and Controller
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors and Stockholders of Duke Energy Corporation
Piedmont Natural Gas Company, Inc.
Charlotte, North Carolina
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc.Duke Energy Corporation and subsidiaries (the “Company”"Company") as of OctoberDecember 31, 2014,2017, based on criteria established in Internal Control—Control – Integrated Framework (1992)(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2017, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for the period ended December 31, 2017, and the related notes of the Company and our report dated February 23, 2018, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report onOn Internal Control overOver Financial Reporting.Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2014, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31, 2014 of the Company and our report dated December 23, 2014 expressed an unqualified opinion on those financial statements.
/s/Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2014
Item 9B. Other InformationFebruary 21, 2018
PART III
Item 10. Directors, Executive Officers and Corporate Governance
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Information concerning our executive officers and directorsregarding Duke Energy's Executive Officers is set forth in Part I, Item 1, "Business – Executive Officers of the sections entitled “Board of Directors” and “Executive Officers” in our Proxy Statement for the 2015 Annual Meeting of Shareholders (2015 Proxy Statement), which sections are incorporatedRegistrants," in this annual reportAnnual Report on Form 10-K by reference. Information concerning compliance with Section 16(a)10-K. Duke Energy will provide information that is responsive to the remainder of this Item 10 in its definitive proxy statement or in an amendment to this Annual Report not later than 120 days after the end of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2015 Proxy Statement, which sectionfiscal year covered by this Annual Report. That information is incorporated in this annual report on Form 10-KItem 10 by reference.
Information concerning our Audit Committee and our Audit Committee financial expertsITEM 11. EXECUTIVE COMPENSATIONDuke Energy will provide information that is set forthresponsive to this Item 11 in its definitive proxy statement or in an amendment to this Annual Report not later than 120 days after the section entitled “Committeesend of the Board” in our 2015 Proxy Statement, which sectionfiscal year covered by this Annual Report. That information is incorporated in this annual report on Form 10-KItem 11 by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Equity Compensation Plan Information
The following table shows information as of December 31, 2017, about securities to be issued upon exercise of outstanding options, warrants and rights under Duke Energy's equity compensation plans, along with the weighted-average exercise price of the outstanding options, warrants and rights and the number of securities remaining available for future issuance under the plans. |
| | | | | | |
| Plan Category | Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights (a) | Weighted average
exercise price of
outstanding options,
warrants and rights (b)(1) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
| Equity compensation plans approved by security holders | 3,566,563 |
| (2) | n/a | 7,314,882 | (3) |
| Equity compensation plans not approved by security holders | 191,394 |
| (4) | n/a | n/a | (5) |
| Total | 3,757,957 |
| | n/a | 7,314,882 | |
(1) As of December 31, 2017, no options were outstanding under equity compensation plans.
| |
| (2) | Includes restricted stock units and performance shares (assuming the maximum payout level) granted under the Duke Energy Corporation 2010 Long-Term Incentive Plan or the Duke Energy Corporation 2015 Long-Term Incentive Plan, as well as shares that could be payable with respect to certain compensation deferred under the Duke Energy Corporation Executive Savings Plan (Executive Savings Plan) or the Duke Energy Corporation Directors' Savings Plan (Directors’ Savings Plan). |
| |
| (3) | Includes shares remaining available for issuance pursuant to stock awards under the Duke Energy Corporation 2015 Long-Term Incentive Plan. |
| |
| (4) | Includes shares that could be payable with respect to certain compensation deferred under the Executive Savings Plan or and the Directors' Savings Plan, each of which is a nonqualified deferred compensation plan described in more detail below. Upon the acquisition of Piedmont Natural Gas Company, Inc., performance shares granted prior to such acquisition under the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan were converted into restricted stock units payable in shares of Duke Energy common stock. As of December 31, 2017, 45,173 such restricted stock units were outstanding. Following the acquisition, no further stock awards were permitted to be granted under the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan. These converted awards are not listed in the table above. |
| |
| (5) | The number of shares remaining available for future issuance under equity compensation plans not approved by security holders cannot be determined because it is based on the amount of future voluntary deferrals, if any, under the Executive Savings Plan and the Directors' Savings Plan. |
Under the Executive Savings Plan, participants can elect to defer a portion of their base salary and short‑term incentive compensation. Participants also receive a company matching contribution in excess of the contribution limits prescribed by the Internal Revenue Code under the Duke Energy Retirement Savings Plan, which is the 401(k) plan in which employees are generally eligible to participate. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may direct the deemed investment of base salary deferrals, short-term incentive compensation deferrals and matching contributions among investment options available under the Duke Energy Retirement Savings Plan, including the Duke Energy Common Stock Fund. Participants may change their investment elections on a daily basis. Deferrals of equity awards are credited with earnings and losses based on the performance of the Duke Energy Common Stock Fund. The benefits payable under the plan are unfunded and subject to the claims of Duke Energy’s creditors.
Under the Directors’ Savings Plan, outside directors may elect to defer all or a portion of their annual compensation, generally consisting of retainers. Deferred amounts are credited to an unfunded account, the balance of which is adjusted for the performance of phantom investment options, including the Duke Energy common stock fund, as elected by the director, and generally are paid when the director terminates his or her service from the Board of Directors.
We have adopted a Code of Ethics and Business Conduct262
Duke Energy will provide additional information that is applicableresponsive to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, which serves asthis Item 12 in its definitive proxy statement or in an amendment to this Annual Report not later than 120 days after the code of ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions under Item 406(b) of Regulation S-K. The Code of Ethics and Business Conduct is available on the “For Investors-Corporate Governance” section of our website at www.piedmontng.com. If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct that apply to the principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions and that relate to any elementend of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.
Item 11. Executive Compensation
Information forfiscal year covered by this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our 2015 Proxy Statement, which sections are incorporated in this annual report on Form 10-K by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our 2015 Proxy Statement, which sectionAnnual Report. That information is incorporated in this annual report on Form 10-KItem 12 by reference.
Information concerning securities authorized for issuance under our equity compensation plansITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEDuke Energy will provide information that is set forthresponsive to this Item 13 in its definitive proxy statement or in an amendment to this Annual Report not later than 120 days after the section entitled “Equity Compensation Plan Information” in our 2015 Proxy Statement, which sectionend of the fiscal year covered by this Annual Report. That information is incorporated in this annual report on Form 10-KItem 13 by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Information for this item is set forth in the section entitled “Director Independence and Related Person Transactions” in our 2015 Proxy Statement, which section is incorporated in this annual report on Form 10-K by reference.
Item 14. Principal Accounting Fees and Services
Information for this item is set forth in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP Asand the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) provided professional services to the Duke Energy Registrants. The following tables present the Deloitte fees for services rendered to the Duke Energy Registrants during 2017 and 2016. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 | | |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
| | |
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
| | |
(in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
| | Piedmont |
|
Types of Fees | | | | | | | | | | | | | | | |
Audit Fees(a) | $ | 13.6 |
| | $ | 4.7 |
| | $ | 5.6 |
| | $ | 3.1 |
| | $ | 2.4 |
| | $ | 0.8 |
| | $ | 1.4 |
| | $ | 0.8 |
|
Audit-Related Fees(b) | 0.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Tax Fees(c) | 1.7 |
| | 0.6 |
| | 0.1 |
| | 0.4 |
| | — |
| | 0.1 |
| | 0.1 |
| | 0.1 |
|
Other Fees(d) | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Fees | $ | 15.6 |
| | $ | 5.3 |
| | $ | 5.7 |
| | $ | 3.5 |
| | $ | 2.4 |
| | $ | 0.9 |
| | $ | 1.5 |
| | $ | 0.9 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | Duke |
| | | | Duke |
| | Duke |
| | Duke |
| | Duke |
|
| | Duke |
| | Energy |
| | Progress |
| | Energy |
| | Energy |
| | Energy |
| | Energy |
|
(in millions) | Energy |
| | Carolinas |
| | Energy |
| | Progress |
| | Florida |
| | Ohio |
| | Indiana |
|
Types of Fees | | | | | | | | | | | | | |
Audit Fees(a) | $ | 13.6 |
| | $ | 4.8 |
| | $ | 5.2 |
| | $ | 3.0 |
| | $ | 2.2 |
| | $ | 0.8 |
| | $ | 1.4 |
|
Audit-Related Fees(b) | 0.7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Tax Fees(c) | 0.4 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | — |
| | — |
| | 0.1 |
|
Other Fees(d) | 0.2 |
| | 0.1 |
| | 0.1 |
| | 0.1 |
| | — |
| | — |
| | — |
|
| Total Fees | $ | 14.9 |
| | $ | 5.0 |
| | $ | 5.4 |
| | $ | 3.2 |
| | $ | 2.2 |
| | $ | 0.8 |
| | $ | 1.5 |
|
|
| | | | | | |
| | Piedmont(e) |
| | Two Months Ended |
| Year Ended October 31, |
(in millions) | December 31, 2016 | 2016 |
Types of Fees | | |
Audit Fees(a) | $ | 0.6 |
| $ | 1.3 |
|
Audit-Related Fees(b) | — |
| 0.1 |
|
| Total Fees | $ | 0.6 |
| $ | 1.4 |
|
| |
| (a) | Audit Fees are fees billed, or expected to be billed, by Deloitte for professional services for the financial statement audits, audit of the Duke Energy Registrants’ financial statements included in the Annual Report on Form 10-K, reviews of financial statements included in Quarterly Reports on Form 10‑Q, and services associated with securities filings such as comfort letters and consents. |
| |
| (b) | Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of financial statements, including statutory reporting requirements. |
| |
| (c) | Tax Fees are fees billed by Deloitte for tax return assistance and preparation, tax examination assistance and professional services related to tax planning and tax strategy. |
| |
| (d) | Other Fees are billed by Deloitte for attendance at Deloitte-sponsored conferences and access to Deloitte research tools and subscription services. In 2016, Other Fees also included non-audit fees related to consulting services. |
| |
| (e) | Includes all accounting fees and services paid prior to and subsequent to the acquisition. Prior to the acquisition, Piedmont's Audit Committee preapproved all services provided by the independent auditor. |
To safeguard the continued independence of the independent auditor, the Audit Committee of the Board of Directors (Audit Committee) of Duke Energy adopted a policy that all services provided by the independent auditor require preapproval by the Audit Committee. Pursuant to the policy, certain audit services, audit-related services, tax services and other services have been specifically preapproved up to fee limits. In the event the cost of any of these services may exceed the fee limits, the Audit Committee must specifically approve the service. All services performed in 2017 and 2016 by the independent accountant were approved by the Audit Committee pursuant to the preapproval policy.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | |
| (a) | Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows: |
Duke Energy Corporation
Consolidated Financial Statements
Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm For Fiscal Year 2015”
All other schedules are omitted because they are not required, or because the required information is included in ourthe Consolidated Financial Statements or Notes.
