10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2016

or

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina	56-0556998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(Address of principal executive offices)	(Zip Code)

   Registrant’s telephone number, including area code (704) 364-3120

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ¨ No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨	Accelerated filer o
Non-accelerated filer ý (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Description	Shares
Common Stock, no par value	All of the registrant's common stock is directly owned by Duke Energy Corporation as of October 3, 2016.

DOCUMENTS INCORPORATED BY REFERENCE

None

Piedmont Natural Gas Company, Inc. meets the condition set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format permitted by General Instruction I (2) to such Form 10-K.

Piedmont Natural Gas Company, Inc.
2016 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
		Page
Cautionary Statement Regarding Forward-Looking Information
Part I.
Item 1.	Business	4
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Mine Safety Disclosures	11
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder   Matters and Issuer Purchases of Equity Securities	12
Item 6.	Selected Financial Data	12
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results   of Operations	12
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	19
Item 8.	Financial Statements and Supplementary Data	21
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial   Disclosure	84
Item 9A.	Controls and Procedures	84
Item 9B.	Other Information	87
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related   Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	87
Item 14.	Principal Accounting Fees and Services	87
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	88
	Signatures	93

Forward-Looking Statements

This report, including the documents incorporated by reference and other documents that we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management 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:

• 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.

• 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 external 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.

• Changes in our parent's strategy, relationship with us or operating performance.

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.

3

PART I

Item 1. Business

On October 3, 2016, the merger was consummated between Duke Energy Corporation (Duke Energy) and Piedmont Natural Gas Company, Inc. (Piedmont) and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Agreement and Plan of Merger (Merger Agreement) provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. Under the terms of the Merger Agreement, each share of Piedmont common stock issued and outstanding immediately prior to the closing was converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. The merger is being recorded using the acquisition method of accounting. Under Securities and Exchange Commission regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. These adjustments will be recorded by Duke Energy. Unless the context requires otherwise, references to "we," "us," "our," "the Company" or "Piedmont" means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

Piedmont is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation businesses.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. In Tennessee, our service area is the metropolitan area of Nashville.

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt securities. We are also subject to various federal regulations that affect our regulated utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that 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 U.S. Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency (EPA) relating to the environment, including proposed air emissions regulations that would expand to include emissions of methane. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices that are generally applicable to companies doing business in the United States of America.

The following table summarizes certain components underlying our approved and effective base rates for each regulatory jurisdiction during 2016.

(in millions)	Rate Base		Return on Equity	Equity Component of Capital Structure	Effective Date
2013 North Carolina Rate Proceeding	$	1,822.4	10.0%	50.7%	January 2014
2015 South Carolina Rate Stabilization Adjustment Filing (1)	224.2		10.2%	55.0%	November 2015
2011 Tennessee Rate Proceeding	348.9		10.2%	52.7%	March 2012
(1) Under the rate stabilization adjustment (RSA) mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis.

Our sole reportable operating segment is Gas Utilities and Infrastructure, which encompasses local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. See Note 11 "Investments in Unconsolidated Affiliates" and Note 13 "Business Segments" to the Consolidated Financial Statements in this Form 10-K for further information on our investments.

4

Effective November 1, 2016, Piedmont's fiscal year end has been changed from October 31 to December 31. As a result, we expect to file a Form 10-QT covering the transition period from October 31 to December 31 in early 2017.

Item 1A. Risk Factors

Market Risks

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.

Our business is subject to competition that could negatively affect our results of operations.

The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane 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 and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our 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 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 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.

5

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, our results of operations, earnings or cash flows could vary and be negatively impacted.

Commercial Risks

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.

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.

Our business activities are concentrated in three states.

We are a regulated utility under the jurisdiction of three state regulatory bodies. 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 are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.

We may not be able to complete necessary or desirable pipeline expansion or infrastructure development or maintenance projects, which may delay or prevent us from serving our customers or expanding our business.

In order to serve current or new customers or expand our service to existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. 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, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, or could result in higher than anticipated cost, both of which would negatively impact our earnings.

6

Financial and Corporate Structure Risks

A downgrade in our, Duke Energy's, and other Duke Energy registrants' credit ratings could negatively affect our cost of and ability to access capital.

Our ability to obtain adequate and cost effective financing depends in part on our credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. A negative change in Duke Energy's or other Duke Energy registrants' ratings outlook or any downgrade in credit ratings could negatively impact our ratings outlook or downgrade our credit ratings. Such downgrades could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement and unsecured 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 or cash flows 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, which would result in higher expense and could adversely impact liquidity. As a subsidiary of Duke Energy, we also may become a party to Duke Energy's master credit facility or rely on access to short-term intercompany borrowings. 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, require us to reduce or eliminate distributions to our parent or other discretionary uses of cash or could negatively affect our future growth or earnings. 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.

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 may continue to pursue other similar investments, all of which are and will be important to our growth and profitability as a subsidiary of Duke Energy. 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. Our dependency 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, 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.

7

The cost of providing pension benefits and related funding obligations may increase.

Our costs of providing a non-contributory defined benefit pension plan are dependent on 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, future government regulation, changes in life expectancy and our required or voluntary contributions made to the plan. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, could increase the expense of our pension plan, and we could be required to fund our plan with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing cash flows and could negatively affect results of operations.

As a wholly owned subsidiary of Duke Energy, we are affected by Duke Energy's strategic decisions and operating performance.

As a wholly owned subsidiary of Duke Energy, our business and operating performance can be affected by a wide range of strategic decisions that Duke Energy may make from time to time. Additionally, we rely on Duke Energy to provide corporate services and support, such as accounting, information technology and legal. Significant changes in Duke Energy's strategy, its relationship with Piedmont or its provision of support services as well as material adverse changes in the performance of Duke Energy could have a material adverse effect on Piedmont.

Regulatory Risks

Elevated levels of capital expenditures may weaken our financial position and inhibit customer growth.

We make significant annual capital expenditures for system integrity, infrastructure and maintenance that do not immediately produce revenue. We have the ability to recover these costs either through general rate cases or alternative rate mechanisms approved by state regulatory commissions, such as RSAs and integrity management riders (IMRs), that periodically adjust rates to reflect incurred capital expenditures. However, before rates are adjusted, we fund construction through operating 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 from 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.

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 utility operations are 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 costs and a reasonable return, or significantly lowers our allowed return or negatively alters our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, or prohibits recovery of regulatory assets, including deferred gas costs.

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 been 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 access natural gas supply through their own connection to an interstate pipeline. If regulators

8

decided to discontinue allowing us to use these tariff mechanisms, it would negatively impact our results of 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 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.

We are subject to new and existing laws and regulations that may require significant expenditures, significantly increase operating costs, or significant fines or penalties for noncompliance.

Our business and operations are subject to regulation by the FERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to numerous federal and state laws and regulations. Compliance with existing or new laws and regulations may 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 some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1.0 million per day for each violation. As the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of these events could result in a material adverse effect on our business, results of operations or financial condition.

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 requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could 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.

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 earnings and cash flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce other discretionary uses of cash, and could negatively affect earnings.

Operational Risks

The operation of our gas distribution and transmission activities may be interrupted by accidents, work stoppage, severe weather conditions, including destructive weather patterns, such as hurricanes, tornadoes and floods, pandemic or acts of terrorism and sabotage.

Inherent in our gas distribution and transmission activities, including natural gas and liquefied natural gas storage,

9

are a variety of hazards and operational risks, such as third-party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism and sabotage, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result in 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 increase 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 our financial position, results of operations and cash flows.

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, make compliance filings 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. In recent years, cybersecurity risks have increased due in part to the increased sophistication and frequency of the attacks.

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, property and cyber 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 our financial position, results of operations and cash flows.

10

Strategic Risks

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, all of which are regulated by either a state commission or the FERC. 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. 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 on 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The majority of property included in the Consolidated Balance Sheets in "Cost" in "Property, Plant and Equipment" is owned by us and used in our utility operations. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,880 linear miles 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 22,800 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties are located in North Carolina, South Carolina and Tennessee. Our utility plant includes construction work in progress, which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion. The classification of our "Property, Plant and Equipment" is detailed in Note 1 "Summary of Significant Accounting Policies" to the Consolidated Financial Statements in this Form 10-K.

None of our property is encumbered, and all property is in use except for "Plant held for future use" included in "Cost" within "Property, Plant and Equipment" as detailed in Note 1 "Summary of Significant Accounting Policies" 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 $4.8 million for the year ended October 31, 2016.

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.

11

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

On October 3, 2016, we consummated the merger with Duke Energy Corporation (Duke Energy) and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Agreement and Plan of Merger (Merger Agreement) provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). Each share of Piedmont’s issued and outstanding common stock was canceled, and each share of Merger Sub’s issued and outstanding capital stock was converted into one share of no par value common stock for a total of 100 shares issued. As a result of the Acquisition, there is no longer a market for Piedmont’s common stock.

Dividends

Under our senior note agreements, 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. Dividends are now paid to our parent,

Duke Energy.

Item 6. Selected Financial Data

Information for this item has been omitted as Piedmont Natural Gas Company, Inc. is a wholly owned subsidiary of Duke Energy and afforded relief under General Instruction I (2)(a) of such Form 10-K.

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

Overview

On October 3, 2016, the Acquisition was consummated as discussed above. Under the terms of the Merger Agreement, each share of Piedmont common stock issued and outstanding immediately prior to the closing (other than shares owned by Duke Energy or its wholly owned subsidiaries) was converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. The Acquisition was recorded using the acquisition method of accounting. Under Securities and Exchange Commission regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. These adjustments will be recorded by Duke Energy.

Management's Discussion and Analysis should be read in conjunction with the accompanying Consolidated Financial Statements and Notes for the years ended October 31, 2016, 2015 and 2014.

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. As a result of the Acquisition, there were no changes in accounting principles and practices or method of application that had a material effect on net income as reported for the year ended October 31, 2016. See Note 1 "Summary of Significant Accounting Policies" to the Consolidated Financial Statements in this Form 10-K for a discussion of our policies.

Results of Operations

Regulated margin, rather than revenues, is one of the financial measures used by management to evaluate utility operations due to the regulatory pass through of changes in wholesale gas costs. Our regulated 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 recover our utility operating expenses and our return of and on our utility capital investments and related taxes.

In general rate proceedings, state regulatory commissions authorize us to recover our regulated margin in our fixed monthly 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

12

agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers.

Management views regulated margin as more representative of the overall economic result than other comparable measures based on the items noted above and uses this measure to compare results against established benchmarks. This non-generally accepted accounting principles (GAAP) financial measure is not in accordance with, or an alternative to, GAAP. A reconciliation of margin to Operating Income, which is the most directly comparable GAAP measure, is presented below.

	Years Ended October 31,
(in millions)	2016		2015		Variance
Regulated natural gas operating revenues	$	1,131.6	$	1,371.7	$	(240.1	)
Related party revenue from Duke Energy	7.0				7.0
Cost of natural gas	390.5		644.4		(253.9		)
Regulated margin	748.1		727.3		20.8
Nonregulated and other operating revenues	10.1		11.4		(1.3		)
Operations, maintenance and other	352.9		304.8		48.1
Depreciation and amortization	137.3		128.7		8.6
Property and other taxes	42.6		42.4		0.2
Operating Income	225.4		262.8		(37.4		)
Other Income (Expense), net	160.6		33.0		127.6
Interest Expense	68.6		68.6		—
Income Before Income Taxes	317.4		227.2		90.2
Income Tax Expense	124.2		90.2		34.0
Net Income	$	193.2	$	137.0	$	56.2

Further summaries of our annual results are as follows.

Regulated Margin by Customer Class
(in millions)	2016				2015
Sales and Transportation:
Residential	$	397.0	53	%	$	376.6	52	%
Commercial	189.3		25	%	181.6		25	%
Industrial	51.4		7	%	49.9		7	%
Power Generation	77.1		10	%	77.2		10	%
For Resale	11.7		2	%	12.5		2	%
Total	726.5		97	%	697.8		96	%
Secondary Market Sales	17.7		2	%	21.1		3	%
Miscellaneous	3.9		1	%	8.4		1	%
Total	$	748.1	100	%	$	727.3	100	%

13

Gas Deliveries, Customers, Weather Statistics and Number of Employees
					Percent
	2016		2015		Change
Deliveries in Dekatherms (in millions):
Residential	48.1		61.0		(21.1	)%
Commercial	38.3		44.6		(14.1	)%
Industrial	95.9		96.4		(0.5	)%
Power Generation	296.5		262.2		13.1	%
For Resale	6.3		7.3		(13.7	)%
Throughput	485.1		471.5		2.9	%
Secondary Market Volumes	61.3		30.8		99.0	%
Customers Billed (at period end)	1,026,466		1,011,959		1.4	%
Gross Residential, Commercial and Industrial Customer Additions	17,328		17,017		1.8	%
Degree Days
Actual	2,583		3,449		(25.1	)%
Normal	3,265		3,257		0.2	%
Percent (warmer) colder than normal	(20.9	)%	5.9	%	n/a
Number of Employees (at period end)	1,971		1,943		1.4	%

Operating Revenues - Regulated Natural Gas

The change in "Regulated natural gas" operating revenues for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Residential and commercial customers	$	(271.6	)
Industrial customers	(6.5		)
Power generation customers	(0.5		)
Secondary market	(62.0		)
Margin decoupling mechanism	58.5
WNA mechanisms	22.3
IMR mechanisms	27.2
Other	(0.5		)
Total	$	(233.1	)

• Residential and commercial customers – the decrease is due to lower consumption from warmer weather and lower wholesale gas costs passed through to customers, slightly offset by customer growth.