Duke Energy Carolinas, LLC
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015 Proxy Statement, which section
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is incorporatedincluded in this annual report on Form 10-K by reference.the Consolidated Financial Statements or Notes.
Progress Energy, Inc.
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
Duke Energy Progress, LLC
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
Duke Energy Florida, LLC
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
PART IV
Item 15. Exhibits, Financial Statement Schedules
Duke Energy Ohio, Inc.
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
Duke Energy Indiana, LLC
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2017, 2016 and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
Piedmont Natural Gas Company, Inc.
Consolidated Financial Statements
Consolidated Statements of Operations and Comprehensive Income for the Year Ended December 31, 2017, Two Months Ended December 31, 2016, and the Years Ended October 31, 2016, and 2015
Consolidated Balance Sheets as of December 31, 2017, and 2016
Consolidated Statements of Cash Flows for the Year Ended December 31, 2017, Two Months Ended December 31, 2016, and the Years Ended October 31, 2016, and 2015
Consolidated Statements of Changes in Equity for the Year Ended December 31, 2017, Two Months Ended December 31, 2016, and the Years Ended October 31, 2016, and 2015
Notes to the Consolidated Financial Statements
Quarterly Financial Data, (unaudited, included in Note 25 to the Consolidated Financial Statements)
Report of Independent Registered Public Accounting Firm
All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.
EXHIBIT INDEX
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**). The Company agrees to furnish upon request to the Commission a copy of any omitted schedules or exhibits upon request on all items designated by a triple asterisk (***). |
| | | | |
(a) | | 1. | | Financial Statements |
The following consolidated financial statements for the year ended October 31, 2014, are included in Item 8 of this report as follows: |
|
Consolidated Balance Sheets – October 31, 2014 and 2013
Consolidated Statements of Comprehensive Income – Years Ended October 31, 2014, 2013 and 2012
Consolidated Statements of Cash Flows – Years Ended October 31, 2014, 2013 and 2012
Consolidated Statements of Stockholders’ Equity – Years Ended October 31, 2014, 2013 and 2012
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
|
|
(a) | | 2. | | Supplemental Consolidated Financial Statement Schedules |
None
Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
|
|
(a) | | 3. | | Exhibits |
|
| | | | | Where an exhibit is filed by incorporationDuke | | | | Duke | | Duke | | Duke | | Duke | | |
| Exhibit | | Duke | | Energy | | Progress | | Energy | | Energy | | Energy | | Energy | | |
| Number | | Energy | | Carolinas | | Energy | | Progress | | Florida | | Ohio | | Indiana | | Piedmont |
| 2.1 | |
| X |
| | | | | The exhibits numbered 10.1 through 10.18 are management contracts or compensatory plans or arrangements. |
| | | | | | | | |
| 2.2 | | X | | 3.1 | | | | | | | | | | | | |
| 3.1 | | X | | | | | | | | | | | | | | |
| 3.2 | | X | | | | | | | | | | | | | | |
| 3.3 | | | | X | | | | | | | | | | | | |
| 3.3.1 | | | | X | | | | | | | | | | | | |
| 3.4 | | | | | | | | | | | | X | | | | |
| 3.4.1 | | | | | | | | | | | | X | | | | |
| 3.5 | | | | | | | | | | | | | | X | | |
| 3.5.1 | | | | | | | | | | | | | | X | | |
| 3.5.2 | | | | | | | | | | | | | | X | | |
| 3.5.3 | | | | | | | | | | | | | | X | | |
| 3.5.4 | | | | | | | | | | | | | | X | | |
| 3.6 | | | | X | | | | | | | | | | | | |
| 3.7 | | | | | | | | | | | | X | | | | |
| 3.8 | | | | | | | | X | | | | | | | | |
| 3.8.1 | | | | | | | | X | | | | | | | | |
| 3.8.2 | | | | | | | | X | | | | | | | | |
| 3.9 | | | | | | X | | | | | | | | | | |
| 3.9.1 | | | | | | X | | | | | | | | | | |
| 3.9.2 | | | | | | X | | | | | | | | | | |
| 3.9.3 | | | | | | X | | | | | | | | | | |
| 3.10 | | | | | | | | | | X | | | | | | |
| 3.10.1 | | | | | | | | | | X | | | | | | |
| 3.10.2 | | | | | | | | | | X | | | | | | |
| 3.10.3 | | | | | | | | | | X | | | | | | |
| 3.11 | |
|
| | 3.2 | | Bylaws of Piedmont Natural Gas Company, Inc., as Amended and Restated Effective September 8, 2011 (incorporated by reference to Exhibit 3.1, Form 8-K dated September 13, 2011). |
|
| | 4.1 | | Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.30,registrant's Annual Report on Form 10-K for the fiscal year ended October 31, 1992)2016, filed on December 22, 2016, File No. 001-06196). |
|
| | | 4.2 | | Amendment | | | | | | | | | | X |
| 3.11.1 | | | | | | | | | | | | | | | | X |
| 4.1 | | X | | | | | | | | | | | | | | |
| 4.1.1 | | X | | | | | | | | | | | | | | |
| 4.1.2 | | X | | | | | | | | | | | | | | |
| 4.1.3 | | X | | | | | | | | | | | | | | |
| 4.1.4 | | X | | | | | | | | | | | | | | |
| 4.1.5 | | X | | | | | | | | | | | | | | |
| 4.1.6 | | X | | | | | | | | | | | | | | |
| 4.1.7 | | X | | | | | | | | | | | | | | |
| 4.1.8 | | X | | | | | | | | | | | | | | |
| 4.1.9 | | X | | | | | | | | | | | | | | |
| 4.1.10 | | X | | | | | | | | | | | | | | |
| 4.1.11 | | X | | | | | | | | | | | | | | |
| 4.1.12 | | X | | | | | | | | | | | | | | |
| 4.1.13 | Thirteenth Supplemental Indenture, dated as of April 18, 2016, to the indenture dated as of June 3, 2008, between Duke Energy Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Duke Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed on May 5, 2016, File No. 1-32853). | X | | | | | | | | | | | | | | |
| 4.1.14 | | X | | | | | | | | | | | | | | |
| 4.1.15 | | X | | | | | | | | | | | | | | |
| 4.1.16 | | X | | | | | | | | | | | | | | |
| 4.1.17 | | X | | | | | | | | | | | | | | |
| 4.2 | | | | X | | | | | | | | | | | | |
| 4.2.1 | | | | X | | | | | | | | | | | | |
| 4.2.2 | | | | X | | | | | | | | | | | | |
| 4.3 | First and Refunding Mortgage from Duke Energy Carolinas, LLC to The Bank of New York Mellon Trust Company, N.A., successor trustee to Guaranty Trust Company of New York, dated as of December 1, 1927, (incorporated by reference to Exhibit 7(a) to registrant's Form S-1, effective October 15, 1947, File No. 2-7224). | | | X | | | | | | | | | | | | |
| 4.3.1 | Instrument of Resignation, Appointment and Acceptance among Duke Energy Carolinas, LLC, JPMorgan Chase Bank, N.A., as Trustee, and The Bank of New York Mellon Trust Company, N.A., as Successor Trustee, dated as of September 24, 2007, (incorporated by reference to Exhibit 4.6.1 to registrant's Registration Statement on Form S-3 filed on October 3, 2007, File No. 333-146483). | | | X | | | | | | | | | | | | |
| 4.3.2 | Ninth Supplemental Indenture, dated as of February 1, 1949, (incorporated by reference to Exhibit 7(j) to registrant's Form S-1 filed on February 3, 1949, File No. 2-7808). | | | X | | | | | | | | | | | | |
| 4.3.3 | Twentieth Supplemental Indenture, dated as of June 15, 1964, (incorporated by reference to Exhibit 4-B-20 to registrant's Form S-1 filed on August 23, 1966, File No. 2-25367). | | | X | | | | | | | | | | | | |
| 4.3.4 | Twenty-third Supplemental Indenture, dated as of February 1, 1968, (incorporated by reference to Exhibit 2-B-26 to registrant's Form S-9 filed on January 21, 1969, File No. 2-31304). | | | X | | | | | | | | | | | | |
| 4.3.5 | Sixtieth Supplemental Indenture, dated as of March 1, 1990, (incorporated by reference to Exhibit 4-B-61 to registrant's Annual Report on Form 10-K for the fiscal year ended OctoberDecember 31, 2007)1990, File No.1-4928). |
|
| | | 4.3X | | | | | | | | | | | | |
| 4.3.6 | Sixty-third Supplemental Indenture, dated as of July 1, 1991, (incorporated by reference to Exhibit 4-B-64 to registrant's Registration Statement on Form S-3 filed on February 13, 1992, File No. 33-45501). | | �� | X | | | | | | | | | | | | |
| 4.3.7 | | | | X | | | | | | | | | | | | |
| 4.3.8 | | | | X | | | | | | | | | | | | |
| 4.3.9 | | | | X | | | | | | | | | | | | |
| 4.3.10 | | | | X | | | | | | | | | | | | |
| 4.3.11 | | | | X | | | | | | | | | | | | |
| 4.3.12 | | | | X | | | | | | | | | | | | |
| 4.3.13 | | | | X | | | | | | | | | | | | |
| 4.3.14 | | | | X | | | | | | | | | | | | |
| 4.3.15 | | | | X | | | | | | | | | | | | |
| 4.3.16 | | | | X | | | | | | | | | | | | |
| 4.3.17 | | | | X | | | | | | | | | | | | |
| 4.3.18 | | | | X | | | | | | | | | | | | |
| 4.3.19 | | | | X | | | | | | | | | | | | |
| 4.4 | Mortgage and Deed of Trust between Duke Energy Progress, Inc. (formerly Carolina Power & Light Company) and The Bank of New York Mellon (formerly Irving Trust Company) and Frederick G. Herbst (Tina D. Gonzalez, successor), as Trustees, dated as of May 1, 1940. | | | | | | | X | | | | | | | | |