• Industrial customers – the decrease is primarily due to lower wholesale gas costs and lower volumes from warmer weather.

• Secondary market – the decrease is due to lower margin sales prices, partially offset by increased volumes. Secondary market transactions consist of off-system sales and capacity release and asset management arrangements that are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and us. Effective October 3, 2016 as a result of the Acquisition, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers.

• Margin decoupling mechanism – the increase is primarily related to warmer weather in North Carolina as compared to the prior period. The margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.

• Weather normalization adjustment (WNA) mechanisms – the increase is primarily related to warmer weather in South Carolina and Tennessee as compared to the prior period. The WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

14

• IMR mechanisms – the increase is due to the integrity management rider (IMR) rate adjustments in Tennessee, effective in January 2015 and 2016, and North Carolina, effective in February 2015, December 2015 and June 2016.

Cost of Natural Gas

The change in "Cost of natural gas" for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Commodity gas costs passed through to sales customers	$	(161.4	)
Commodity gas costs in secondary market transactions	(58.6		)
Pipeline demand charges	0.2
Regulatory approved gas cost mechanisms	(34.1		)
Total	$	(253.9	)

• Commodity gas costs passed through to sales customers – the decrease is primarily due to lower wholesale gas costs passed through to sales customers and lower consumption due to warmer weather, slightly offset by customer growth.

• Commodity gas costs in secondary market transactions – the decrease is primarily due to lower average wholesale gas costs, partially offset by increased volumes.

• Regulatory approved gas cost mechanisms – the decrease is primarily due to a decrease in commodity cost and demand true-ups, partially offset by other regulatory mechanisms.

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 in current "Regulatory assets" or current "Regulatory liabilities" in the Consolidated Balance Sheets and are added to or deducted from cost of natural gas. See Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K for the amounts included in "Amounts due from customers" or "Amounts due to customers."

Regulated Margin

Our utility regulated margin is impacted by certain regulatory mechanisms. 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 programs **	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. Effective October 3, 2016, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million.

Our commodity gas costs accounted for 25% of revenues for the year ended October 31, 2016 and 35% for the year ended October 31, 2015. Our pipeline transportation and storage costs accounted for 12% for the year ended October 31, 2016 and 10% for the year ended October 31, 2015.

15

The change in regulated margin for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Residential and commercial customers	$	28.2
Industrial customers	0.6
Power generation customers	(0.1		)
Secondary market activity	(3.4		)
Net gas cost adjustments	(4.5		)
Total	$	20.8

• Residential and commercial customers – the increase is primarily due to IMR rate adjustments in Tennessee and North Carolina, both effective as stated above, and customer growth in all three states.

• Secondary market activity – the decrease is primarily due to lower margin sales, partially offset by increased volumes.

• Net gas cost adjustments – the decrease is due to North Carolina customer bill credits applied in October 2016 in compliance with the North Carolina Utilities Commission (NCUC) order approving the Acquisition.

Operations, Maintenance and Other

The change in "Operations, maintenance and other" for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Acquisition and integration-related expenses	$	53.0
Contract labor	1.9
Employee benefits	(3.1		)
Payroll	(1.2		)
Other	(2.5		)
Total	$	48.1

• Acquisition and integration-related expenses – the increase is due to increased costs paid to outside parties, primarily financial and legal advisory costs, severance costs, retention and acceleration of incentive plans, and an accrual for our commitment of charitable contributions and community support. See Note 2 "Acquisition by Duke Energy Corporation" to the Consolidated Financial Statements in this Form 10-K for further information on these expenses.

• Contract labor – the increase is primarily due to the utilization of third parties for operations projects, legal and training design, partially offset by capitalization of contract labor related to accounting software implementation.

• Employee benefits – the decrease is primarily due to lower defined benefit plan accruals related to changes in actuarial assumptions.

• Payroll – the decrease is primarily related to incremental expense from the accelerated vesting and payment of incentive awards under provisions in the Merger Agreement being reflected in "Acquisition and integration-related expenses" above, partially offset by merit increases.

Depreciation and Amortization

Depreciation and amortization expense increased $8.6 million from 2015 to 2016 primarily due to increases in plant in service, particularly related to major additions in transmission integrity investments and natural gas system infrastructure.

16

Other Income and Expense

The change in "Other Income and Expense" for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Equity in earnings of unconsolidated affiliates
Constitution Pipeline Company LLC (Constitution)	$	(7.5	)
Atlantic Coast Pipeline, LLC (ACP)	2.3
Other	(0.7		)
Total	(5.9		)
Gain on sale of unconsolidated affiliates	132.8
Other expense, net	0.7
Total	$	127.6

• Equity in earnings of unconsolidated affiliates from Constitution – the decrease is primarily due to the discontinued capitalization of ongoing expenditures.

• Equity in earnings of unconsolidated affiliates from ACP – the increase is primarily due to higher capitalized interest costs.

• Gain on sale of unconsolidated affiliates – the increase was due to the gain on the sale of our 15% ownership interest in SouthStar Energy Services, LLC (SouthStar). See Note 11 "Investments in Unconsolidated Affiliates" to the Consolidated Financial Statements in this Form 10-K for further information on this transaction.

Interest Expense

The change in "Interest Expense" for 2016 compared with 2015 is presented below.

	Increase
(in millions)	(Decrease)
Regulatory interest expense, net	$	(7.3	)
Borrowed AFUDC	(1.2		)
Interest expense on long-term debt	7.2
Interest expense on short-term debt	1.3
Total	$	—

• Regulatory interest expense, net – the change is primarily due to interest income on net amounts due from customers compared with interest expense in the prior period on net amounts due to customers.

• Borrowed allowance for funds used during construction (AFUDC) – the decrease is due to increased capitalized interest from higher capital expenditures.

• Interest expense on long-term debt – the increase is primarily due to higher amounts of outstanding debt in the current period.

• Interest expense on short-term debt – the increase is primarily due to higher average interest rates of 34 basis points over the prior period on higher average daily borrowings.

Income Tax Expense

The change in "Income Tax Expense" for 2016 compared with 2015 of $34.0 million is primarily due to higher pre-tax income, partially offset by a lower effective tax rate of 39.1% compared to 39.7% for the years ended October 31, 2016 and 2015, respectively. The decrease in the effective tax rate is primarily due to a reduction in income tax expense of $2.2 million related to the portion of the Tennessee rate decrement implemented to refund excess deferred income taxes to customers in Tennessee, as discussed in Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K and a decrease in the North Carolina income tax rate as discussed in Note 10 "Income Taxes" to the Consolidated Financial Statements in this Form 10-K, partially offset by an increase in merger related permanent differences.

17

Matters Impacting Future Results

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. 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 order to provide additional diversification, reliability and gas cost benefits to our customers, we have long-term supply and capacity contracts to buy and transport more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These competitive long-term sources of gas supply became available during the winter 2015 – 2016 season via the Williams – Transco Leidy Southeast expansion project and its Virginia Southside expansion project and substantially replaced other sources of gas within our supply portfolio, supporting our supply diversification strategy. Additional gas supplies from diverse eastern gas supply basins are anticipated to be available under a long-term pipeline capacity firm transportation agreement with ACP upon completion of the project in late 2019.

Customer Growth – We have added over 17,300 new customers in our service areas during the year ended October 31, 2016, an increase of 1.8%. Affordable and stable wholesale natural gas costs continue to favorably position natural gas relative to other energy sources. Continued targeted marketing programs on the benefits of natural gas should help us to sustain growth comparable to prior years. Residential conversion growth decreased compared to demand for residential new home construction, impacting growth in these markets during the current period as compared to the same prior period.

We forecast gross customer growth of approximately 1.6 – 2.0% for fiscal 2017. Overall, total net customers billed increased 1.4% as compared to 2015.

IMR – We continue to incur significant capital costs under our ongoing system integrity programs. We have IMR regulatory mechanisms in North Carolina and Tennessee that separately track and recover certain costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity programs, as well as additional state safety and integrity requirements in Tennessee. The IMR orders by jurisdiction and the amount reflected in "Operating Revenues" in the Consolidated Statements of Operations and Comprehensive Income for 2016 and 2015 are summarized below.

(in millions)	North Carolina			Tennessee
Incremental annual margin revenue - 2014 IMR filing	$	1.0	(1)	$	13.1
Incremental annual margin revenue - 2015 IMR filing	24.4		(1)	6.5
Incremental annual margin revenue - 2016 IMR filing	22.9		(2)	1.7
Total cumulative incremental annual margin revenue in 2016 (3)	$	48.3	(1)	$	21.3
Amounts recorded as revenues during fiscal year 2016	$	41.5		$	20.9
Amounts recorded as revenues during fiscal year 2015	17.1			18.2
(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC Public Staff under the approved IMR settlement agreement and procedural schedule, which may differ from the amounts reflected in the filed and approved rate adjustments. See Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K for further information on the IMR settlement agreement.
(2) Amount reflects additional annual margin revenues of $15.5 million effective December 1, 2015 and $7.4 million effective June 1, 2016 as approved by the NCUC.
(3) IMR recovery period in both jurisdictions does not align with our fiscal year. See Note 3 "Regulatory Matters" to the Consolidated Financial Statements in this Form 10-K for further information on the recovery periods.

Equity Method Investments – In accordance with the SouthStar limited liability company agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to Georgia Natural Gas Company (GNGC), a wholly owned subsidiary of Southern Company. On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective upon the consummation of the Acquisition. On October 3, 2016, we sold our 15% interest in SouthStar, and at closing, we received $160.0 million from GNGC resulting in a pre-tax gain of $132.8 million, classified as "Gain on sale of unconsolidated affiliates" on the Consolidated Statements of Operations and Comprehensive Income.

Also on October 3, 2016, in connection with the consummation of the Acquisition, Dominion Resources, Inc. purchased 3% of our 10% membership interest in ACP at book value for $13.9 million. As a result of the transfer, our interest in ACP was reduced to 7%.

We are a 24% equity member of Constitution that plans to transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. On April 22, 2016, the New York State Department of Environmental Conservation

18

(NYSDEC) denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution has filed legal actions in the U.S District Court for the Northern District of New York and 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. Both courts have granted Constitution's motions to expedite the schedules for the legal actions. On November 16, 2016, oral arguments were heard in the U.S Court of Appeals.

In July 2016, Constitution requested and the Federal Energy Regulatory Commission (FERC) approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. On November 22, 2016, the FERC denied the NYAG's request for reconsideration of this order.

Constitution has revised its target in-service date as early as the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded. Failure to ultimately obtain the necessary permit could result in recording a non-cash impairment charge of substantially all of our investment in the capitalized project costs. Our investment totaled $93.1 million as of October 31, 2016, the write-off of which could materially adversely impact our earnings.

With the project on hold, our funding of project costs is on hold until the resolution of the legal actions. We are contractually obligated to provide funding of required operating costs, including our ownership percentage of legal expenses to obtain the necessary permitting for the project and project costs incurred prior to the denial of the water permit. We expect significantly reduced earnings from the Constitution investment to continue into 2017 until resolution of the legal and regulatory actions. If the legal actions result in the most severe outcome where the project is abandoned, Constitution is obligated under various contracts to pay breakage fees that we would be obligated to fund up to our ownership percentage of 24%, or potentially up to approximately $10.0 million.

Integration Costs – We expect to incur system integration and other merger-related transition costs, primarily through 2019, that are necessary to achieve certain anticipated cost savings, efficiencies and other benefits by Duke Energy.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk, weather risk and marketable securities risk associated with the assets of our qualified pension and other postretirement employee benefits (OPEB) plans. We seek to identify, assess, monitor and manage all of these risks in accordance with established comprehensive risk management policies. As a Duke Energy subsidiary registrant, Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of the market risk management policies and the delegation of approval and authorization levels that apply to Piedmont. The Finance and Risk Management Committee of Duke Energy's Board of Directors receives periodic updates from Duke Energy's Chief Risk Officer and other members of management on market risk positions, corporate exposures, and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits.

We hold all financial instruments discussed below for purposes other than trading.

Credit Risk

We enter into contracts with third parties to buy and sell natural gas. 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, the 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.

19

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 purchase gas adjustment (PGA) procedures. 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 or colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2016, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level 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, 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, 2016, we had $145.0 million of short-term debt outstanding as commercial paper at an interest rate of .63%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $3.8 million during 2016.

As of October 31, 2016, information about our long-term debt is presented below.

																						Fair Value as
	Expected Maturity Date																					of October 31,
(in millions)	2017			2018			2019			2020			2021			Thereafter			Total			2016
Fixed Rate Long-term Debt	$	35.0		$	—		$	—		$	—		$	160.0		$	1,640.0		$	1,835.0		$	2,061.2
Average Interest Rate	8.51		%	—		%	—		%	—		%	4.24		%	4.60		%	4.64		%

Commodity Price Risk

We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that 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, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in "Amounts due from customers" in "Current Regulatory Assets" or any over-recoveries are included in "Amounts due to customers" in "Current Regulatory Liabilities" as presented in Note 3 "Regulatory Matters" 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 due to customers," we incur a carrying charge that we must refund to our customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course 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 substantially all of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier's default would have a material effect on our financial position, results of operations or cash flows.

20

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. We are responsible for following competitive and reasonable practices in purchasing gas for our customers. Costs have never been disallowed on the basis of prudence in any jurisdiction.

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. This risk is mitigated by a WNA mechanism designed to offset 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 regulated margin is collected through volumetric rates in all of our jurisdictions.