| 4.4.1 | First through Fifth Supplemental Indentures thereto (incorporated by reference to Exhibit 2(b), File No. 2-64189). | | | | | | | X | | | | | | | | |
| 4.4.2 | Sixth Supplemental Indenture dated April 1, 1960 (incorporated by reference to Exhibit 2(b)-5, File No. 2-16210). | | | | | | | X | | | | | | | | |
| 4.4.3 | Seventh Supplemental Indenture dated November 1, 1961 (incorporated by reference to Exhibit 2(b)-6, File No. 2-16210). | | | | | | | X | | | | | | | | |
| 4.4.4 | Eighth Supplemental Indenture dated July 1, 1964 (incorporated by reference to Exhibit 4(b)-8, File No. 2-19118). | | | | | | | X | | | | | | | | |
| 4.4.5 | Ninth Supplemental Indenture dated April 1, 1966 (incorporated by reference to Exhibit 4(b)-2, File No. 2-22439). | | | | | | | X | | | | | | | | |
| 4.4.6 | Tenth Supplemental Indenture dated October 1, 1967 (incorporated by reference to Exhibit 4(b)-2, File No. 2-24624). | | | | | | | X | | | | | | | | |
| 4.4.7 | Eleventh Supplemental Indenture dated October 1, 1968 (incorporated by reference to Exhibit 2(c), File No. 2-27297). | | | | | | | X | | | | | | | | |
| 4.4.8 | Twelfth Supplemental Indenture dated January 1, 1970 (incorporated by reference to Exhibit 2(c), File No. 2-30172). | | | | | | | X | | | | | | | | |
| 4.4.9 | Thirteenth Supplemental Indenture dated August 1, 1970 (incorporated by reference to Exhibit 2(c), File No. 2-35694). | | | | | | | X | | | | | | | | |
| 4.4.10 | Fourteenth Supplemental Indenture dated January 1, 1971 (incorporated by reference to Exhibit 2(c), File No. 2-37505). | | | | | | | X | | | | | | | | |
| 4.4.11 | Fifteenth Supplemental Indenture dated October 1, 1971 (incorporated by reference to Exhibit 2(c), File No. 2-39002). | | | | | | | X | | | | | | | | |
| 4.4.12 | Sixteenth Supplemental Indenture dated May 1, 1972 (incorporated by reference to Exhibit 2(c), File No. 2-41738). | | | | | | | X | | | | | | | | |
| 4.4.13 | Seventeenth Supplemental Indenture dated November 1, 1973 (incorporated by reference to Exhibit 2(c), File No. 2-43439). | | | | | | | X | | | | | | | | |
| 4.4.14 | Eighteenth Supplemental Indenture dated (incorporated by reference to Exhibit 2(c), File No. 2-47751). | | | | | | | X | | | | | | | | |
| 4.4.15 | Nineteenth Supplemental Indenture dated May 1, 1974 (incorporated by reference to Exhibit 2(c), File No. 2-49347). | | | | | | | X | | | | | | | | |
| 4.4.16 | Twentieth Supplemental Indenture dated December 1, 1974 (incorporated by reference to Exhibit 2(c), File No. 2-53113). | | | | | | | X | | | | | | | | |
| 4.4.17 | Twenty-first Supplemental Indenture dated April 15, 1975 (incorporated by reference to Exhibit 2(d), File No. 2-53113). | | | | | | | X | | | | | | | | |
| 4.4.18 | Twenty-second Supplemental Indenture dated October 1, 1977 (incorporated by reference to Exhibit 2(c), File No. 2-59511). | | | | | | | X | | | | | | | | |
| 4.4.19 | Twenty-third Supplemental Indenture dated June 1, 1978 (incorporated by reference to Exhibit 2(c), File No. 2-61611). | | | | | | | X | | | | | | | | |
| 4.4.20 | Twenty-fourth Supplemental Indenture dated May 15, 1979 (incorporated by reference to Exhibit 2(d), File No. 2-64189). | | | | | | | X | | | | | | | | |
| 4.4.21 | Twenty-fifth Supplemental Indenture dated November 1, 1979 (incorporated by reference to Exhibit 2(c), File No. 2-65514). | | | | | | | X | | | | | | | | |
| 4.4.22 | Twenty-sixth Supplemental Indenture dated November 1, 1979 (incorporated by reference to Exhibit 2(c), File No. 2-66851). | | | | | | | X | | | | | | | | |
| 4.4.23 | Twenty-seventh Supplemental Indenture dated April 1, 1980 (incorporated by reference to Exhibit 2 (d), File No. 2-66851). | | | | | | | X | | | | | | | | |
| 4.4.24 | Twenty-eighth Supplemental Indenture dated October 1, 1980 (incorporated by reference to Exhibit 4(b)-1, File No. 2-81299). | | | | | | | X | | | | | | | | |
| 4.4.25 | Twenty-ninth Supplemental Indenture dated October 1, 1980 (incorporated by reference to Exhibit 4(b)-2, File No. 2-81299). | | | | | | | X | | | | | | | | |
| 4.4.26 | Thirtieth Supplemental Indenture dated December 1, 1982 (incorporated by reference to Exhibit 4(b)- 3, File No. 2-81299). | | | | | | | X | | | | | | | | |
| 4.4.27 | Thirty-first Supplemental Indenture dated March 15, 1983 (incorporated by reference to Exhibit 4(c)-1, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.28 | Thirty-second Supplemental Indenture dated March 15, 1983 (incorporated by reference to Exhibit 4(c)-2, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.29 | Thirty-third Supplemental Indenture dated December 1, 1983 (incorporated by reference to Exhibit 4(c)-3, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.30 | Thirty-fourth Supplemental Indenture dated December 15, 1983 (incorporated by reference to Exhibit 4(c)-4, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.31 | Thirty-fifth Supplemental Indenture dated April 1, 1984 (incorporated by reference to Exhibit 4(c)-5, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.32 | Thirty-sixth Supplemental Indenture dated June 1, 1984 (incorporated by reference to Exhibit 4(c)-6, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.33 | Thirty-seventh Supplemental Indenture dated June 1, 1984 (incorporated by reference to Exhibit 4(c)-7, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.34 | Thirty-eighth Supplemental Indenture dated June 1, 1984 (incorporated by reference to Exhibit 4(c)- 8, File No. 2-95505). | | | | | | | X | | | | | | | | |
| 4.4.35 | Thirty-ninth Supplemental Indenture dated April 1, 1985 (incorporated by reference to Exhibit 4(b), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.36 | Fortieth Supplemental Indenture dated October 1, 1985 (incorporated by reference to Exhibit 4(c), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.37 | Forty-first Supplemental Indenture dated March 1, 1986 (incorporated by reference to Exhibit 4(d), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.38 | Forty-second Supplemental Indenture dated July 1, 1986 (incorporated by reference to Exhibit 4(e), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.39 | Forty-third Supplemental Indenture dated January 1, 1987 (incorporated by reference to Exhibit 4(f), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.40 | Forty-fourth Supplemental Indenture dated December 1, 1987 (incorporated by reference to Exhibit 4(g), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.41 | Forty-fifth supplemental Indenture dated September 1, 1988 (incorporated by reference to Exhibit 4(h), File No. 33-25560). | | | | | | | X | | | | | | | | |
| 4.4.42 | Forty-sixth Supplemental Indenture dated April 1, 1989 (incorporated by reference to Exhibit 4(b), File No. 33-33431). | | | | | | | X | | | | | | | | |
| 4.4.43 | Forty-seventh Supplemental Indenture dated August 1, 1989 (incorporated by reference to Exhibit 4(c), File No. 33-33431). | | | | | | | X | | | | | | | | |
| 4.4.44 | Forty-eighth Supplemental Indenture dated November 15, 1990 (incorporated by reference to Exhibit 4(b), File No. 33-38298). | | | | | | | X | | | | | | | | |
| 4.4.45 | Forty-ninth Supplemental Indenture dated November 15, 1990 (incorporated by reference to Exhibit 4(c), File No. 33-38298). | | | | | | | X | | | | | | | | |
| 4.4.46 | Fiftieth Supplemental Indenture dated February 15, 1991 (incorporated by reference to Exhibit 4(h), File No. 33-42869). | | | | | | | X | | | | | | | | |
| 4.4.47 | Fifty-first Supplemental Indenture dated April 1, 1991 (incorporated by reference to Exhibit 4(i), File No. 33-42869). | | | | | | | X | | | | | | | | |
| 4.4.48 | Fifty-second Supplemental Indenture dated September 15, 1991(incorporated by reference to Exhibit 4(e), File No. 33-48607). | | | | | | | X | | | | | | | | |
| 4.4.49 | Fifty-third Supplemental Indenture dated January 1, 1992 (incorporated by reference to Exhibit 4(f), File No. 33-48607). | | | | | | | X | | | | | | | | |
| 4.4.50 | Fifty-fourth Supplemental Indenture dated April 15, 1992 (incorporated by reference to Exhibit 4 (g), File No. 33-48607). | | | | | | | X | | | | | | | | |
| 4.4.51 | Fifty-fifth Supplemental Indenture dated July 1, 1992 (incorporated by reference to Exhibit 4(e), File No. 33-55060). | | | | | | | X | | | | | | | | |
| 4.4.52 | Fifty-sixth Supplemental Indenture dated October 1, 1992 (incorporated by reference to Exhibit 4(f), File No. 33-55060). | | | | | | | X | | | | | | | | |
| 4.4.53 | Fifty-seventh Supplemental Indenture dated February 1, 1993 (incorporated by reference to Exhibit 4(e), File No. 33-60014). | | | | | | | X | | | | | | | | |