Marketable Securities Price Risk of Benefit Plan Assets

We maintain investments to facilitate funding the costs of providing noncontributory defined benefit retirement and OPEB plans. These investments are exposed to price fluctuations in equity markets and changes in interest 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. We have established asset allocation targets for our 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.

A significant decline in the value of plan asset holdings could require us to increase funding of our 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 our results of operations in those periods.

Item 8. Financial Statements and Supplementary Data

Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV of this Form 10-K.

21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM    

To the Board of Directors of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the "Company") (a wholly owned subsidiary of Duke Energy Corporation) as of October 31, 2016 and 2015, and 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 October 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 22, 2016

22

Consolidated Statements of Operations and Comprehensive Income

	Years Ended October 31,
(in millions)	2016			2015			2014
Operating Revenues
Regulated natural gas (1)	$	1,131.6		$	1,371.7		$	1,470.0
Nonregulated and other	10.1			11.4			9.5
Related party revenue from Duke Energy (2)	7.0
Total operating revenues	1,148.7			1,383.1			1,479.5
Operating Expenses
Cost of natural gas (1)	390.5			644.4			779.8
Operations, maintenance and other	352.9			304.8			279.9
Depreciation and amortization	137.3			128.7			119.0
Property and other taxes	42.6			42.4			37.7
Total operating expenses	923.3			1,120.3			1,216.4
Operating Income	225.4			262.8			263.1
Other Income and Expense
Equity in earnings of unconsolidated affiliates	28.6			34.5			32.8
Gain on sale of unconsolidated affiliates	132.8			—			—
Other expense, net	0.8			1.5			2.6
Total other income and expense	160.6			33.0			30.2
Interest Expense	68.6			68.6			54.7
Income Before Income Taxes	317.4			227.2			238.6
Income Tax Expense	124.2			90.2			94.8
Net Income	193.2			137.0			143.8
Other Comprehensive Income (Loss), net of tax
Unrealized (loss) gain from hedging activities, net of tax of ($2.5), ($1.0) and $0.2 for the years ended October 31, 2016, 2015 and 2014, respectively	(2.8		)	(1.6		)	0.3
Reclassification adjustment of realized loss (gain) from hedging activities of equity method investments included in net income, net of tax of $2.0, $0.7 and ($0.2) for the years ended October 31, 2016, 2015 and 2014, respectively	3.4			1.0			(0.3		)
Other Comprehensive Income (Loss), net of tax	0.6			(0.6		)	—
Comprehensive Income	$	193.8		$	136.4		$	143.8
(1) See Note 11 for amounts attributable to investments in unconsolidated affiliates.
(2) See Note 14 for details on related party transactions with Duke Energy.
See Notes to Consolidated Financial Statements.

23

Consolidated Balance Sheets

	October 31,
(in millions)	2016			2015
ASSETS
Current Assets
Cash and cash equivalents	$	16.6		$	13.7
Receivables (less allowance for doubtful accounts of $1.9 in 2016 and $1.6 in 2015)	75.2			86.9
Receivables from affiliated companies (1)(2)	7.0			0.2
Inventory	55.6			69.5
Regulatory assets	113.7			19.1
Prepaids	27.2			28.9
Other	12.0			12.8
Total current assets	307.3			231.1
Investments and Other Assets
Investments in equity method unconsolidated affiliates	199.2			207.0
Goodwill	48.9			48.9
Other	10.9			53.1
Total investments and other assets	259.0			309.0
Property, Plant and Equipment
Cost	6,079.1			5,601.3
Accumulated depreciation and amortization	(1,329.5		)	(1,252.9		)
Net property, plant and equipment	4,749.6			4,348.4
Regulatory Assets and Deferred Debits
Regulatory assets	373.3			196.7
Other	1.8			1.1
Total regulatory assets and deferred debits	375.1			197.8
Total Assets	$	5,691.0		$	5,086.3
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	130.5		$	120.3
Accounts payable to affiliated companies (1)(2)	8.7			2.5
Notes payable and commercial paper	145.0			340.0
Taxes accrued	68.4			30.3
Interest accrued	29.3			29.5
Current maturities of long-term debt	35.0			40.0
Regulatory liabilities	—			21.5
Gas supply derivative liabilities, at fair value	41.5			—
Other	61.7			59.3
Total current liabilities	520.1			643.4
Long-Term Debt	1,786.0			1,523.7
Deferred Credits and Other Liabilities
Deferred income taxes	904.1			829.2
Investment tax credits	0.9			1.0
Accrued pension and other post-retirement benefit costs	23.4			15.1
Asset retirement obligations	14.1			19.7
Regulatory liabilities	617.0			590.3
Other	180.5			37.6
Total deferred credits and other liabilities	1,740.0			1,492.9
Commitments and Contingencies
Equity
Common stock, no par value: 100 shares authorized and outstanding in 2016 and 200.0 million authorized and 80.9 million outstanding in 2015	859.8			721.4
Retained earnings	785.3			705.7
Accumulated other comprehensive loss	(0.2		)	(0.8		)
Total equity	1,644.9			1,426.3
Total Liabilities and Equity	$	5,691.0		$	5,086.3
(1) See Note 11 for amounts attributable to investments in unconsolidated affiliates.
(2) See Note 14 for details on related party transactions with Duke Energy.
See Notes to Consolidated Financial Statements.

24

Consolidated Statements of Cash Flows

	Years Ended October 31,
(in millions)	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITES
Net income	$	193.2		$	137.0		$	143.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	148.3			140.2			129.3
Provision for doubtful accounts	4.9			5.1			7.0
Impairment charges	—			—			2.0
Net gain on sale of property	—			—			(0.8		)
Net gain on sale of interests in unconsolidated affiliates, net of tax	(80.9		)	—			—
Deferred income taxes, net	74.2			73.0			87.2
Equity in earnings of unconsolidated affiliates	(28.6		)	(34.5		)	(32.8		)
Distributions of earnings from unconsolidated affiliates	25.8			24.9			24.8
Accrued/deferred postretirement benefit costs	12.4			2.2			5.9
Contributions to benefit plans	(14.0		)	(12.7		)	(22.5		)
Settlement of legal asset retirement obligations	(6.4		)	(5.6		)	(3.5		)
(Increase) decrease in:
Receivables, net	6.9			(2.6		)	9.7
Receivables from affiliated companies	(7.0		)
Inventory	13.9			16.3			(10.1		)
Regulatory assets	(291.6		)	(24.0		)	21.2
Other current assets	2.4			38.4			(12.0		)
Increase (decrease) in:
Accounts payable	6.2			(5.1		)	(4.7		)
Accounts payable to affiliated companies	6.3
Taxes accrued	(13.7		)	3.8			3.6
Gas supply derivatives, at fair value	187.9			—			—
Other current liabilities	(13.5		)	(20.5		)	51.1
Other assets	58.2			7.4			20.7
Other liabilities	23.5			28.3			10.7
Net cash provided by operating activities	308.4			371.6			430.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(521.8		)	(443.7		)	(460.5		)
Allowance for borrowed funds used during construction	(12.3		)	(11.1		)	(16.4		)
Investment expenditures	(47.4		)	(29.7		)	(37.6		)
Distributions of capital from unconsolidated affiliates	18.0			1.5			3.9
Net proceeds from the sales of interests in unconsolidated affiliates and other assets	174.5			0.7			1.9
Other	15.3			3.9			4.2
Net cash used in investing activities	(373.7		)	(478.4		)	(504.5		)

25

Consolidated Statements of Cash Flows

	Years Ended October 31,
(in millions)	2016			2015			2014
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt	$	299.6		$	149.9		$	249.6
Issuance of common stock related to employee benefit plans	17.0			27.0			25.6
Issuance of common stock, net of expense	104.6			53.7			47.3
Payments for the:
Redemptions of long-term debt	(40.0		)	—			(100.0		)
Expenses related to issuance of debt	(4.3		)	(1.3		)	(2.9		)
Notes payable and commercial paper	(195.0		)	(15.0		)	(45.0		)
Dividends paid	(113.7		)	(103.4		)	(99.2		)
Net cash provided by financing activities	68.2			110.9			75.4
Net increase in cash and cash equivalents	2.9			4.1			1.5
Cash and cash equivalents at beginning of period	13.7			9.6			8.1
Cash and cash equivalents at end of period	$	16.6		$	13.7		$	9.6
Supplemental Disclosures:
Cash paid for interest, net of amount capitalized	$	81.4		$	71.5		$	64.3
Cash (received from) paid for income taxes	(24.5		)	3.2			10.8
Significant non-cash transactions:
Accrued capital expenditures	$	62.8		$	58.9		$	38.9
See Notes to Consolidated Financial Statements.

26

Consolidated Statements of Changes in Equity

(in millions)	Common Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Equity
Balance at October 31, 2013	$	561.6		$	627.2		$	(0.2	)	$	1,188.6
Net income				143.8						143.8
Other comprehensive income, net of tax							—			—
Common stock issuances, including dividend reinvestment and employee benefits	75.2									75.2
Expenses from Issuance of Common Stock	—									—
Tax Benefit from Dividends Paid on ESOP Shares				0.2						0.2
Common stock dividends				(99.2		)				(99.2		)
Balance at October 31, 2014	636.8			672.0			(0.2		)	1,308.6
Net income				137.0						137.0
Other comprehensive loss, net of tax							(0.6		)	(0.6		)
Common stock issuances, including dividend reinvestment and employee benefits	85.0									85.0
Expenses from Issuance of Common Stock	(0.4		)							(0.4		)
Tax Benefit from Dividends Paid on ESOP Shares				0.1						0.1
Common stock dividends				(103.4		)				(103.4		)
Balance at October 31, 2015	721.4			705.7			(0.8		)	1,426.3
Net income				193.2						193.2
Other comprehensive income, net of tax							0.6			0.6
Common stock issuances, including dividend reinvestment and employee benefits	138.5									138.5
Expenses from Issuance of Common Stock	(0.1		)							(0.1		)
Tax Benefit from Dividends Paid on ESOP Shares				0.1						0.1
Common stock dividends				(113.7		)				(113.7		)
Balance at October 31, 2016	$	859.8		$	785.3		$	(0.2	)	$	1,644.9
See Notes to Consolidated Financial Statements.

The components of accumulated other comprehensive income (loss) (OCIL) as of October 31, 2016 and 2015 are as follows.

(in millions)	2016			2015
Hedging activities of equity method investments	$	(0.2	)	$	(0.8	)

27

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont Natural Gas Company, Inc. is an energy services company 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 regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. With the October 3, 2016 sale of our 15% membership interest in SouthStar Energy Services, LLC (SouthStar), we are no longer invested in the unregulated retail natural gas marketing business; see Note 11 for further information on this sale. Our utility operations are regulated by three state regulatory commissions; see Note 3 for further information on regulatory matters. Unless the context requires otherwise, references to "we," "us," "our," "the Company" or "Piedmont" means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

The Consolidated Financial Statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The Consolidated Financial Statements reflect 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. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

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 "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. Gain from the sale of membership interests in our joint ventures are recorded in "Gain on sale of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. See Note 11 for further information on investments in unconsolidated affiliates and related party transactions with these affiliates.

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). On October 3, 2016, the merger was consummated between Duke Energy and Piedmont and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). The Acquisition was recorded using the acquisition method of accounting. Under SEC regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. These adjustments will be recorded by Duke Energy. See Note 2 for further information.

The information presented in this Form 10-K for the fiscal years ended October 31, 2016, 2015 and 2014 are presented solely for the registrant Piedmont on a stand-alone basis. The Consolidated Financial Statements for the 2015 and 2014 periods have been reclassified to conform to Duke Energy's financial statement format. See Note 16 for further information on the reclassification of our Consolidated Financial Statements. Also, Duke Energy and Piedmont performed a comparative analysis of accounting policies with no significant differences except for actuarial assumptions for pension and other postretirement benefit plans. See Note 8 for the discussion of the change of the discount rate in actuarial assumptions.

Use of Estimates

In accordance with GAAP, we 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 during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

28

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by 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 effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, 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 by 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 the 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 by the state regulatory commissions.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are probable of recovery in current rates or in future rate proceedings.

Net Property, Plant and Equipment

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, where the costs of homogeneous assets are aggregated 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 that is recorded in "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income.

29

The classification of net property, plant and equipment for the years ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Intangible plant	$	3.4		$	3.4
Other storage plant	189.1			181.0
Transmission plant	2,315.8			2,024.3
Distribution plant	2,864.7			2,766.9
General plant	469.7			452.3
Asset retirement cost	—			4.1
Contributions in aid of construction	(5.6		)	(5.4		)
Total utility plant in service	5,837.1			5,426.6
Construction work in progress	233.0			170.3
Plant held for future use	7.7			3.1
Other property	1.3			1.3
Total cost	6,079.1			5,601.3
Utility plant in service accumulated depreciation	(1,328.6		)	(1,252.0		)
Other property accumulated depreciation and amortization	(0.9		)	(0.9		)
Total accumulated depreciation and amortization	(1,329.5		)	(1,252.9		)
Total net property, plant and equipment	$	4,749.6		$	4,348.4

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.

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 reduces "Interest Expense" on the Consolidated Statements of Operations and Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. For the three years ended October 31, 2016, 2015 and 2014, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
AFUDC	$	12.3	$	11.1	$	16.4

In accordance with utility accounting practice, we classify costs incurred for utility plant that is not in service to be "Plant held for future use" in "Cost" within "Property, Plant and Equipment" on the Consolidated Balance Sheets. Since March 2009 when construction was suspended, we classified real estate and development costs associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina as "Plant held for future use." 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 are recorded as a regulatory asset with amortization over 38 months beginning January 1, 2014 through February 2017. During fiscal 2016, we reclassified $4.6 million of project costs recorded as "Construction work in progress" to "Plant held for future use." We intend to resume the project when future economic conditions become more favorable.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted average depreciation rates were 2.44% for 2016, 2.48% for 2015 and 2.54% for 2014.

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 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

30

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;" see Note 3 for the amount of these removal costs in "Rate-Regulated Basis of Accounting." See "Asset Retirement Obligations" in this Note 1 for further discussion of this regulatory liability.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents. We have no material restrictions on our cash balances as of October 31, 2016 and 2015.

Receivables and Allowance for Doubtful Accounts

Receivables consist of natural gas sales and transportation services, unbilled revenues, and other miscellaneous receivables, including merchandise and service work, construction related receivables and other miscellaneous receivables. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based 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 Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual 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 regulated 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" within "Investments and Other Assets" on the Consolidated Balance Sheets.

We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2016 and 2015, our receivables and allowance for doubtful accounts consisted of the following.

(in millions)	2016			2015
Gas receivables	$	43.1		$	57.6
Unbilled revenues	13.4			17.4
Other miscellaneous receivables	20.6			13.5
Allowance for doubtful accounts	(1.9		)	(1.6		)
Receivables and Allowance for Doubtful Accounts	$	75.2		$	86.9

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Balance at beginning of year	$	1.6		$	2.2		$	1.6
Additions charged to uncollectibles expense	4.9			5.1			7.0
Accounts written off, net of recoveries	(4.6		)	(5.7		)	(6.4		)
Balance at end of year	$	1.9		$	1.6		$	2.2

See Note 6 for further information on credit risk in "Credit and Counterparty Risk."

Inventory

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

31

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 release the transportation capacity and storage capacity to the asset manager and may assign the gas supply and/or storage inventory 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 "Inventory." From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets in "Prepaids," and the inventory that is available for our use remains in "Inventory."

As of October 31, 2016 and 2015, such counterparties held natural gas storage assets as recorded in "Prepaids," with a value of $21.3 million and $24.8 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 us. The AMAs expire at various times through January 31, 2026. See Note 3 for further information on the revenue sharing of secondary market transactions.

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 value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option 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. As discussed below, beginning with the year ended October 31, 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

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 for the specific instrument, location or commodity being valued. 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 maturity and settlement of our 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 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

32

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 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.

Beginning with the year ended October 31, 2016, we have long-dated, fixed quantity natural gas supply contracts for our regulated utility operations which are accounted for as derivatives. We have classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third-party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. See Note 6 for further information on our fair value measurements of our derivatives and marketable securities. See Note 8 for further information for the fair value measurements of our benefit plan assets.

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.

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, 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. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segment as discussed in Note 13. 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 our regulated utility operations.

Our annual goodwill impairment assessment as of October 31, 2016 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on

33

earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility operations which would have a negative effect on the carrying value of the reporting unit.

Based on our qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test of our 2016 goodwill. The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment was recognized during the years ended October 31, 2016, 2015 and 2014.

On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. Each equity method investment is recorded at cost plus its post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. See Note 11 for further information on our OTTI assessment of one of our equity method investments.

In April 2014, we recorded a $2.0 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. There were no events or circumstances during the years ended October 31, 2016 and 2015 that resulted in any impairment charges.

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. See Note 8 for further information on the deferred compensation plans.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets in "Other" within "Investments and Other Assets" with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their deemed investments at any time.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2016 and 2015 is as follows.

	2016				2015
(in millions)	Cost		Fair Value		Cost		Fair Value
Money markets	$	0.5	$	0.5	$	0.5	$	0.5
Mutual funds	3.2		3.7		3.8		4.4
Total trading securities	$	3.7	$	4.2	$	4.3	$	4.9

Issuances and Repurchases of Common Stock

As discussed in Note 4, prior to the consummation of the Acquisition on October 3, 2016, from time to time, we have repurchased shares on the open market and such shares were then canceled and became authorized but unissued shares. It was our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. In anticipation of the Acquisition by Duke Energy, we suspended new investments in our employee plans effective July 31, 2016.

We present net shares issued under these awards and plans in "Common stock issuances, including dividend reinvestment and employee benefits" in the Consolidated Statements of Changes in Equity.

34

Upon consummation of the Acquisition, our common stock was delisted from the New York Stock Exchange (NYSE).

Asset Retirement Obligations

The accounting guidance for asset retirement obligations (AROs) addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services.

We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in "Regulatory Liabilities" as presented in Note 3. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which our regulated utility operations have the opportunity to earn its allowed rate of return. See "Net Property, Plant and Equipment" in this Note 1, for further discussion of these costs of removal as a component of depreciation.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Operations and Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage 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 4.62% to 5.89% with a time value weighted average of 5.69% for the twelve months ended October 31, 2016. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016		2015
Regulatory non-legal AROs	$	538.0	$	521.5
Conditional AROs	14.1		19.7
Total cost of removal obligations	$	552.1	$	541.2

A reconciliation of the changes in conditional AROs for the year ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Beginning of period	$	19.7		$	14.7
Liabilities incurred during the period	5.5			4.7
Liabilities settled during the period	(6.5		)	(5.6		)
Accretion	1.1			0.9
Adjustment to estimated cash flows	(5.7		)	5.0
End of period	$	14.1		$	19.7

35

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 expense 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. Long-term debt is presented net of unamortized debt expenses in the accompanying Consolidated Balance Sheets. For further information on the effects on regulatory assets and our long-term debt, see Note 3 and Note 5, respectively.

We amortize bank debt expense over the life of the syndicated revolving credit facility, which is 5 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 debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability 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.

Revenue Recognition and Unbilled Revenue

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 gas component of rates may be adjusted periodically under PGA provisions. In North Carolina, a margin decoupling mechanism provides for 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 margin or to recover any under-collection of margin. In South Carolina, a rate stabilization adjustment (RSA) mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA 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 October through April. 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 initially approved in December 2013 in the settlement of our 2013 general rate case and subsequently revised in November 2015. Under the revised North Carolina IMR tariff, we make filings semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates effective the following December 1 and June 1, respectively. Under the Tennessee IMR, we 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. See Note 3 for further discussion of the IMRs.

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. 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. As of October 31, 2016 and 2015, unbilled revenues of $13.4 million and $17.4 million, respectively, are included within "Receivables" on the Consolidated Balance Sheets.

Secondary market revenues 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 sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 3 regarding revenue sharing of secondary market transactions.

36

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. See "Taxes" in this Note 1 for further information regarding taxes.

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 on a monthly basis based on principal, rate and term.

Cost of Natural 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 natural 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 regulated margin is recognized related to these costs, are deferred and included in "Amounts due from customers" in "Current Regulatory Assets" or "Amounts due to customers" in "Current Regulatory Liabilities" as presented in Note 3 in "Rate-Regulated Basis of Accounting." 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 categories of income taxes in the Consolidated Statements of Operations and 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 natural 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 property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Operations and Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded within "Property and other taxes" on the Consolidated Statements of Operations and Comprehensive Income. Property and other taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

37

Consolidated Statements of Cash Flows

With respect to cash, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Accounting Standards Update (ASU)

We early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes in our first fiscal quarter 2016. The core principle of this revised accounting guidance is that all deferred tax assets and liabilities should be classified as noncurrent. Due to the adoption of the new accounting guidance, the balance sheet classification of deferred tax assets and liabilities were retrospectively classified as noncurrent. See Note 16 for the effect of the reclassification of deferred income taxes on the presentation on our Consolidated Balance Sheets. See Note 10 for information related to the presentation of deferred tax assets and liabilities.

We prospectively adopted ASU 2015-05 Intangibles - Goodwill and Other (Topic 350) Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement in our fourth fiscal quarter 2016. The core principle of this revised accounting guidance is determining the accounting for internal-use software for cloud computing arrangements containing a software license. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

Recently Issued Accounting Guidance

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606), including subsequent ASUs clarifying the guidance	Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from any entity's contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of first period of adoption.	Annual periods (and interim periods within those periods) beginning after December 15, 2017, with early adoption permitted for annual periods beginning after December 15, 2016.	As a Duke Energy registrant, we intend to adopt the revised accounting guidance effective for the interim and annual periods beginning January 1, 2018. We are currently evaluating the effect on our financial position and results of operations, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are monitoring specific developments for our industry.

38

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted.	We are currently evaluating the effect on our financial position and results of operations. We do expect an increase in assets and liabilities from the recording of our operating leases.
ASU 2016-15, August 2016, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments	The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle.	Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.	We are currently evaluating the effect on the presentation of our cash flows.

2. Acquisition by Duke Energy Corporation

On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated. Under the terms of the Merger Agreement, each share of Piedmont common stock issued and outstanding immediately prior to the closing (other than shares owned by Duke Energy or its wholly owned subsidiaries) was converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. Each share of the Merger Sub's issued and outstanding stock was converted into one share of no par value common stock for a total of 100 shares owned by Duke Energy. As a result of the merger, the legacy Piedmont common stock outstanding was canceled, and Piedmont's common stock was delisted from the NYSE.

39

Acquisition-related Regulatory Matters

In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. Subsequently, we, Duke Energy and the NCUC Public Staff reached an agreement of stipulation and settlement setting forth stipulations and conditions for approval of the proposed Acquisition, which was originally filed with the NCUC in June 2016. Among the stipulations contained in the agreement are:    

• Funding by the combined company of annual charitable contributions totaling at least $17.5 million in North Carolina during each of the four years after the Acquisition;

• Commitment by the combined company of $7.5 million for low-income household energy assistance and workforce development programs in North Carolina during the first year after the Acquisition;

• Exclusion of certain expenses related to the Acquisition, including severance costs, from customer bills;

• Withdrawal of our March 2016 petition requesting approval of deferred accounting treatment for certain distribution integrity management program expenses; and

• A one-time bill credit to our North Carolina customers collectively of $10.0 million.

A hearing was held on July 18 and 19, 2016. In September 2016, the NCUC approved the Acquisition pursuant to the terms of the stipulation and settlement agreement.

In October 2016, we reduced customers' bills by $4.7 million as a result of the one-time bill credit with the remainder to be reflected on November bills.

Also in January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition was not required.

In January 2016, we and Duke Energy filed a joint application with the TRA seeking approval to transfer Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statute due to the change in control. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition.

Costs to Achieve the Acquisition

The following table summarizes pre-tax acquisition consummation costs, integration and other related costs (collectively referred to as costs to achieve) that we recorded in connection with the Acquisition and are included in "Operations, maintenance and other" within "Operating Expenses" in the Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016 and 2015.

(in millions)	2016		2015
Financial and legal advisory costs	$	22.4	$	8.6
Severance costs (1)	18.7		—
Charitable contributions and community support (2)	8.8		—
Acceleration of incentive plans (3)	5.3		—
Key employee retention payments	3.5		—
Other	2.9		—
Total	$	61.6	$	8.6
(1) See Note 15 for further information on severance costs.
(2) Charitable contributions and community support reflect: 1) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years, and 2) the unconditional obligation to provide funding for low-income household energy assistance and workforce development programs in North Carolina over the next year.
(3) See Note 9 for further information on the accelerated vesting, payment and taxation of certain share-based awards.

40

3. Regulatory Matters

Rate-Regulated Basis of Accounting

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.

(in millions)	2016		2015
REGULATORY ASSETS
Current Regulatory Assets
Unamortized debt expense on reacquired debt	$	0.2	$	0.2
Amounts due from customers	61.9		8.2
Environmental costs	1.5		1.5
Deferred operations and maintenance expenses	0.9		0.8
Deferred pipeline integrity expenses	3.5		3.5
Deferred pension and other retirement benefit costs	2.8		2.8
Robeson LNG development costs	0.1		0.4
Derivatives - gas supply contracts held for utility operations	41.5		—
Other	1.3		1.7
Total current regulatory assets	113.7		19.1
Noncurrent Regulatory Assets
Unamortized debt expense on reacquired debt	4.4		4.7
Environmental costs	3.6		5.1
Deferred operations and maintenance expenses	3.1		4.0
Deferred pipeline integrity expenses	32.4		29.8
Deferred pension and other retirement benefits costs	16.8		17.9
Amounts not yet recognized as a component of pension and other retirement benefit costs	151.6		114.8
Regulatory cost of removal asset	14.1		19.1
Robeson LNG development costs	—		0.1
Derivatives - gas supply contracts held for utility operations	146.4		—
Other	0.9		1.2
Total noncurrent regulatory assets	373.3		196.7
Total Regulatory Assets	$	487.0	$	215.8

REGULATORY LIABILITIES
Current Regulatory Liabilities
Amounts due to customers	$	—	$	21.5
Noncurrent Regulatory Liabilities
Regulatory cost of removal obligations	538.0		521.5
Deferred income taxes	78.9		68.7
Amounts not yet recognized as a component of pension and other retirement benefit costs	0.1		0.1
Total noncurrent regulatory liabilities	617.0		590.3
Total Regulatory Liabilities	$	617.0	$	611.8

As of October 31, 2016, we have $14.1 million of AROs and $344.9 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 funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the TRA on a deferred cash basis.

41

Regulatory Oversight and Rate and Regulatory Actions

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 securities.

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 regulated margin, portion of uncollectibles is included in base rates and uncollectibles expense.