| 4.4.54 | Fifty-eighth Supplemental Indenture dated March 1, 1993 (incorporated by reference to Exhibit 4(f), File No. 33-60014). | | | | | | | X | | | | | | | | |
| 4.4.55 | Fifty-ninth Supplemental Indenture dated July 1, 1993 (incorporated by reference to Exhibit 4(a) to Post-Effective Amendment No. 1, File No. 33-38349). | | | | | | | X | | | | | | | | |
| 4.4.56 | Sixtieth Supplemental Indenture dated July 1, 1993 (incorporated by reference to Exhibit 4(b) to Post-Effective Amendment No. 1, File No. 33-38349). | | | | | | | X | | | | | | | | |
| 4.4.57 | Sixty-first Supplemental Indenture dated August 15, 1993 (incorporated by reference to Exhibit 4(e), File No. 33-50597). | | | | | | | X | | | | | | | | |
| 4.4.58 | | | | | | | | X | | | | | | | | |
| 4.4.59 | | | | | | | | X | | | | | | | | |
| 4.4.60 | | | | | | | | X | | | | | | | | |
| 4.4.61 | | | | | | | | X | | | | | | | | |
| 4.4.62 | | | | | | | | X | | | | | | | | |
| 4.4.63 | | | | | | | | X | | | | | | | | |
| 4.4.64 | | | | | | | | X | | | | | | | | |
| 4.4.65 | | | | | | | | X | | | | | | | | |
| 4.4.66 | | | | | | | | X | | | | | | | | |
| 4.4.67 | | | | | | | | X | | | | | | | | |
| 4.4.68 | | | | | | | | X | | | | | | | | |
| 4.4.69 | | | | | | | | X | | | | | | | | |
| 4.4.70 | | | | | | | | X | | | | | | | | |
| 4.4.71 | | | | | | | | X | | | | | | | | |
| 4.4.72 | | | | | | | | X | | | | | | | | |
| 4.4.73 | | | | | | | | X | | | | | | | | |
| 4.4.74 | | | | | | | | X | | | | | | | | |
| 4.4.75 | | | | | | | | X | | | | | | | | |
| 4.4.76 | | | | | | | | X | | | | | | | | |
| 4.4.77 | | | | | | | | X | | | | | | | | |
| 4.4.78 | | | | | | | | X | | | | | | | | |
| 4.4.79 | | | | | | | | X | | | | | | | | |
| 4.4.80 | | | | | | | | X | | | | | | | | |
| 4.4.81 | | | | | | | | X | | | | | | | | |
| 4.5 | | | | | | | | X | | | | | | | | |
| 4.6 | | | | | | | | X | | | | | | | | |
| 4.7 | Indenture (for First Mortgage Bonds) between Duke Energy Florida, Inc. (formerly Florida Power Corporation) and The Bank of New York Mellon (as successor to Guaranty Trust Company of New York and The Florida National Bank of Jacksonville), as Trustee, dated as of January 1, 1944, (incorporated by reference to Exhibit B-18 to registrant's Form A-2, File No. 2-5293). | | | | | | | | | X | | | | | | |
| 4.7.1 | Seventh Supplemental Indenture (incorporated by reference to Exhibit 4(b) to Duke Energy Florida, Inc.'s (formerly Florida Power Corporation) Registration Statement on Form S-3 filed on September 27, 1991, File No. 33-16788). | | | | | | | | | X | | | | | | |
| 4.7.2 | Eighth Supplemental Indenture (incorporated by reference to Exhibit 4(c) to Duke Energy Florida, Inc.'s (formerly Florida Power Corporation) Registration Statement on Form S-3 filed on September 27, 1991, File No. 33-16788). | | | | | | | | | X | | | | | | |
| 4.7.3 | Sixteenth Supplemental Indenture (incorporated by reference to Exhibit 4(d) to Duke Energy Florida, Inc.'s (formerly Florida Power Corporation) Registration Statement on Form S-3 filed on September 27, 1991, File No. 33-16788). | | | | | | | | | X | | | | | | |
| 4.7.4 | Twenty-ninth Supplemental Indenture (incorporated by reference to Exhibit 4(c) to Duke Energy Florida, Inc.'s (formerly Florida Power Corporation) Registration Statement on Form S-3 filed on September 17, 1982, File No. 2-79832). | | | | | | | | | X | | | | | | |
| 4.7.5 | | | | | | | | | | X | | | | | | |
| 4.7.6 | | | | | | | | | | X | | | | | | |
| 4.7.7 | | | | | | | | | | X | | | | | | |
| 4.7.8 | | | | | | | | | | X | | | | | | |
| 4.7.9 | | | | | | | | | | X | | | | | | |
| 4.7.10 | | | | | | | | | | X | | | | | | |
| 4.7.11 | | | | | | | | | | X | | | | | | |
| 4.7.12 | | | | | | | | | | X | | | | | | |
| 4.7.13 | | | | | | | | | | X | | | | | | |
| 4.7.14 | | | | | | | | | | X | | | | | | |
| 4.7.15 | | | | | | | | | | X | | | | | | |
| 4.7.16 | | | | | | | | | | X | | | | | | |
| 4.8 | Indenture (for Debt Securities) between Duke Energy Florida, Inc. (formerly Florida Power Corporation (d/b/a Progress Energy Florida, Inc.)) and The Bank of New York Mellon Trust Company, National Association (successor in interest to J.P. Morgan Trust Company, National Association), as Trustee, dated as of December 7, 2005, (incorporated by reference to Exhibit 4(a) to registrant's Current Report on Form 8-K filed on December 13, 2005, File No. 1-3274). | | | | | | | | | X | | | | | | |
| 4.8.1 | | | | | | | | | | X | | | | | | |
| 4.9 | | | | | | | | | | X | | | | | | |
| 4.10 | | | | | | | | | | | | X | | | | |
| 4.10.1 | | | | | | | | | | | | X | | | | |
| 4.10.2 | | | | | | | | | | | | X | | | | |
| 4.11 | Original Indenture (First Mortgage Bonds) between Duke Energy Ohio, Inc. (formerly The Cincinnati Gas & Electric Company) and The Bank of New York Mellon Trust Company, N.A., as Successor Trustee, dated as of August 1, 1936, (incorporated by reference to an exhibit to registrant's Registration Statement No. 2-2374). | | | | | | | | | | | X | | | | |
| 4.11.1 | | | | | | | | | | | | X | | | | |
| 4.11.2 | | | | | | | | | | | | X | | | | |
| 4.11.3 | | | | | | | | | | | | X | | | | |
| 4.11.4 | | | | | | | | | | | | X | | | | |
| 4.12 | Indenture between Duke Energy Indiana, LLC (formerly PSI Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Successor Trustee, dated as of November 15, 1996, (incorporated by reference to Exhibit 4(v) to the Cinergy Corp. Form 10–K for the year ended December 31, 1996, filed on March 27, 1997, File No. 1–11377). | | | | | | | | | | | | | X | | |
| 4.12.1 | | | | | | | | | | | | | | X | | |
| 4.12.2 | | | | | | | | | | | | | | X | | |
| 4.12.3 | | | | | | | | | | | | | | X | | |
| 4.12.4 | | | | | | | | | | | | | | X | | |
| 4.13 | Original Indenture (First Mortgage Bonds) between Duke Energy Indiana, LLC (formerly PSI Energy, Inc.) and Deutsche Bank National Trust Company, as Successor Trustee, dated as of September 1, 1939, (filed as an exhibit in File No. 70-258). | | | | | | | | | | | | | X | | |
| 4.13.1 | Tenth Supplemental Indenture, dated as of July 1, 1952, (filed as an exhibit in File No. 2-9687). | | | | | | | | | | | | | X | | |
| 4.13.2 | Twenty-third Supplemental Indenture, dated as of January 1, 1977, (filed as an exhibit in File No. 2-57828). | | | | | | | | | | | | | X | | |
| 4.13.3 | Twenty-fifth Supplemental Indenture, dated as of September 1, 1978, (filed as an exhibit in File No. 2-62543). | | | | | | | | | | | | | X | | |
| 4.13.4 | Twenty-sixth Supplemental Indenture, dated as of September 1, 1978, (filed as an exhibit in File No. 2-62543). | | | | | | | | | | | | | X | | |
| 4.13.5 | Thirtieth Supplemental Indenture, dated as of August 1, 1980, (filed as an exhibit in File No. 2-68562). | | | | | | | | | | | | | X | | |
| 4.13.6 | Thirty-fifth Supplemental Indenture, dated as of March 30, 1984, (filed as an exhibit to registrant's Annual Report on Form 10-K for the year ended December 31, 1984, File No. 1-3543). | | | | | | | | | | | | | X | | |
| 4.13.7 | Forty-sixth Supplemental Indenture, dated as of June 1, 1990, (filed as an exhibit to registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 1-3543). | | | | | | | | | | | | | X | | |
| 4.13.8 | Forty-seventh Supplemental Indenture, dated as of July 15, 1991, (filed as an exhibit to registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 1-3543). | | | | | | | | | | | | | X | | |
| 4.13.9 | Forty-eighth Supplemental Indenture, dated as of July 15, 1992, (filed as an exhibit to registrant's Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-3543). | | | | | | | | | | | | | X | | |
| 4.13.10 | | | | | | | | | | | | | | X | | |
| 4.13.11 | | | | | | | | | | | | | | X | | |
| 4.13.12 | | | | | | | | | | | | | | X | | |
| 4.13.13 | | | | | | | | | | | | | | X | | |
| 4.13.14 | | | | | | | | | | | | | | X | | |
| 4.13.15 | | | | | | | | | | | | | | X | | |
| 4.13.16 | | | | | | | | | | | | | | X | | |
| 4.13.17 | | | | | | | | | | | | | | X | | |
| 4.13.18 | | | | | | | | | | | | | | X | | |
| 4.13.19 | | | | | | | | | | | | | | X | | |
| 4.13.20 | | | | | | | | | | | | | | X | | |
| 4.13.21 | Sixty-seventh Supplemental Indenture, dated as of January 1, 2016, between Duke Energy Indiana, Inc. and Deutsche Bank National Trust Company, as Trustee, supplementing and amending the Indenture of Mortgage or Deed of Trust, dated September 1, 1939, between Duke Energy Indiana, Inc. and Deutsche Bank National Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to Duke Energy Indiana, LLC's (formerly PSI Energy, Inc.) Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, filed on May 5, 2016, File No. 1-3543). | | | | | | | | | | | | | X | | |
| 4.13.22 | | | | | | | | | | | | | | X | | |