See Note 2 for further information on our regulatory filings and hearings related to the Acquisition.

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 $200.0 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 operations, 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 EasternNC to defer its operation and maintenance (O&M) expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9.0 million as of 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, 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, 2016 and 2015, we had unamortized balances, including accrued interest, of $4.0 million and $4.8 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and 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 was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2016 and 2015, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $35.9 million and $33.3 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs is expected to continue until another recovery mechanism is established in a future rate proceeding.

As approved in the settlement of the 2013 NCUC general rate proceeding, certain capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements are separately tracked and recovered on an annual basis through an IMR, as revised by a subsequent settlement approved by the NCUC in November 2015. The settlement of the 2013 NCUC general rate proceeding 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 disallowed on the basis of prudence.

42

In November 2014, the NCUC approved our accounting of gas costs for 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.

In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2016, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2016. 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 up 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, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under 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 November 2014, November 2015 and November 2016 found our hedging activities during the review periods to be reasonable and prudent.

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 2013 general rate case proceeding as discussed above. The IMR provided 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. In February 2014, the NCUC approved as filed the initial IMR adjustment totaling $0.8 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 capital investments in integrity and safety projects through October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:

• Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31.

• Extension of the IMR tariff from October 31, 2017 to October 31, 2019.

• An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings.

• Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case:

• Transmission integrity: 85% IMR / 15% rate case.

• Distribution integrity: 90% IMR / 10% rate case.

• Right-of-way clearing for integrity projects: 15% IMR / 85% rate case.

• Work and asset management system: 68% IMR / 32% rate case.

• Tax-related adjustments.

• An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015.

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust our rates effective December 1, 2015 to collect an additional $13.4 million in annual IMR margin revenues, based on IMR-eligible capital investments in integrity and safety projects through September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers, which we began recording in January 2016. In May 2016, we filed a petition to adjust our rates effective June 1, 2016 to collect an additional $7.4 million in annual IMR margin revenues from that approved by the NCUC in December 2015. The June 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through March 31, 2016. In May 2016, the NCUC approved the requested rate increase. In October 2016, we filed a petition to adjust our rates effective December 1, 2016 to collect an additional $8.2 million in annual IMR margin revenues from that approved by the NCUC in May 2016. The December 2016 rate adjustment was based on IMR-eligible capital

43

investments in integrity and safety projects through September 30, 2016, which total $513.1 million since inception of the IMR mechanism. In November 2016, the NCUC approved the requested rate increase.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1.0 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. See Note 5 for further information on this shelf registration statement.

In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina to reduce the balance of our amounts due to customers. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina.

In March 2016, we filed a petition with the NCUC requesting approval of deferred accounting treatment for certain distribution integrity management program expenses. We proposed this accounting treatment as an extension of the regulatory asset accounting treatment approved by the NCUC in December 2004 for our transmission integrity management program expenses. In June 2016, we agreed to withdraw this deferral request upon the NCUC’s approval of the agreement of stipulation and settlement in the proceeding seeking approval of the Acquisition as discussed above, contingent upon the closing of the Acquisition. In October 2016, we withdrew the petition pursuant to the terms of the NCUC-approved agreement of stipulation and settlement for the Acquisition.

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 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 October 2013. In October 2014, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (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 $0.1 million of our deferred South Carolina environmental costs and $0.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina, both with amortization periods of one year beginning November 2014 and ending October 2015.

In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2015.

In June 2016, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2016 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2015 order. In October 2016, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in an $8.3 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2016. Also in this proceeding, the PSCSC approved the use of revised depreciation rates effective November 1, 2016.

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 up 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.

44

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 September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015.

In August 2016, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2016.

Tennessee

In Tennessee, we operate under the Tennessee Incentive Plan (TIP) that benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. Under the TIP, the TRA established an allocation of secondary marketing gains and losses to ratepayers and shareholders with a uniform 75/25 sharing ratio with a $1.6 million annual incentive cap for us on these gains and losses. The TIP includes procedures for asset management transactions and provides for a triennial review of TIP operations by an independent consultant. Although the TIP replaced annual prudence reviews of our gas purchasing activities, we undergo an annual compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding the calculation of our deferred gas cost account balances under the Actual Cost Adjustment (ACA) mechanism.

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 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. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015.

In August 2015, 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, 2015 under the TIP. In March 2016, the TRA’s audit staff submitted their report, including immaterial adjustments, with which we concurred. In April 2016, the TRA approved and adopted the audit staff’s report.

In August 2016, 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, 2016 under the TIP. We are waiting on a ruling from the TRA at this time.

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.

In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In June 2016, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2016, we filed an annual report for the twelve months ended June 30, 2016 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 a petition with the TRA seeking authority to implement an IMR to recover 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 $13.1 million in annual margin revenue from tariff customers based on capital expenditures of $100.4 million incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014.

45

In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54.0 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015.

In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.

In November 2016, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2017 based on $20.1 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2016. We are waiting on a ruling from the TRA at this time.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. The TRA’s written order was issued in February 2016.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the costs of our capital investments 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, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general 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. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. The TRA's written order was issued in October 2015.

In July 2016, the TRA Staff filed its compliance audit report for operation of our WNA rider during the 2015 – 2016 heating season, concluding that we had correctly implemented the WNA rider in all material aspects. The TRA Staff identified an immaterial error that resulted in an under-collection of our WNA revenues and recommended a correcting adjustment through the ACA mechanism which we recorded in August 2016. In August 2016, the TRA approved and adopted the TRA Staff’s compliance audit report. The TRA’s written order was issued in September 2016.

All States

Due to the seasonal nature of our business and as approved by our state regulatory commissions, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. These sales normally 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 are favorable and when the supply and capacity are not required to serve our retail distribution system. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Effective October 3, 2016, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2016, 2015, and 2014 is presented below.

46

(in millions)	2016		2015		2014
Allocated to customers as gas cost reductions	$	52.0	$	60.1	$	72.2
Margin allocated to us	17.7		21.1		25.4
Margin from secondary market activity	$	69.7	$	81.2	$	97.6

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

4. Common Stock

With the consummation of the Acquisition on October 3, 2016, each share of Piedmont's outstanding common stock (other than shares owned by Duke Energy and its wholly owned subsidiaries) was converted into the right to receive $60 in cash per share, and all of Piedmont's outstanding common stock was canceled and delisted from the NYSE. Our Restated Articles of Incorporation were amended on the consummation date to change the number of authorized shares to 100 shares of common stock, no par value. The issued and outstanding shares of the Merger Sub became the issued and outstanding shares of Piedmont, a wholly owned subsidiary of Duke Energy.

Common Stock

Changes in common stock for the years ended October 31, 2016, 2015 and 2014 are as follows.

(in millions)	Shares		Amount
Balance, October 31, 2013	76.1		$	561.6
Issued to participants in the Employee Stock Purchase Plan (ESPP)	—		1.1
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP)	0.7		23.5
Issued to incentive compensation plan (ICP)	0.1		3.3
Issuance of common stock through forward sale agreements (FSAs), net of expenses	1.6		47.3
Balance, October 31, 2014	78.5		636.8
Issued to ESPP	—		1.2
Issued to DRIP	0.7		24.7
Issued to ICP	0.2		5.0
Issuance of common stock through FSAs, net of expenses	1.5		53.7
Balance, October 31, 2015	80.9		721.4
Issued to ESPP *	—		1.0
Issued to DRIP *	0.3		14.5
Issued to ICP	0.3		18.3
Issuance of common stock through FSAs, net of expenses	1.8		104.6
Outstanding shares of common stock converted into the right to receive cash	(83.3	)
Balance, October 31, 2016	—		$	859.8
*In anticipation of the Acquisition, we suspended new investments in our DRIP and ESPP, effective July 31, 2016.

Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we could issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170.0 million (subject to certain exceptions) during the period beginning January 7, 2015 and ending October 31, 2016.

In addition to the issuance and sale of shares by us through the Agents, we could also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers would, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. Under the Sales Agreements, we specified the maximum number of our shares to be sold and the minimum price per share. We paid each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale

47

price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements could be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs.

The table below presents equity transactions that were settled in shares under the open registration statements over the two-year period ended October 31, 2016.

(in millions, except per share amounts)
Equity Issuance Transaction	Number of Shares	Settled	Net Proceeds Before Issuance Costs (1)		Net Settlement Price Per Share (2)
FSA - executed March 2015	0.6	October 2015	$	21.8	$35.50
FSA - executed June 2015	0.8	October 2015	28.2		$35.49
FSA - executed September 2015	0.1	October 2015	4.1		$36.03
Total 2015 ATM program	1.5		$	54.1
FSA - executed January 2016	0.4	September 2016	$	20.2	$56.25
FSA - executed March 2016	0.6	September 2016	36.2		$58.35
FSA - executed June 2016	0.8	September 2016	48.3		$58.87
Total 2016 ATM program	1.8		$	104.7
(1) Issuance costs incurred as follows: October 2015 shares $0.4 million and September 2016 shares $0.1 million.
(2) Net of 1.5% commission plus other adjustments.

In accordance with accounting guidance, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and the physical settlement was within our control. As a result of this classification, no amounts were recorded in the Consolidated Financial Statements until the final settlement of the FSAs, which were all physically settled. We recorded the FSA amounts in "Equity" as an addition to "Common stock" on the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our commercial paper (CP) program and for general corporate purposes.

As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances.

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and retirement benefits from our investments in unconsolidated affiliates. See Note 11 for further information on our investments in unconsolidated affiliates. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2016 and 2015.

Changes in Accumulated OCIL (1)
(in millions)	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(0.8	)	$	(0.2	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(2.8		)	(1.6		)
Amounts reclassified from accumulated OCIL, net of tax	3.4			1.0
Total current period activity of hedging activities of equity method investments, net of tax	0.6			(0.6		)
Accumulated OCIL ending balance, net of tax	$	(0.2	)	$	(0.8	)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

48

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2016 and 2015.

Reclassification Out of Accumulated OCIL (1)
	Years Ended					Affected Line Items on Statement of Operations and Comprehensive Income
	October 31,
(in millions)	2016		2015
Hedging activities of equity method investments	$	1.4	$	1.7		Equity in earnings of unconsolidated affiliates
Income tax expense	2.0		(0.7		)	Income tax expense
Total reclassification for the period, net of tax	$	3.4	$	1.0
(1) Amounts in parentheses indicate debits to accumulated OCIL.

5. Debt and Credit Facilities

Summary of Long-Term Debt

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. None of our debt is actively traded. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.

	Long-Term Debt as of October 31, 2016
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
8.51%, due September 30, 2017	$	35.0	$	—		$	35.0
4.24%, due June 6, 2021	160.0		(0.6		)	159.4
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.2		)	198.8
4.10%, due September 18, 2034	250.0		(2.5		)	247.5
4.65%, due August 1, 2043	300.0		(2.9		)	297.1
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
3.64%, due November 1, 2046	300.0		(3.4		)	296.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.2		)	59.8
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,835.0		(14.0		)	1,821.0
Less current maturities	35.0		—			35.0
Total	$	1,800.0	$	(14.0	)	$	1,786.0

49

	Long-Term Debt as of October 31, 2015
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
2.92%, due June 6, 2016	$	40.0	$	(0.1	)	$	39.9
8.51%, due September 30, 2017	35.0		—			35.0
4.24%, due June 6, 2021	160.0		(0.8		)	159.2
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.3		)	198.7
4.10%, due September 18, 2034	250.0		(2.6		)	247.4
4.65%, due August 1, 2043	300.0		(3.0		)	297.0
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.3		)	59.7
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,575.0		(11.3		)	1,563.7
Less current maturities	40.0		—			40.0
Total	$	1,535.0	$	(11.3	)	$	1,523.7

Current maturities for the next five years ending October 31 and thereafter are as follows.

(in millions)
2017	$	35.0
2018	—
2019	—
2020	—
2021	160.0
Thereafter	1,640.0
Total	$	1,835.0

In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration statement up to $1.0 billion during its three-year life. As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances.

On September 14, 2015, we issued $150.0 million of ten-year, unsecured senior notes with an interest rate of 3.60% and at a discount of .065% or $0.1 million 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 June 1, 2025, 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 to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 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 June 1, 2025, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $148.9 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

On June 6, 2016, we repaid $40.0 million of our 2.92% senior notes at maturity.

50

On July 28, 2016, we issued $300.0 million of unsecured senior notes maturing November 1, 2046 with an interest rate of 3.64% and at a discount of .122% or $0.4 million under the registration statement in effect noted above. We have the option to redeem all or part of the notes before May 1, 2046, at a redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and 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 25 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 on or after May 1, 2046, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.0 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

The amount of cash dividends that may be paid on 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, 2016, our net earnings available for restricted payments were $1.3 billion.

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, 2016, we are in compliance with all default provisions.

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 $1.0 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 4.65 times as of October 31, 2016;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 55% of total capitalization as of October 31, 2016;

• 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, 2016;

• Restrictions on permitted liens;

• Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and

• Restrictions on burdensome agreements.

The Acquisition constituted a change in control under the note agreements under which our 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition did not constitute an event of default, upon the closing of the Acquisition, we were required to offer to prepay 100% of the principal amounts plus accrued interest to these noteholders. None of the noteholders exercised the prepayment option.

Available Credit Facilities

At October 31, 2016, we have an $850.0 million five-year revolving syndicated credit facility that expires on December 14, 2020 that has an option to request an expansion up to an additional $200.0 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10.0 million, of which $1.7 million and $1.6 million were issued and outstanding as of October 31, 2016 and 2015, respectively. These letters of credit are used 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 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020 provided that we are in compliance with all terms of the agreement. The facility expressly permitted the Acquisition by Duke Energy.

We have an $850.0 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 $850.0 million. The notes issued under the CP program may have maturities not to exceed 397 days

51

from the date of issuance and bear interest based 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, 2016, we had $145.0 million of notes outstanding under the CP program, as included in "Notes payable and commercial paper" within "Current Liabilities" on the Consolidated Balance Sheets, with original maturities ranging from 1 to 6 days from their dates of issuance at a weighted average interest rate of .64%. As of October 31, 2015, our outstanding notes under the CP program, included on the Consolidated Balance Sheets as stated above, were $340.0 million at a weighted average interest rate of .22%.

Other than outstanding CP balances, we did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2016. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2016 is as follows.

(in millions)
Minimum amount outstanding	$	110.0
Maximum amount outstanding	$	530.0
Minimum interest rate	.20		%
Maximum interest rate	.75		%
Weighted average interest rate	.55		%

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 55% at October 31, 2016.

6. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans with the purchase of financial gas call option derivative instruments (gas purchase options). The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase options. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2016 and 2015, we had long gas purchase options providing total coverage of 15.4 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held as of October 31, 2016 are for the period from December 2016 through May 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Beginning with the year ended October 31, 2016, we have certain long-dated, fixed quantity forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "Other" in "Current Liabilities" and "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use gas purchase options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these long-dated, fixed quantity gas supply contracts that became effective beginning with the year ended October 31, 2016 should be recorded at fair value.

52

The costs of our gas cost hedging plans 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, we present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of our gas purchase options held for our utility operations. There are no gas purchaseoptions 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 gas purchase options held for utility operations. Our gas purchase options held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivative contracts presented at fair value that are held for our utility operations.

We also have trading securities that are held in rabbi trusts established for certain deferred compensation plans and are included in "Other" within "Investments and Other Assets" on the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in "Fair Value Measurements" in Note 1.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2016 and 2015. 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 to the fair value measurement requires judgment 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, 2016 and 2015.

Recurring Fair Value Measurements as of October 31, 2016
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.5	$	—	$	—	$	—	$	1.5
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	3.7		—		—		—		3.7
Total fair value assets	$	5.7	$	—	$	—	$	—	$	5.7
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	187.9	$	—	$	187.9

Recurring Fair Value Measurements as of October 31, 2015
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.3	$	—	$	—	$	—	$	1.3
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	4.4		—		—		—		4.4
Total fair value assets	$	6.2	$	—	$	—	$	—	$	6.2

53

In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our gas supply derivative contracts in the mid to later years of contract terms ranged from $2.60 to $4.47 per dekatherm.

The fair value of our gas supply derivative contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain.

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.

(in millions)	2016
Gas supply derivative liabilities, beginning balance	$	—
Realized and unrealized losses:
Recorded to regulatory assets *	187.9
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Gas supply derivative liabilities, ending balance	$	187.9
* Included are the actual costs recorded within "Cost of natural gas" on the Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing.

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 are to use these financial instruments to reduce gas cost volatility for our customers.

Our regulated utility operations gas purchase options are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These gas purchase options are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these gas purchase options 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 operation of the hedging programs of the regulated utility operations as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as "Current Regulatory Assets" or amounts due to customers included as "Current Regulatory Liabilities" in Note 3 and recognized on the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" when the related costs are recovered through our rates. These gas purchase options are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "Derivatives - gas supply contracts held for utility operations" in Note 3.

The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of October 31, 2016 and 2015.

Fair Value of Derivative Instruments
(in millions)	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Financial Asset Instruments:
Current Assets - Gas purchase derivative assets	$	1.5	$	1.3
Nonfinancial Liabilities Instruments:
Current Liabilities - Gas supply derivative liabilities	41.5
Noncurrent Liabilities - Gas supply derivative liabilities	146.4

54

The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016 and 2015, 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 millions)	2016			2015			2016			2015
Gas purchase options	$	(5.2	)	$	(4.4	)	$	(5.2	)	$	(4.4	)	Cost of natural 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 as 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 as 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.

We would have recorded an unrealized loss of $187.9 million related to our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" in the month purchased.

Our long-term debt is presented at net 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. The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.

(in millions)	Principal		Fair Value
As of October 31, 2016	$	1,835.0	$	2,061.2
As of October 31, 2015	1,575.0		1,720.6

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 have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations 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 "Receivables" within "Current Assets" on the Consolidated Balance Sheets attributable to these entities amounted to $14.2 million, or approximately 31% of our gross receivables as of October 31, 2016. 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

55

while under the management of this third party. We believe, based on our credit policies as of October 31, 2016, 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 receivables 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 receivables; however, we believe that our provision for possible losses on uncollectible receivables are 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 established comprehensive risk management policies under the direction of Duke Energy’s Chief Executive Officer (CEO) and Chief Financial Officer. The Finance and Risk Management Committee of Duke Energy's Board of Directors receives periodic updates from Duke Energy's Chief Risk Officer and other members of management on market risk positions, corporate exposures, and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits.

7. Commitments and Contingencies

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, 2016, 2015 and 2014 are as follows.

(in millions)	2016		2015		2014
Operating lease payments (1)	$	4.8	$	5.0	$	4.7
(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 millions)
2017	$	4.7
2018	4.6
2019	4.4
2020	4.5
2021	4.6
Thereafter	19.8
Total	$	42.6

56

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 fully recoverable subject to 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 nineteen years. The time periods for fixed payments of reservation fees under gas supply contracts are up to two years. The time period for the gas supply purchase commitments is up to fifteen 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, 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 on the Consolidated Statements of Operations and Comprehensive Income as part of gas purchases and included within "Cost of natural gas."

As of October 31, 2016, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Gas Supply		Telecommunications
	and Storage		Reservation		Purchase		and Information
(in millions)	Capacity		Fees		Commitments		Technology		Other		Total
2017	$	170.0	$	2.2	$	124.4	$	9.6	$	62.1	$	368.3
2018	143.8		—		96.8		5.4		—		246.0
2019	133.4		—		96.8		5.2		—		235.4
2020	115.4		—		97.1		4.5		—		217.0
2021	113.7		—		96.8		1.1		—		211.6
Thereafter	405.5		—		896.1		—		—		1,301.6
Total	$	1,081.8	$	2.2	$	1,408.0	$	25.8	$	62.1	$	2,579.9

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters 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 $1.7 million in letters of credit that were issued and outstanding as of October 31, 2016. See Note 5 for additional information concerning letters of credit.

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, 2016, we had open surety bonds with a total contingent obligation of $6.4 million.

57

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).

We share environmental responsibility for various MGP sites with Duke Energy, and one of its subsidiaries. In 1997, we entered into a settlement with Duke Energy 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 our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition and prior to its closing, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress), a subsidiary of Duke Energy since July 2012. Progress has complete responsibility for performing all of the former 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 were 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.

As of October 31, 2016, our estimated undiscounted environmental liability totaled $1.0 million, and consisted of $0.8 million for MGP sites for which we retain responsibility and $0.2 million for USTs, our Huntersville LNG facility and other environmental costs. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others. For the period ending October 31, 2016, we incurred $0.1 million of remediation costs related to our MGP sites and Huntersville LNG facility.

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, 2016, our regulatory assets for unamortized environmental costs in our three-state territory totaled $5.1 million. We received approval from the TRA to recover $2.0 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.

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.

8. Employee Benefit Plans

We recognize all obligations related to our 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. We measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. Our plans’ assets are recorded at fair value. In accordance with accounting guidance, 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.

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

58

retirement using information about that participant. An employee is 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 an applicable year. 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.

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 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, where applicable.

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 the following types of investments:

• Fixed income securities: includes U.S. treasuries, corporate bonds, high yield debt (bank loans), 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.

• Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as international equity.

• Real estate: includes a diversified global real estate investment trust fund.

• Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies.

59

The target and actual allocations of the qualified pension plan's assets are as follows.

	Target		Assets as of October 31,
Asset Allocations	Allocation		2016		2015
Fixed income securities	45	%	46	%	46	%
Equity securities	35	%	33	%	34	%
Real estate	5	%	5	%	5	%
Cash and cash equivalents	—	%	2	%	1	%
Other investments	15	%	14	%	14	%
Total	100	%	100	%	100	%

Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee 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, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2016, 2015 and 2014, we contributed $1.8 million, $1.4 million and $0.9 million, respectively, to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees hired prior to January 1, 2008 are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees hired after January 1, 2008 have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Employees who meet the eligibility requirements to retire also receive a life insurance benefit of $15,000.

Prior to January 1, 2016, employees who met the eligibility requirement noted above or were part of a "grandfathered" group received either full or partial retiree coverage paid by us, subject to certain participation limits. Retirees were responsible for the full cost of dependent coverage.

Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). Under the new HRA, participating eligible retirees and their dependents may qualify for a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical and dental expenses.

OPEB plan assets are comprised of mutual funds within a 401(h) account and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the investment philosophy of the qualified pension plan as discussed above, except the OPEB fixed income portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

60

The target and actual allocations of the OPEB plan's assets are as follows.

	Target			Assets as of October 31,
Asset Allocations	Allocation			2016		2015
Fixed income securities	45	%	(1)	47	%	47	%
Equity securities	47	%		44	%	44	%
Real estate	5	%		5	%	5	%
Cash and cash equivalents	3	%		4	%	4	%
Total	100	%		100	%	100	%
(1) Includes 5% target allocation to high yield fixed income.

Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, 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.

We have a non-qualified defined contribution restoration plan (DCR plan) for certain officers at 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% 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. In accordance with the Merger Agreement, the account balances were subject to accelerated vesting effective with the consummation of the Acquisition with distribution occurring upon the participant's separation of service from the Company.

Prior to the Acquisition, we had a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we made no contributions to this plan. Participants could defer a percentage of their base salary and annual incentive pay in accordance with the plan. Benefits under this plan, known as the Voluntary Deferral Plan, were informally funded monthly through a rabbi trust with a bank as the trustee. In accordance with the Merger Agreement, the account balances were subject to accelerated distribution effective with the consummation of the Acquisition.

Our funding to the DCR plan account for the years ended October 31, 2016 and 2015, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2016 and 2015, are presented below.

(in millions)	2016		2015
Funding	$	0.5	$	0.5
Liability	4.7		5.3

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 was $0.1 million for the years ended October 31, 2016, 2015 and 2014.

61

Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2016 and 2015, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2016 and 2015, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension						Other Benefits
(in millions)	2016			2015			2016			2015			2016			2015
Accumulated benefit obligation at year end	$	296.3		$	263.1		$	4.6		$	5.5		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	311.5		$	302.7		$	5.5		$	5.9		$	37.6		$	37.8
Service cost	10.6			11.4			—			—			1.2			1.2
Interest cost	9.5			12.0			0.2			0.2			1.3			1.5
Plan amendments	—			—			—			—			—			(1.9		)
Plan settlements	—			—			(0.9		)	—			—			—
Actuarial loss (gain)	34.1			3.5			0.3			(0.1		)	1.6			1.7
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Obligation at end of year	351.7			311.5			4.6			5.5			39.3			37.6
Change in fair value of plan assets:
Fair value at beginning of year	329.3			336.4			—			—			27.5			27.7
Actual return on plan assets	17.6			1.0			—			—			1.1			0.3
Employer contributions	10.0			10.0			1.4			0.5			2.6			2.2
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Plan settlements	—			—			(0.9		)	—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Fair value at end of year	342.9			329.3			—			—			28.8			27.5
Funded status at year end - (under) over	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Noncurrent assets	$	—		$	17.8		$	—		$	—		$	—		$	—
Current liabilities	—			—			(0.5		)	(0.5		)	—			—
Noncurrent liabilities	(8.8		)	—			(4.1		)	(5.0		)	(10.5		)	(10.1		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized prior service credit (cost)	$	10.7		$	12.8		$	—		$	(0.2	)	$	1.5		$	1.9
Unrecognized actuarial loss	(153.1		)	(120.5		)	(1.5		)	(1.6		)	(9.1		)	(7.2		)
Regulatory asset	(142.4		)	(107.7		)	(1.5		)	(1.8		)	(7.6		)	(5.3		)
Cumulative employer contributions in
excess of cost	133.6			125.5			(3.1		)	(3.7		)	(2.9		)	(4.8		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Weighted average assumptions used in the measurement of
the benefit obligations:
Discount rate	3.80		%	4.34		%	3.80		%	3.85		%	3.80		%	4.38		%
Rate of compensation increase	4.05		%	4.07		%	N/A			N/A			N/A			N/A

62

Net periodic benefit cost components for the years ended October 31, 2016, 2015 and 2014 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2016, 2015 and 2014 are presented below.