| 4.14 | Repayment Agreement between Duke Energy Ohio, Inc. (formerly The Cincinnati Gas & Electric Company) and The Dayton Power and Light Company, dated as of December 23, 1992, (filed with registrant's Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1232). | | | | | | | | | | | X | | | | |
| 4.15 | | | | | | | | | | | | | | X | | |
| 4.16 | | | | | | | | | | | | | | X | | |
| 4.17 | | | | | | | | | | | | | | X | | |
| 4.18 | | | | | | X | | | | | | | | | | |
| 4.19 | | | | | | | | | | | | | | | | X |
| 4.20 | | | | | | | | | | | | | | | | X |
| 4.21 | | | | | | | | | | | | | | | | X |
| 4.22 | | | | | | | | | | | | | | | | X |
| 4.23 | | | | | | | | | | | | | | | | X |
| 4.24 | | | | | | | | | | | | | | | | X |
| 4.25 | | | | | | | | | | | | | | | | X |
| 4.26 | |
|
| | | 4.4 | | | | | | | | | | | | X |
| 4.26.1 | | | | | | | | | | | | | | | | X |
| 4.26.2 | | | | | | | | | | | | | | | | X |
| 4.26.3 | | | | | | | | | | | | | | | | X |
| 4.26.4 | | | | | | | | | | | | | | | | X |
| 4.26.5 | | | | | | | | | | | | | | | | X |
| 4.26.6 | | | | | | | | | | | | | | | | X |
| 4.27 | Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8 to registrant's Annual Report on Form 10-K for the fiscal year ended October 31, 1993)1993, File No. 1-06196). |
|
| | | | |
|
| | | 4.5 | | First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.2, Form S-3 Registration Statement No. 33-59369). |
|
| | | 4.6 | | | | | | | | | X |
| 4.28 | |
|
| | | 4.7 | | | | | | | | | | | | X |
| 4.29 | | | | | | | | | | | | | | | | X |
| 4.30 | |
|
| | | 4.8 | | | | | | | | | | | | X |
| 4.31 | |
|
| | | 4.9 | | | | | | | | | | | | X |
| 4.32 | |
|
| | | 4.10 | | Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161). |
|
| | | 4.11 | | | | | | | | | X |
| 4.33 | |
|
| | | 4.12 | | Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (incorporated by reference to Exhibit 4.3, Form S-3 Registration Statement No. 333-106268). |
|
| | | 4.13 | | Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (incorporated by reference to Exhibit 99.2, Form 8-K, dated December 23, 2003). |
|
| | | 4.14 | | Third Supplemental Indenture, dated as of June 20, 2006, between Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.1, Form 8-K dated June 20, 2006). |
|
| | | 4.15 | | | X |
| 4.34 | |
|
| | 4.16 | | Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10, Form 8-K, dated May 12, 2011). |
|
| | 4.17 | | Form of 2.92% Series A Senior Notes due June 6, 2016 (incorporated by reference to Exhibit 4.1, Form 8-K dated May 12, 2011). |
|
| | 4.18 | | Form of 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011). |
|
| | 4.19 | | Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386). |
|
| | | | |
|
| | 4.20 | | Amendment to September 1992 Note Agreement dated as of April 15, 2011 by and between Piedmont Natural Gas Company, Inc., and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 10.3,registrant's Quarterly Report on Form 10-Q for the quarter ended April 30, 2011)2007, filed on June 8, 2007, File No. 1-06196). |
|
| | | 4.21 | | Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto | | | | | | | | | | X |
| 10.1** | Directors’ Charitable Giving Program (incorporated by reference to Exhibit 10.1,10-P to Duke Energy Carolinas, LLC's Annual Report on Form 8-K dated March 29, 2012)10-K for the year ended December 31, 1992, File No. 1-4928). |
|
| | | 4.22X | | Form of 3.47% Series A Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.1, Form 8-K dated March 29, 2012). |
|
| | | 4.23 | | Form of 3.57% Series B Senior Notes due July 16, 2027 (incorporated by reference to Exhibit 4.2, Form 8-K dated March 29, 2012). |
|
| | | 4.24 | | Corporate Commercial Paper Master Note dated March 1, 2012 between U.S. Bank National Association as Paying Agent and Piedmont Natural Gas Company, Inc. as Issuer (incorporated by reference to Exhibit 4.1, Form 10-Q for the quarter ended April 30, 2012). |
|
| | 4.25 |
| Fifth Supplemental Indenture, dated August 1, 2013, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated August 1, 2013). |
|
|
| 4.26 |
| Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013). |
|
| | 4.27 | | Sixth Supplemental Indenture, dated September 18, 2014, between the Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 8-K dated September 18, 2014). |
| | | | | |
| 10.1.1** | | 4.28 | | FormAmendment to Directors’ Charitable Giving Program, dated as of 4.10% Senior Notes due 2034June 18, 1997, (incorporated by reference to Exhibit 4.2,10-1.1 to Duke Energy Carolinas, LLC's Annual Report on Form 8-K dated September 18, 2014)10-K for the year ended December 31, 2003, filed on March 15, 2004, File No. 1-4928). |
| | X | | | | | | | | | | | | |
| 10.1.2** | | 4.29 | | Third Amendment to September 1992 Note Agreement,Directors’ Charitable Giving Program, dated as of OctoberJuly 28, 1997, (incorporated by reference to Exhibit 10-1.2 to Duke Energy Carolinas, LLC's Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2014, between the Company and Provident Life and Accident Insurance Company.2004, File No. 1-4928). |
| |
| X | | | | | Compensatory Contracts: |
|
| | | 10.1 | | Form | | |
| 10.1.3** | Amendment to Directors’ Charitable Giving Program, dated as of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999February 18, 1998, (incorporated by reference to Exhibit 10.54,10-1.3 to Duke Energy Carolinas, LLC's Annual Report on Form 10-K for the fiscal year ended OctoberDecember 31, 1999)2003, filed on March 15, 2004, File No. 1-4928). |
|
| | | 10.2X | | Severance Agreement | | | | | | | | | | |
| 10.2 | | | | X | | | | | | | | | | | | |
| 10.3 | Asset Purchase Agreement between Saluda River Electric Cooperative, Inc., as Seller, and Duke Energy Carolinas, LLC, as Purchaser, dated as of December 20, 2006, (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on December 27, 2006, File No. 1-4928). | | | X | | | | | | | | | | | | |
| 10.4 | | | | X | | | | | | | | | | | | |
| 10.5 | | | | | | | | | | | | | | | | X |
| 10.6 | | | | | | | | | | | | | | | | X |
| 10.7 | | | | | | | | | | | | | | | | X |
| 10.8 | | | | X | | | | | | | | | | | | |
| 10.9 | | | | | | | | | | | | | | | | X |
| 10.10 | Engineering, Procurement and Construction Management Agreement between Duke Energy Indiana, LLC (formerly PSI Energy, Inc.) and Bechtel Power Corporation, dated as of December 15, 2008, (incorporated by reference to Exhibit 10.16 to registrant's Annual Report on Form 10-K for the year ended December 31, 2008, filed on March 13, 2009, File No. 1-3543). (Portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.) | | | | | | | | | | | | | X | | |
| 10.11 | Formation and Sale Agreement between Duke Ventures, LLC, Crescent Resources, LLC, Morgan Stanley Real Estate Fund V U.S. L.P., Morgan Stanley Real Estate Fund V Special U.S., L.P., Morgan Stanley Real Estate Investors V U.S., L.P., MSP Real Estate Fund V, L.P., and Morgan Stanley Strategic Investments, Inc., dated as of September 7, 2006, (incorporated by reference to Exhibit 10.3 to Duke Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed on November 9, 2006, File No. 1-32853). | X | | | | | | | | | | | | | | |
| 10.12 | | X | | | | | | | | | | | | | | |
| 10.13** | | X | | | | | | | | | | | | | | |
| 10.14 | | X | | | | | | | | | | | | X | | |
| 10.15** | | X | | | | | | | | | | | | | | |
| 10.16 | $6,000,000,000 Five-Year Credit Agreement between Duke Energy Corporation, Duke Energy Carolinas, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC, Duke Energy Kentucky, Inc., Carolina Power and Light Company d/b/a Duke Energy Progress, Inc. and Florida Power Corporation, d/b/a Duke Energy Florida, Inc., as Borrowers, the lenders listed therein, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and The Royal Bank of Scotland plc, as Co-Syndication Agents and Bank of China, New York Branch, Barclays Bank PLC, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, Industrial and Commercial Bank of China Limited, New York Branch, JPMorgan Chase Bank, N.A. and UBS Securities LLC, as Co-Documentation Agents, dated as of November 18, 2011, (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on November 25, 2011, File Nos. 1-32853, 1-4928, 1-1232 and 1-3543). | X | | X | | | | | | | | X | | X | | |
| 10.16.1 | Amendment No. 1 and Consent between Duke Energy Corporation, Duke Energy Carolinas, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC, Duke Energy Kentucky, Inc., Duke Energy Progress, Inc., Duke Energy Florida, Inc., and Wells Fargo Bank, National Association, dated as of December 18, 2013, (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on December 23, 2013, File Nos. 1-32853, 1-4928, 1-3382, 1-3274, 1-1232 and 1-3543). | X | | X | | | | X | | X | | X | | X | | |
| 10.16.2 | Amendment No. 2 and Consent between Duke Energy Corporation, Duke Energy Carolinas, LLC, Duke Energy Ohio, Inc., Duke Energy Indiana, LLC, Duke Energy Kentucky, Inc., Duke Energy Progress, Inc., and Duke Energy Florida, Inc., the Lenders party hereto, the issuing Lenders party hereto, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, dated as of January 30, 2015, (incorporated by reference to Exhibit 10.1 of registrant's Current Report on Form 8-K filed on February 5, 2015, File Nos. 1-32853, 1-4928, 1-1232, 1-3543, 1-3382 and 1-3274). | X | | X | | | | X | | X | | X | | X | | |
| 10.16.3 | Amendment No. 3 and Consent, dated as of March 16, 2017, among the registrants, the Lenders party thereto, the issuing Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender (incorporated by reference to Exhibit 10.1 to registrants' Current Report on Form 8-K filed on March 17, 2017, File Nos. 1-32853, 1-04928, 1-03382, 1-03274, 1-01232, 1-03543, 1-06196). | X | | X | | | | X | | X | | X | | X | | X |
| 10.17** | | X | | | | | | | | | | | | | | |
| 10.17.1** | | X | | | | | | | | | | | | | | |
| 10.18** | | X | | | | | | | | | | | | | | |
| 10.19** | | X | | | | | | | | | | | | | | |
| 10.20** | | X | | | | | | | | | | | | | | |
| 10.21** | | X | | | | | | | | | | | | | | |
| 10.22** | | X | | | | | | | | | | | | | | |
| 10.23** | | X | | | | | | | | | | | | | | |
| *10.24** | | X | | | | | | | | | | | | | | |
| 10.25** | | X | | | | | | | | | | | | | | |
| 10.26** | | X | | | | | | | | | | | | | | |
| *10.27* | | X | | | | | | | | | | | | | | |
| 10.28 | | X | | | | | | | | | | | | | | |
| 10.29 | | X | | | | | | | | | | | | | | |
| 10.30** | | X | | | | | | | | | | | | | | |
| 10.31** | | X | | | | | | | | | | | | | | |
| 10.32 | Purchase, Construction and Ownership Agreement, dated as of July 30, 1981, between Duke Energy Progress, Inc. (formerly Carolina Power & Light Company) and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution, dated as of December 16, 1981, changing name to North Carolina Eastern Municipal Power Agency, amending letter, dated as of February 18, 1982, and amendment, dated as of February 24, 1982, (incorporated by reference to Exhibit 10(a) to registrant's File No. 33-25560). | | | | | | | X | | | | | | | | |
| 10.33 | Operating and Fuel Agreement, dated as of July 30, 1981, between Duke Energy Progress, Inc. (formerly Carolina Power & Light Company) and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution, dated as of December 16, 1981, changing name to North Carolina Eastern Municipal Power Agency, amending letters, dated as of August 21, 1981, and December 15, 1981, and amendment, dated as of February 24, 1982, (incorporated by reference to Exhibit 10(b) to registrant's File No. 33-25560). | | | | | | | X | | | | | | | | |
| 10.34 | Power Coordination Agreement, dated as of July 30, 1981, between Duke Energy Progress, Inc. (formerly Carolina Power & Light Company) and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution, dated as of December 16, 1981, changing name to North Carolina Eastern Municipal Power Agency and amending letter, dated as of January 29, 1982, (incorporated by reference to Exhibit 10(c) to registrant's File No. 33-25560). | | | | | | | X | | | | | | | | |
| 10.35 | Amendment, dated as of December 16, 1982, to Purchase, Construction and Ownership Agreement, dated as of July 30, 1981, between Duke Energy Progress, Inc. (formerly Carolina Power & Light Company) and North Carolina Eastern Municipal Power Agency (incorporated by reference to Exhibit 10(d) to registrant's File No. 33-25560). | | | | | | | X | | | | | | | | |
| 10.36** | | | | | | X | | | | | | | | | | |
| 10.37** | | | | | | X | | | | | | | | | | |
| 10.38** | Progress Energy, Inc. Management Change-in-Control Plan, Amended and Restated, effective July 13, 2011, (incorporated by reference to Exhibit 10(d) to registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, filed on November 8, 2011, File Nos. 1-15929, 1-3382 and 1-3274). | | | | | X | | X | | X | | | | | | |
| 10.39 | Precedent and Related Agreements between Duke Energy Florida, Inc. (formerly Florida PowerCorporation d/b/a Progress Energy Florida, Inc. (“PEF”)), Southern Natural Gas Company, FloridaGas Transmission Company (“FGT”), and BG LNG Services, LLC (“BG”), including:a) Precedent Agreement between Southern Natural Gas Company and PEF, dated as ofDecember 2, 2004;b) Gas Sale and Purchase Contract between BG and PEF, dated as of December 1, 2004;c) Interim Firm Transportation Service Agreement by and between FGT and PEF, dated as ofDecember 2, 2004;d) Letter Agreement between FGT and PEF, dated as of December 2, 2004, andFirm Transportation Service Agreement between FGT and PEF to be entered into upon satisfactionof certain conditions precedent;e) Discount Agreement between FGT and PEF, dated as of December 2, 2004;f) Amendment to Gas Sale and Purchase Contract between BG and PEF, dated as of January 28,2005; andg) Letter Agreement between FGT and PEF, dated as of January 31, 2005, (incorporated byreference to Exhibit 10.1 to registrant's Current Report on Form 8-K/A filed on March 15, 2005, FileNos. 1-15929 and 1-3274). (Portions of the exhibit have been omitted and filed separately with theSecurities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.) | | | | | X | | | | X | | | | | | |
| 10.40 | Engineering, Procurement and Construction Agreement between Duke Energy Florida, Inc. (formerly Florida Power Corporation d/b/a/ Progress Energy Florida, Inc.), as owner, and a consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc., as contractor, for a two-unit AP1000 Nuclear Power Plant, dated as of December 31, 2008, (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on March 2, 2009, File Nos. 1-15929 and 1-3274). (Portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.) | | | | | X | | | | X | | | | | | |
| 10.41** | | X | | | | | | | | | | | | | | |
| 10.41.1** | | X | | | | | | | | | | | | | | |
| 10.42** | | X | | | | | | | | | | | | | | |
| 10.43** | | X | | | | | | | | | | | | | | |
| 10.44** | | X | | | | | | | | | | | | | | |
| 10.44.1 | | X | | | | | | | | | | | | | | |
| 10.45 | Agreement between Duke Energy SAM, LLC, Duke Energy Ohio, Inc., Duke Energy Commercial Enterprise, Inc. and Dynegy Resource I, LLC, dated as of August 21, 2014, (incorporated by reference to Exhibit 10.61 to Duke Energy Corporation's Annual Report on Form 10-K for the year ended December 31, 2014, filed on March 2, 2015, File No. 1-32853). | X | | | | | | | | | | X | | | | |
| 10.46 | | X | | | | | | X | | | | | | | | |
| 10.47 | | X | | | | | | | | | | | | | | |
| 10.48 | | X | | | | | | | | | | | | | | |
| 10.49 | | X | | | | | | | | | | | | | | |
| 10.50 | | X | | | | | | | | | | | | | | |
| 10.51 | $1,500,000,000 Amended and Restated Term Loan Agreement among Duke Energy Corporation, as Borrower, the Lenders listed therein, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Administrative Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., Santander Bank, N.A. and TD Bank, N.A., as Joint Lead Arrangers and Bookrunners, dated as of August 1, 2016, (incorporated by reference to Exhibit 10.1 to Duke Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30,2016, filed on August 4, 2016, File No. 1-32853). | X | | | | | | | | | | | | | | |
| 10.52 | | X | | | | | | | | | | | | | | |
| 10.53 | Purchase and Sale Agreement by and among Duke Energy Brazil Holdings II, C.V., Duke Energy International Uruguay Investments SRL, Duke Energy International Group S.à.r.l., Duke Energy International España Holdings SL, Duke Energy International Investments No. 2 Ltd., ISQ Enerlam Aggregator, L.P., and Enerlam (UK) Holdings Ltd., dated as of October 10, 2016, (incorporated by reference to Exhibit 2.2. to registrant's Current Report on Form 8-K filed on October 13, 2016, File No. 1-32853). | X | | | | | | | | | | | | | | |
| 10.54** | | X | | | | | | | | | | | | | | |
| 10.55** | |
| X |
| | | 10.3 | | Schedule of Severance Agreements with Executives (incorporated by reference to Exhibit 10.2a, Form 10-Q for the quarter ended July 31, 2007). |
|
| | | 10.4 | | Piedmont Natural Gas Company, Inc. Incentive Compensation Plan as Amended and Restated Effective December 15, 2010 (incorporated by reference to Appendix A, Form DEF14A dated January 14, 2011). |
|
|
| | | | |
| | | 10.5 | | Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2011). |
|
| | | 10.6 | | Resolution of Board of Directors, June 7, 2013, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2013). |
| |
| 10.56** | | 10.7 | | Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2009). |
|