	Qualified Pension									Nonqualified Pension									Other Benefits
(in millions)	2016			2015			2014			2016			2015			2014			2016			2015			2014
Service cost	$	10.6		$	11.4		$	10.9		$	—		$	—		$	—		$	1.2		$	1.2		$	1.1
Interest cost	9.5			12.0			11.7			0.2			0.2			0.2			1.3			1.5			1.5
Expected return on plan assets	(24.0		)	(23.6		)	(22.5		)	—			—			—			(1.8		)	(1.8		)	(1.8		)
Amortization of prior service (credit)
cost	(2.2		)	(2.2		)	(2.2		)	0.2			0.2			0.2			(0.3		)	—			—
Amortization of net loss	8.0			8.7			7.7			—			0.1			0.1			0.4			—			—
Settlement loss recognized	—			—			—			0.3			—			—			—			—			—
Net periodic benefit cost	1.9			6.3			5.6			0.7			0.5			0.5			0.8			0.9			0.8
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost (credit)	—			—			—			—			—			0.5			—			(1.9		)	—
Net loss (gain)	40.5			26.2			14.4			0.3			(0.1		)	1.0			2.4			3.2			3.6
Amounts recognized as a component of
net periodic benefit cost:
Amortization of net loss	(8.0		)	(8.7		)	(7.7		)	—			(0.1		)	(0.1		)	(0.4		)	—			—
Settlement loss recognized	—			—			—			(0.3		)	—			—			—			—			—
Prior service credit (cost)	2.2			2.2			2.2			(0.2		)	(0.2		)	(0.2		)	0.3			—			—
Total recognized in regulatory asset
(liability)	34.7			19.7			8.9			(0.2		)	(0.4		)	1.2			2.3			1.3			3.6
Total recognized in net periodic benefit
and regulatory asset	$	36.6		$	26.0		$	14.5		$	0.5		$	0.1		$	1.7		$	3.1		$	2.2		$	4.4
Weighted average assumptions used to determine the net periodic benefit cost:
Discount rate	4.34		%	4.13		%	4.55		%	3.85		%	3.69		%	3.98		%	4.38		%	4.03		%	4.44		%
Expected long-term rate of return on plan assets	7.25		%	7.50		%	7.75		%	N/A			N/A			N/A			7.25		%	7.50		%	7.75		%
Rate of compensation increase	4.07		%	3.68		%	3.72		%	N/A			N/A			N/A			N/A			N/A			N/A

The 2017 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 millions)	Pension			Pension		Benefits
Amortization of unrecognized prior service credit	$	(2.2	)	$	—	$	(0.3	)
Amortization of unrecognized actuarial loss	11.3			0.1		0.7

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.

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. Our assumed mortality rates incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. We also applied the updated projection scale issued by the Society of Actuaries in October 2016.

63

We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31, 2017.

(in millions)
Qualified pension plan	$	10.0
Nonqualified pension plans	0.5
MPP plan	2.1
OPEB plan	2.2

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. We are in compliance with the 100% funding target established in the PPA.

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 millions)	Pension		Pension		Benefits
2017	$	39.6	$	0.5	$	1.9
2018	25.2		0.5		2.1
2019	25.0		0.5		2.2
2020	24.8		0.4		2.4
2021	24.9		0.4		2.4
2022 – 2026	126.8		1.7		13.1

Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2016 and 2015.

In fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our plans. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. This change improved the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provided a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Effective with the consummation of the Acquisition, we changed the methodology we use to calculate the discount rate for the current year benefit obligation and next year's periodic net benefit cost for our plans. We replaced our full yield curve methodology with a bond selection-settlement portfolio approach used by Duke Energy. 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, which was 3.80% as of October 31, 2016, 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. This change decreased our total benefit obligations on our plans as of October 31, 2016 by $2.4 million.

Fair Value Measurements

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 are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

64

Fixed income securities – These assets include:

• 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.

• 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.

• Derivatives – The Level 1 assets are valued using a compilation of observable market information on an active market. The Level 2 assets are valued using broker quotes on a non-active market.

Equity securities – These are level 1 assets valued at the market price of the active market on which the individual security is traded.

Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Common trust fund – These are Level 2 assets held in a common trust fund 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 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; $2.6 million of the original $12.0 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 Standard & Poor's 500 Stock Index. Our investment is in various funds that invest in North American companies, allocate capital to private equity funds, invest in venture capital partnerships and private equity partnerships in emerging markets.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Hedge fund of funds – 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.

Commodities fund of funds – These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers. Currently, there are no restrictions on redemptions for the fund.

High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund.

65

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, 2016.	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 business 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 8 to 10 years.

The qualified pension plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment 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.

	Qualified Pension Plan as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	5.1	$	0.8	$	—	$	5.9
Fixed income securities	—		78.9		—		78.9
Equity securities	44.4		—		—		44.4
Mutual funds	78.2		55.0		—		133.2
Common trust fund	—		25.0		—		25.0
Private equity fund of funds	—		—		8.9		8.9
Other Investments:
Hedge fund of funds							20.0		(1)
Commodities fund of funds							9.2		(1)
High yield debt (bank loans)							17.4		(1)
Total assets at fair value	$	127.7	$	159.7	$	8.9	$	342.9

66

	Qualified Pension Plan as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	2.8	$	0.1	$	—	$	2.9
Fixed income securities	—		84.1		—		84.1
Equity securities	44.7		—		—		44.7
Mutual funds	78.9		42.9		—		121.8
Common trust fund	—		23.6		—		23.6
Private equity fund of funds	—		—		8.3		8.3
Other Investments:
Hedge fund of funds							19.8		(1)
Commodities fund of funds							7.7		(1)
High yield debt (bank loans)							16.4		(1)
Total assets at fair value	$	126.4	$	150.7	$	8.3	$	329.3
(1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
(in millions)	of Funds
Balance, October 31, 2014	$	7.2
Actual return on plan assets:
Relating to assets still held at the reporting date	0.4
Relating to assets sold during the period	0.6
Purchases, sales and settlements (net)	0.1
Transfer in/out of Level 3	—
Balance, October 31, 2015	8.3
Actual return on plan assets:
Relating to assets still held at the reporting date	0.1
Relating to assets sold during the period	0.5
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, October 31, 2016	$	8.9

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.

Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

67

Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date.

The OPEB plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of 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 1.

	Other Benefits as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.2	$	—	$	—	$	1.2
Mutual funds	27.6		—		—		27.6
Total assets at fair value	$	28.8	$	—	$	—	$	28.8

	Other Benefits as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.1	$	—	$	—	$	1.1
Mutual funds	26.4		—		—		26.4
Total assets at fair value	$	27.5	$	—	$	—	$	27.5

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. Prior to the Acquisition, participants could 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, 2016, 2015 and 2014, we made matching contributions to participant accounts as follows.

(in millions)	2016		2015		2014
401(k) matching contributions	$	6.9	$	6.6	$	6.1

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. Prior to the Acquisition, former ESOP participants could remain invested in Piedmont common stock in their 401(k) plan or could 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 Statements of Changes in Equity as an increase in retained earnings.

68

9. Employee Share-Based Plans

Prior to the Acquisition, under our shareholder approved ICP, eligible officers and other participants were awarded units that paid out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards were made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans required that a minimum threshold performance level be achieved in order for any award to be distributed.

During 2016, we had three series of awards that were outstanding under the approved ICP, with a three-year performance period that ended October 31, 2016 (2016 plan), October 31, 2017 (2017 plan) and October 31, 2018 (2018 plan). For the years ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. We re-measured the liability to market value each quarter and at the settlement date of the award.

The Merger Agreement provided for the conversion of the 2016 and 2017 plans shares subject to the ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at their election to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, was done for tax planning purposes and occurred on December 15, 2015. In connection with the election to accelerate the ICP awards, each respective participant executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated ICP awards. With the consummation of the Acquisition, all restrictions were lifted.

The accelerated ICP awards were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes.

Upon consummation of the Acquisition, the participants that did not accelerate their ICP awards, as discussed above, received $60 per share under the 2016 and 2017 plans, or $0.3 million in cash, net of applicable income taxes withheld.

The 2018 plan was approved subsequent to the execution of the Merger Agreement with Duke Energy. Under the Merger Agreement, the 2018 plan performance awards were fully converted into Duke Energy restricted stock unit awards (Duke Energy RSU Award) upon consummation of the Acquisition. Vesting under the Duke Energy RSU Award will be subject to the participant remaining continuously employed by Duke Energy or its affiliates through October 31, 2018. The Duke Energy RSU Award will be subject to 100% accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement. The Duke Energy RSU Award is recorded as an equity award on Duke Energy's balance sheet. As of October 31, 2016, our liability related to this plan is $6.1 million as reflected in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets.

Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO prior to the consummation of the merger (former CEO) in December 2011. During the vesting period, any dividend equivalents were accrued on these stock units and 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 vested RSUs were payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, only if he remained an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units were scheduled to vest on December 15, 2016 (2016 RSU). The Merger Agreement provided for the conversion of the 2016 RSU into the right to receive $60 cash per share upon closing of the transaction contemplated in the Merger Agreement. Similar to the accelerated ICP awards discussed above, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU (accelerated RSU) in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. Our former CEO executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated RSU. The acceleration and payout of the accelerated RSU occurred on December 15, 2015. With the consummation of the Acquisition, all restrictions were lifted. For the twelve months ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for nonvested RSUs as applicable, based on the fair market value of our common stock at the end of each quarter. The liability was re-measured to market value each quarter and at the settlement date of the award.

69

The following table summarizes the settlement of the RSUs.

	December 15, 2014 vesting (20% of the grant)			December 15, 2015 vesting (30% of the grant)			Accelerated RSU settled on December 15, 2015 (50% of the grant)
Shares of common stock issued, including accrued dividends, net of shares withheld for taxes	7,231			11,732			19,554
NYSE composite closing price	$	37.89	(1)	$	56.85	(2)	$	56.85	(2)
(1) Closing price on December 12, 2014.
(2) Closing price on December 14, 2015.

At the time of distribution of any award under the ICP, the number of shares of common stock issuable was reduced by the withholdings for payment of applicable income taxes for each participant. The participant could elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. We present the net shares issued in the Consolidated Statements of Changes in Equity and in Note 4.

The compensation expense related to the awards under the ICP for the years ended October 31, 2016, 2015 and 2014, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016			2015		2014
Compensation expense	$	16.1	(1)	$	14.2	$	8.5
Tax benefit	6.1			4.0		2.5
Liability	—			22.0
(1) Includes $5.3 million incremental expense related to the accelerated ICP and RSU awards, and the conversion of the 2018 plan to a Duke Energy RSU Award. See Note 2 for further information.

Equity Plan

Prior to the Acquisition, on a quarterly basis, we issued shares of common stock under the ESPP and accounted for the issuance as an equity transaction. The exercise price was calculated as 95% of the fair market value on the purchase date of each quarter where the fair value was determined by calculating the average of the high and low trading prices on the purchase date.

In anticipation of the Acquisition, we suspended new investments in our ESPP and resulting issuances of common stock under this plan, effective July 31, 2016. The ESPP was terminated at the closing date of the Acquisition on October 3, 2016.

70

10. Income Taxes

The components of income tax expense for the years ended October 31, 2016, 2015 and 2014 are presented below.

	2016					2015					2014
(in millions)	Federal			State		Federal			State		Federal			State
Charged (Credited) to income:
Current	$	27.2		$	11.8	$	(0.7	)	$	1.1	$	2.5		$	1.8
Deferred (1) (2)	79.6			5.8		77.9			12.1		76.5			14.2
Tax Credits:
Amortization	(0.2		)	—		(0.2		)	—		(0.2		)	—
Total	$	106.6		$	17.6	$	77.0		$	13.2	$	78.8		$	16.0
(1) Includes benefits from net operating loss (NOL) and tax carryforwards of $91.4 million and $64.3 million for the years ended October 31, 2016 and 2015, respectively.
(2) Includes the anticipated utilization of NOL and tax carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.

The Protecting Americans from Tax Hikes Act of 2015 enacted in December 2015 and the Tax Increase Prevention Act of 2014, enacted in December 2014, retroactively extended the 50% bonus depreciation which had expired the December of the year preceding the enactments. As a result of the retroactive extensions of bonus depreciation, we were able to claim additional depreciation deductions on our tax returns for the years ended October 31, 2015 and 2014. Prior to the retroactive extensions, we had anticipated utilizing NOL and tax carryforwards to offset taxable income generated in our fiscal years 2015 and 2014 as discussed in note ⁽²⁾ in the table above. The benefits from NOL and tax carryforwards in note ⁽¹⁾ in the table above include $46.8 million and $61.1 million to record the retroactive impact of the passage of bonus depreciation for the years ended October 31, 2016 and 2015, respectively.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Federal taxes at 35%	$	111.1		$	79.5		$	83.5
State income taxes, net of federal benefit	11.4			8.6			10.4
Amortization of investment tax credits	(0.2		)	(0.2		)	(0.2		)
Other, net	1.9			2.3			1.1
Total	$	124.2		$	90.2		$	94.8
Effective Tax Rate	39.1		%	39.7		%	39.7		%

We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. Effective with the Acquisition, our tax year end will change to December 31, 2016, and we and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns. Accordingly, Piedmont and its subsidiaries will file final consolidated income tax returns for the short tax year November 1, 2015 through October 3, 2016. We and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns for the period October 4, 2016 through December 31, 2016. Piedmont and each of our subsidiaries have entered into a tax sharing agreement with Duke Energy and subsidiaries. The tax sharing agreement provides allocation of consolidated tax liabilities and benefits based on amounts participants would incur as separate C-Corporations. Income taxes recorded for the period October 4, 2016 through October 31, 2016 are based on amounts we and our subsidiaries would incur as separate C-Corporations. Current and deferred income tax expense (benefit) of $40.4 million and $(8.7) million, respectively, was recorded for the period October 4 through October 31, 2016. "Taxes accrued" on the Consolidated Balance Sheets as of October 31, 2016 includes $31.5 million payable to Duke Energy for federal income taxes due under the tax sharing agreement. In accordance with IRS regulations, we and our subsidiaries are jointly and severally liable for the federal tax liability.