| | 10.8 | | Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009, (incorporated by reference to Exhibit 10.2 to registrant's Quarterly Report on Form 10-Q for the quarter ended January 31, 2009)2009, filed on March 9, 2009, File No. 1-06196). |
| X |
| | | 10.9 | | Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (incorporated by reference to Exhibit 4.1, Form 8-K dated April 3, 2009). |
|
| | | 10.10 | | Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008 (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2009). |
|
| | | 10.11 | | Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010 (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended July 31, 2010). |
|
| | | 10.12 | | |
| 10.56.1** | |
| X |
| | | 10.13 | | 2011 Retention Award Agreement dated December 15, 2011 between | | | | | | | | | |
| 10.56.2** | | X | | | | | | | | | | | | | | |
| 10.57** | | X | | | | | | | | | | | | | | |
| 10.57.1** | | X | | | | | | | | | | | | | | |
| 10.58** | |
| X |
| | | 10.14 | | Severance | | | | | | | | | |
| 10.59** | | X | | | | | | | | | | | | | | |
| 10.60** | | X | | | | | | | | | | | | | | |
| 10.61** | | X | | | | | | | | | | | | | | |
| 10.62 | | X | | | | | | | | | | | | | | |
| 10.62.1 | | X | | | | | | | | | | | | | | |
| 10.63 | $1,000,000,000 Credit Agreement, dated as of June 14, 2017, among Duke Energy Corporation, the lenders listed therein, The Bank of Nova Scotia, as Administrative Agent, PNC Bank, National Association, Sumitomo Mitsui Banking Corporation and TD Bank, N.A., as C0-Syndication Agents, and Bank of China, New York Branch, BNP Paribas, Santander Bank, N.A. and U.S. Bank National Association, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on June 14, 2017, File No. 1-32853). | X | | | | | | | | | | | | | | |
| 10.64 | $250,000,000 Term Loan Credit Agreement, dated as of June 14, 2017, among Piedmont Natural Gas Company, Inc. the lenders listed therein, U.S. Bank National Association, as Administrative Agent, Branch Banking and Trust Company and Regions Bank, as Co-Syndication Agents and PNC Bank, National Association, as Documentation Agent (incorporated by reference to Exhibit 10.1 to registrant's Current Report on Form 8-K filed on June 14, 2017, File No. 1-06196). | | | | | | | | | | | | | | | X |
| 10.65 | |
|
| | 10.15 | | Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho) (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2012). |
|
| | 10.16 | | Schedule of Amended and Restated Employment Agreements with Executives (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2012). |
|
| | 10.17 | | Amendment to the Piedmont Natural Gas Company Employee Stock Purchase Plan dated September 18, 2012, by Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 10.21, Form 10-K for the fiscal year ended October 31, 2012). |
|
| | 10.18 | | Resolution of Board of Directors, June 6, 2014, establishing compensation for non-management directors (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended July 31, 2014). |
|
|
| | | | |
| | | | Other Contracts: |
|
| | 10.19 | | Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004). |
|
| | 10.20 | | First Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of July 31, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2006). |
|
| | 10.21 | | Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of August 28, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 2006). |
|
| | 10.22 | | Amendment by Written Consent to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 20, 2006, between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 2006). |
|
| | 10.23 | | Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009 (incorporated by reference to Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009). |
|
| | 10.24 | | Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.1, Form 8-K dated August 4, 2009). |
|
| | 10.25 | | Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (incorporated by reference to Exhibit 10.2, Form 8-K dated August 4, 2009). |
|
| | 10.26 | | Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and DealersPurchasers party thereto (incorporated by reference to Exhibit 10.3,10 to registrant's Current Report on Form 10-Q for the quarter ended April 30, 2012)8-K filed on May 12, 2011, File No. 1-06196). |
|
| | | 10.27 | | Amended and Restated Credit Agreement dated as of October 1, 2012 among Piedmont Natural Gas Company, Inc., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and Branch Banking and Trust Company, Bank of America, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each a Lender (incorporated by reference to Exhibit 10.34, Form 10-K for the fiscal year ended October 31, 2012). |
|
| | | 10.28 | | | | | | | | | X |
| 10.66 | |
|
| | | 10.29 | | | | | | | | | | | | X |
| 10.66.1 | First Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of November 9, 2012, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, and Piedmont Constitution Pipeline Company, LLC (incorporated by reference to Exhibit 10.2 to registrant's Quarterly Report on Form 10-Q for the quarter ended January 31, 2013)2013, filed on March 6, 2013, File No. 1-06196). |
|
|
| | | | |
| | | 10.30 | | Confirmation of Forward Sale Transaction dated January 29, 2013, between the Company and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 4, 2013). |
|
| | | 10.31 | | Confirmation of Forward Sale Transaction dated February 19, 2013, between Piedmont Natural Gas Company, Inc., and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 25, 2013). |
|
| | | 10.32 | | | | | | X |
| 10.66.2 | Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1 to registrant's Current Report on Form 8-K filed on September 4, 2013)2013, File No. 1-06196). |
|
| | | 10.33 | | | | | | | | | | | | X |
| 10.67 | |
|
| | | 10.34 | | Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 4, 2013). |
|
| | | 10.35 * | | | | | | | | | X |
| 10.68 | Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. (incorporated by reference to Exhibit 10.35 to registrant's Annual Report on Form 10-K for the year ended October 31, 2014, filed on December 23, 2014, File No. 1-06196). |
|
| | | 12 | | | | | | | | | | | | X |
| *12.1 | |
X |
| | | 21 | | List of Subsidiaries. |
|
| | | 23.1 | | | | | | | | |
| *12.2 | | | | X | | | | | | | | | | | | |
| *12.3 | | | | | | X | | | | | | | | | | |
| *12.4 | | | | | | | | X | | | | | | | | |
| *12.5 | | | | | | | | | | X | | | | | | |
| *12.6 | | | | | | | | | | | | X | | | | |
| *12.7 | | | | | | | | | | | | | | X | | |
| *12.8 | | | | | | | | | | | | | | | | X |
| *21 | | X | | | | | | | | | | | | | | |
| *23.1.1 | |
| X |
| | | 31.1 | | | | | | | | | | | |
| *23.1.2 | | | | X | | | | | | | | | | | | |
| *23.1.3 | | | | | | | | X | | | | | | | | |
| *23.1.4 | | | | | | | | | | X | | | | | | |
| *23.1.5 | | | | | | | | | | | | X | | | | |
| *23.1.6 | | | | | | | | | | | | | | X | | |
| *23.1.7 | | | | | | | | | | | | | | | | X |
| *24.1 | | X | | | | | | | | | | | | | | |
| *24.2 | | X | | | | | | | | | | | | | | |
| *31.1.1 | | X | | | | | | | | | | | | | | |
| *31.1.2 | |
|
| | 31.2 | | CertificationOfficer Pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002. | | | X | | | | | | | | | | | | |
| *31.1.3 | | | | | | X | | | | | | | | | | |
| *31.1.4 | | | | | | | | X | | | | | | | | |
| *31.1.5 | | | | | | | | | | X | | | | | | |
| *31.1.6 | | | | | | | | | | | | X | | | | |
| *31.1.7 | | | | | | | | | | | | | | X | | |
| *31.1.8 | | | | | | | | | | | | | | | | X |
| *31.2.1 | |
| X |
| | | 32.1 | | | | | | | | | | | |
| *31.2.2 | | | | X | | | | | | | | | | | | |
| *31.2.3 | | | | | | X | | | | | | | | | | |
| *31.2.4 | | | | | | | | X | | | | | | | | |
| *31.2.5 | | | | | | | | | | X | | | | | | |
| *31.2.6 | | | | | | | | | | | | X | | | | |
| *31.2.7 | | | | | | | | | | | | | | X | | |
| *31.2.8 | | | | | | | | | | | | | | | | X |
| *32.1.1 | |
X |
| | | 32.2 | | | | | | | | | | | |
| *32.1.2 | |
|
|
| | | | |
| | | 101.INSX | | | | | | | | | | | | |
| *32.1.3 | | | | | | X | | | | | | | | | | |
| *32.1.4 | | | | | | | | X | | | | | | | | |
| *32.1.5 | | | | | | | | | | X | | | | | | |
| *32.1.6 | | | | | | | | | | | | X | | | | |
| *32.1.7 | | | | | | | | | | | | | | X | | |
| *32.1.8 | | | | | | | | | | | | | | | | X |
| *32.2.1 | | X | | | | | | | | | | | | | | |
| *32.2.2 | | | | X | | | | | | | | | | | | |
| *32.2.3 | | | | | | X | | | | | | | | | | |
| *32.2.4 | | | | | | | | X | | | | | | | | |
| *32.2.5 | | | | | | | | | | X | | | | | | |
| *32.2.6 | | | | | | | | | | | | X | | | | |
| *32.2.7 | | | | | | | | | | | | | | X | | |
| *32.2.8 | | | | | | | | | | | | | | | | X |
| *101.INS | XBRL Instance Document |
| X | | 101.SCHX | | X | | X | | X | | X | | X | | X |
| *101.SCH | XBRL Taxonomy Extension Schema Document |
| X | | 101.CALX | | X | | X | | X | | X | | X | | X |
| *101.CAL | XBRL Taxonomy Calculation Linkbase Document |
| X | | 101.DEFX | | X | | X | | X | | X | | X | | X |
| *101.LAB | XBRL Taxonomy Label Linkbase Document | X | | X | | X | | X | | X | | X | | X | | X |
| *101.PRE | XBRL Taxonomy Presentation Linkbase Document | X | | X | | X | | X | | X | | X | | X | | X |
| *101.DEF | XBRL Taxonomy Definition Linkbase Document |
| X | | 101.LABX | | XBRL Taxonomy Extension Label Linkbase |
| X | | 101.PREX | | XBRL Taxonomy Extension Presentation Linkbase |
|
| X | | *X | | Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
|
| X | | Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2014 and 2013; (3) Consolidated Statements of Comprehensive Income for the years ended October 31, 2014, 2013 and 2012; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2014, 2013 and 2012; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2014, 2013 and 2012; and Notes to Consolidated Financial Statements.X |
The total amount of securities of each respective registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10 percent of the total assets of such registrant and its subsidiaries on a consolidated basis. Each registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to it.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
|
| | | |
| DUKE ENERGY CORPORATION (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | Lynn J. Good Chairman, President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | | | | |
| (i) | /s/ LYNN J. GOOD | | | | |
| Lynn J. Good | |
| Chairman, President and Chief Executive Officer (Principal Executive Officer and Director) |
| | |
| (ii) | /s/ STEVEN K. YOUNG | | | | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | | | | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | | |
| (iv) | Directors: | | |
| | | |
| Michael G. Browning* | James B. Hyler, Jr.* | |
| | | |
| Theodore F. Craver, Jr.* | William E. Kennard* | |
| | | |
| Robert M. Davis* | E. Marie McKee* | |
| | | |
| Daniel R. DiMicco* | Charles W. Moorman IV* | |
| | | |
| John H. Forsgren* | Carlos A. Saladrigas* | |
| | | |
| Lynn J. Good* | Thomas E. Skains* | |
| | | |
| John T. Herron* | William E. Webster, Jr.* | |
Steven K. Young, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk (*) pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto. |
| | | | |
| | |
| By: | /s/ STEVEN K. YOUNG |
| Attorney-In-Fact | |
| | | | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 21, 2018
|
| | | |
| DUKE ENERGY CAROLINAS, LLC (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | |
Piedmont Natural Gas Company, Inc. |
| | (Registrant) |
| |
By: | | /s/ Thomas E. Skains |
| | Thomas E. Skains |
| | Chairman of the Board, President |
| | and Lynn J. Good Chief Executive Officer |
| |
Date: | | December 23, 2014 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the datesdate indicated.
|
| | |
| | | |
Signature
(i) | /s/ LYNN J. GOOD | | Title
|
| | Lynn J. Good | |
/s/ Thomas E. Skains | | Chairman of the Board, President and |
Thomas E. Skains | | Chief Executive Officer |
| | (Principal (Principal Executive Officer) |
| | | |
Date: December 23, 2014(ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| | |
/s/ Karl W. NewlinLYNN J. GOOD | | Senior Vice President and |
Karl W. Newlin | | Chief Financial Officer |
| | | (Principal Financial Officer) |
| Lynn J. Good | |
Date: December 23, 2014 | | |
| | /s/ DHIAA M. JAMIL | |
/s/ Jose | Dhiaa M. Simon Jamil | | Vice President and Controller |
Jose M. Simon | | (Principal Accounting Officer) |
| | | |
Date: December 23, 2014 | /s/ LLOYD M. YATES | |
| Lloyd M. Yates | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| PROGRESS ENERGY, INC. (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| | | |
Signature
(i) | /s/ LYNN J. GOOD | |
Title | Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | | |
| (ii) | /s/ E. James BurtonSTEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | Director |
| (iii) | /s/ WILLIAM E. James BurtonCURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| | /s/ LYNN J. GOOD | |
/s/ Malcolm E. Everett III | Lynn J. Good | | Director |
Malcolm E. Everett III | | |
| | |
/s/ Aubrey B. Harwell, Jr. | | Director |
Aubrey B. Harwell, Jr. | JULIA S. JANSON | |
| | |
/s/ Frank B. Holding, Jr. | | Director |
Frank B. Holding, Jr. | Julia S. Janson | |
| | |
/s/ Frankie T. Jones, Sr. | | Director |
Frankie T. Jones, Sr. | | |
| |
/s/ Vicki McElreath | | Director |
Vicki McElreath | | |
| | | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| DUKE ENERGY PROGRESS, LLC (Registrant) | |
| By: | /s/ Minor M. Shaw | | Director |
Minor M. Shaw | |
LYNN J. GOOD |
| | | | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| (i) | /s/ Jo Anne SanfordLYNN J. GOOD | |
| Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | Director |
Jo Anne Sanford(ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| | /s/ DOUGLAS F ESAMANN | |
/s/ David E. Shi | Douglas F Esamann | | Director |
David E. Shi | | |
| | /s/ LYNN J. GOOD | |
/s/ Michael C. Tarwater | Lynn J. Good | | Director |
Michael C. Tarwater | |
|
| | | |
| /s/ Phillip D. WrightDHIAA M. JAMIL | |
Director | Dhiaa M. Jamil | |
Phillip D. Wright | | |
| /s/ JULIA S. JANSON | |
| Julia S. Janson | |
| | |
| /s/ LLOYD M. YATES | |
| Lloyd M. Yates | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 21, 2018 |
| | | |
| DUKE ENERGY FLORIDA, LLC (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| | | Piedmont Natural Gas Company, Inc. |
| (i) | /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | | Form 10-K |
| (ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | | For the Fiscal Year Ended October 31, 2014 |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | | |
| | /s/ DOUGLAS F ESAMANN | Exhibits |
| Douglas F Esamann | |
| | | |
4.29 | /s/ LYNN J. GOOD | |
Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company | Lynn J. Good | |
| | | |
10.35 * | /s/ DHIAA M. JAMIL | |
Limited Liability Company Agreement of Atlantic Coast Pipeline, LLC, dated as of September 2, 2014, by and between Dominion Atlantic Coast Pipeline, LLC, Duke Energy ACP, LLC, Piedmont ACP Company, LLC, and Maple Enterprise Holdings, Inc. | Dhiaa M. Jamil | |
| | | |
12 | /s/ JULIA S. JANSON | | Computation of Ratio of Earnings to Fixed Charges |
| | |
21Julia S. Janson | | List of Subsidiaries |
| |
23.1 | | Consent of Independent Registered Public Accounting Firm |
| |
31.1 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer |
| |
31.2 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer |
| |
32.1 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer |
| |
32.2 | | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer |
| | | |
* | /s/ LLOYD M. YATES | |
| Lloyd M. Yates | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| DUKE ENERGY OHIO, INC. (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | Certain portions of this Exhibit have been omitted pursuant to a request for confidential treatment. The non-public information has been filed separately with the SEC pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| | |
| (i) | /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | |
| (ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| /s/ DOUGLAS F ESAMANN | |
| Douglas F Esamann | |
| | |
| /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| | |
| /s/ DHIAA M. JAMIL | |
| Dhiaa M. Jamil | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| DUKE ENERGY INDIANA, LLC (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| | |
| (i) | /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | |
| (ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| /s/ MELODY BIRMINGHAM-BYRD | |
| Melody Birmingham-Byrd | |
| | |
| /s/ DOUGLAS F ESAMANN | |
| Douglas F Esamann | |
| | |
| /s/ KELLEY A. KARN | |
| Kelley A. Karn | |
Date: February 21, 2018
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| PIEDMONT NATURAL GAS COMPANY, INC. (Registrant) | |
| By: | /s/ LYNN J. GOOD |
| | | Lynn J. Good Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | |
| | |
| (i) | /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| Chief Executive Officer (Principal Executive Officer) |
| | |
| (ii) | /s/ STEVEN K. YOUNG | |
| Steven K. Young | |
| Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
| | |
| (iii) | /s/ WILLIAM E. CURRENS JR. | |
| William E. Currens Jr. | |
| Senior Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) |
| | |
| (iv) | Directors: | |
| | |
| /s/ LYNN J. GOOD | |
| Lynn J. Good | |
| | |
| /s/ FRANKLIN H. YOHO | |
| Franklin H. Yoho | |
| | |
| /s/ DHIAA M. JAMIL | |
| Dhiaa M. Jamil | |
Date: February 21, 2018