As of October 31, 2016 and 2015, deferred income taxes consists of the following temporary differences. As discussed in Note 1 and Note 16, Piedmont early adopted ASU 2015-17, providing guidance that deferred tax assets and

71

liabilities be classified as noncurrent. With this retrospective adoption, the balance sheet classification of deferred tax assets and liabilities were classified as noncurrent.

(in millions)	2016			2015
Deferred tax assets:
Benefit of tax carryforwards	$	175.4		$	84.0
Revenues and cost of natural gas	—			3.5
Employee benefits and compensation	28.6			22.1
Revenue requirement	30.1			26.1
Property, plant and equipment	5.3			7.5
Regulatory asset - gas supply derivative contracts held for utility operations	70.6			—
Other	13.8			10.5
Total deferred tax assets	323.8			153.7
Valuation allowance	(0.8		)	(0.8		)
Total deferred tax assets, net	323.0			152.9
Deferred tax liabilities:
Property, plant and equipment	1,010.8			849.8
Revenues and cost of natural gas	20.0			—
Investments in equity method unconsolidated affiliates	34.8			44.8
Deferred costs	85.0			73.9
Gas supply derivative liabilities	70.6			—
Other	5.9			13.6
Total deferred tax liabilities	1,227.1			982.1
Net deferred income tax liabilities	$	904.1		$	829.2

As of October 31, 2016 and 2015, 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.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
Balance at beginning of year	$	0.8	$	0.5	$	0.5
Charged to income tax expense	—		0.3		—
Balance at end of year	$	0.8	$	0.8	$	0.5

The following table presents the expiration of tax carryforwards.

(in millions)	Amount		Expiration Year
Federal NOL	$	163.5	2020	–	2036
State NOL	8.4		2027	–	2036
Capital loss carryforward	0.3				2017
Charitable carryforward	3.2		2016	–	2019
Total NOL and charitable carryforwards	$	175.4

Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of $159.6 million are subject to an effective annual limitation of $31.8 million.

There were no unrecognized tax benefits for the years ended October 31, 2016 and 2015.

During our 2016 fiscal year, we finalized the federal income tax examinations for tax years ended October 31, 2010, 2011 and 2012. We are no longer subject to federal examination and with few exceptions, state income tax examinations by tax

72

authorities for years ended before and including October 31, 2012. The statute of limitations for the tax year ending October 31, 2012 expires February 28, 2017.

During fiscal year 2016, we recognized $0.5 million in net interest income related to income taxes.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.

North Carolina Corporate Income Tax Rate *	Tax Year Rate is Effective
6.9%	Prior to November 1, 2014
6.0%	November 1, 2014 to October 31, 2015
5.0%	November 1, 2015 to October 3, 2016
4.0%	October 4, 2016 to December 31, 2016
3.0%	Beginning January 1, 2017
* We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse.

As a result of the state income tax rate reductions, we adjusted our deferred income tax balances during fiscal year 2016 and 2015 by approximately $15.7 million and $17.5 million, respectively, for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit during fiscal years 2016 and 2015 in net income of approximately $0.6 million and $0.5 million and recorded the remainder of approximately $15.1 million and $17.0 million during fiscal 2016 and 2015, respectively, as regulatory "Deferred income taxes" as presented in "Noncurrent Regulatory Liabilities" in Note 3, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3.0 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. As of October 31, 2016, we have approximately $58.6 million related to the North Carolina tax rate change included in our "Deferred income taxes" recorded in "Noncurrent Regulatory Liabilities." The NCUC will determine the recovery period of this regulatory liability in future proceedings.

11. Investments in Unconsolidated Affiliates

The Consolidated Financial Statements include the accounts of our wholly owned subsidiaries who have investments in unconsolidated affiliates. These investments are in joint venture, energy-related businesses that are accounted for under the equity method. Our ownership interest in each entity is included in "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" in the Consolidated Statements of Operations and Comprehensive Income.

As of October 31, 2016, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

73

Ownership Interests

We have the following membership interests in these companies as of October 31, 2016.

Entity Name	Interest	Activity
Cardinal Pipeline Company, LLC (Cardinal)	21.49%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Pine Needle LNG Company, LLC (Pine Needle)	45%	Interstate LNG storage facility located in North Carolina; regulated by the FERC
SouthStar *	—%	Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
Hardy Storage Company, LLC (Hardy Storage)	50%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
Constitution Pipeline Company LLC (Constitution)	24%	To develop, construct, own and operate 124 miles of interstate 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 the FERC
Atlantic Coast Pipeline, LLC (ACP) **	7%	To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC
* On October 3, 2016, we sold our 15% interest in SouthStar, effective with the consummation of the Acquisition.
** On October 3, 2016, as a result of the Acquisition, we sold 3% of our interest, reducing our ownership from 10% to 7%.

As of October 31, 2016 and 2015, our investment balances are as follows.

(in millions)	2016		2015
Cardinal	$	14.2	$	15.1
Pine Needle	16.6		18.4
SouthStar	—		41.3
Hardy Storage	42.1		39.7
Constitution	93.1		82.4
ACP	33.2		10.1
Total investments in equity method unconsolidated affiliates	$	199.2	$	207.0

For the years ended October 31, 2016, 2015 and 2014, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income as follows.

(in millions)	2016			2015			2014
Cardinal	$	1.5		$	1.7		$	1.7
Pine Needle	2.8			2.7			2.7
SouthStar	18.8			19.4			20.4
Hardy Storage	5.1			5.2			5.3
Constitution	(1.3		)	6.1			2.7
ACP	1.7			(0.6		)	—
Equity in earnings of unconsolidated affiliates	$	28.6		$	34.5		$	32.8

74

Accumulated Other Comprehensive Income (Loss)

As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. Until the sale of our interest in SouthStar as discussed above, we recorded OCIL from this investment from financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts was based on selected market indices. For these transactions with these unconsolidated affiliates, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in "Accumulated other comprehensive loss" within "Equity" on the Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments are presented in "Other Comprehensive Income (Loss), net of tax" on the Consolidated Statements of Operations and Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For the years ended October 31, 2016, 2015 and 2014, these gas costs and the amounts we owed to our unconsolidated affiliates, as of October 31, 2016 and 2015, are as follows.

Related Party	Type of Expense	Cost of Natural Gas (1)						Accounts Payable to Affiliated Companies (2)
(in millions)		2016		2015		2014		2016		2015
Cardinal	Transportation costs	$	8.7	$	8.8	$	8.8	$	0.7	$	0.7
Pine Needle	Gas storage costs	10.7		11.4		11.4		0.9		1.0
Hardy Storage	Gas storage costs	9.3		9.3		9.5		0.8		0.8
Totals		$	28.7	$	29.5	$	29.7	$	2.4	$	2.5
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Through October 3, 2016, we had related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2016, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2016 and 2015, are as follows.

	Operating Revenues (1)						Receivables from Affiliated Companies (2)
(in millions)	2016		2015		2014		2016		2015
Operating revenues	$	0.3	$	1.6	$	3.5	$	—	$	0.2
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Information on Our Equity Method Investments

Cardinal

Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and SCANA Corporation. 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.

75

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	10.3	$	9.5
Noncurrent assets	101.5		106.4
Current liabilities	46.0		1.2
Noncurrent liabilities	0.3		45.4
Revenues	16.6		16.6		$	16.7
Gross profit	16.6		16.6		16.7
Income before income taxes	7.7		7.7		8.0

Pine Needle

Pine Needle is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. We are dependent on the Williams – Transco pipeline system for redelivery of Pine Needle volumes to our system for service to our customers.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	7.7	$	9.9
Noncurrent assets	68.1		71.6
Current liabilities	3.0		5.4
Noncurrent liabilities	35.2		35.1
Revenues	17.1		16.9		$	18.0
Gross profit	15.4		15.3		15.3
Income before income taxes	6.8		6.0		6.0

SouthStar

SouthStar is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly owned subsidiary of Southern Company Gas (effective July 1, 2016 following its acquisition of AGL Resources, Inc. (AGL)). In September 2015, under the terms of the SouthStar limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to remain a member of SouthStar.

In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. In December 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective upon the consummation of the Acquisition. On October 3, 2016, we sold our 15% interest in SouthStar, and at closing, we received $160.0 million from GNGC resulting in an after-tax gain of $80.9 million.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

76

(in millions)	2016		2015		2014
Current assets	$	212.2	$	204.2
Noncurrent assets	126.8		132.3
Current liabilities	47.1		46.0
Noncurrent liabilities	—		—
Revenues	638.3		769.3		$	845.7
Gross profit	216.4		244.6		234.6
Income before income taxes	125.5		129.3		136.6

Hardy Storage

Hardy Storage is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission, LLC, an indirect subsidiary of TransCanada Corporation. 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 are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery of Hardy Storage volumes to our system for service to our customers.

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	6.6	$	11.7
Noncurrent assets	151.8		156.8
Current liabilities	14.4		19.1
Noncurrent liabilities	59.1		70.0
Revenues	23.5		23.4		$	23.8
Gross profit	23.5		23.4		23.8
Income before income taxes	11.0		10.4		10.5

Constitution

Constitution is 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 will be the operator of the pipeline. In December 2014, the FERC issued an order granting Constitution a certificate of public convenience and necessity.

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 District Court for the Northern District of New York and 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. Both courts granted Constitution's motions to expedite the schedules for the legal actions. On November 16, 2016, oral arguments were heard in the U.S. Court of Appeals.

Constitution has stated that it remains steadfastly committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC's decision. In light of the denial of the certification, Constitution revised its target in-service date of the project to be as early as the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded.

In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. On November 22, 2016, the FERC denied the NYAG's request for reconsideration of this order.

77

As a result of the NYSDEC's actions, beginning in April 2016, Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved. We evaluated our investment in the Constitution project for OTTI. 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. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are in early stages given the actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. See Note 1 for information on our fair value evaluation process.

Pending the outcome of the matters described above, and when construction proceeds, we remain 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 $955.0 million, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately $229.3 million. As of October 31, 2016, our fiscal year contributions were $12.1 million, with our total equity contributions for the project totaling $84.8 million to date. 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, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016			2015		2014
Current assets	$	6.6		$	6.2
Noncurrent assets	380.9			330.2
Current liabilities	1.2			4.4
Noncurrent liabilities	—			—
Revenues	—			—		$	—
Gross profit	—			—		—
Income (Loss) before income taxes	(3.4		)	24.6		10.1

ACP

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary is the operator of the pipeline. The pipeline is being designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date sometime in the second half of 2019, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

The total cost for the project is expected to be between $4.5 billion to $5.0 billion, excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational. As of October 31, 2016, our fiscal year contributions were $35.3 million, with our total equity contributions for the project totaling $46.0 million to date.

In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 to request FERC authorization to construct and operate the project facilities under the previously FERC-approved pre-filing process, including the environmental review for the natural gas pipeline. FERC approval of the application of the certificate of public convenience and necessity is expected in late 2017 with construction projected to begin thereafter.

78

On April 15, 2016, Dominion, on behalf of ACP, filed an updated application with the FERC. The filing included, among other items, updated alignment sheets, tables and information regarding the alternative routes adopted by the partners since filing a certificate application in September.

On August 12, 2016, the FERC issued its notice of schedule for environmental review of the project. Under the notice of schedule, we anticipate that the FERC will issue its final environmental impact statement by June 30, 2017.

On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. Based on our reduced ownership percentage, this commitment is capped at $10.6 million. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP.

On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.

Under a provision in the ACP limited liability company agreement, Dominion had an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. On October 3, 2016, in connection with the consummation of the Acquisition, Dominion purchased 3% of our 10% membership interest in ACP at book value for $13.9 million, whereby our interest in ACP was reduced to 7%.

Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.

(in millions)	2016		2015
Current assets	$	134.3	$	23.4
Noncurrent assets	376.3		86.1
Current liabilities	47.9		9.1
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income (Loss) before income taxes	17.3		(5.2		)

12. Variable Interest Entities

On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. As of October 31, 2016, 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 11. 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, and we will continue to apply equity method accounting to these investments.

Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity, as presented in Note 11.

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

79

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.

13. Business Segments

Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure 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.

The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses. See Note 11 for further information on the sale of SouthStar.

All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Prior periods' segment information has been reclassified to conform to the current year presentation. None of these segment changes impact our reported consolidated revenues or net income. Segment assets as presented in the tables that follow exclude all intercompany assets.

80

Operations by segment for the years ended October 31, 2016, 2015 and 2014, and related assets as of October 31, 2016, 2015 and 2014, are presented below.

	Year Ended October 31, 2016
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated revenues	$	1,141.7	$	—	$	1,141.7
Related party revenue from Duke Energy	7.0		—		7.0
Total Revenues	$	1,148.7	$	—	$	1,148.7
Interest Expense	$	68.6	$	—	$	68.6
Depreciation and amortization	137.3		—		137.3
Equity in earnings of unconsolidated affiliates	9.8		18.8		28.6
Gain on sale of unconsolidated affiliates	—		132.8		132.8
Income tax expense	85.2		39.0		124.2
Segment income	143.3		49.9		193.2
Capital investments and expenditures and acquisitions	$	569.2	$	—	$	569.2
Segment Assets	5,691.0		—		5,691.0
	Year Ended October 31, 2015
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,383.1	$	—	$	1,383.1
Interest Expense	68.6		—		68.6
Depreciation and amortization	128.7		—		128.7
Equity in earnings of unconsolidated affiliates	15.1		19.4		34.5
Income tax expense	85.9		4.3		90.2
Segment Income	131.1		5.9		137.0
Capital investments and expenditures and acquisitions	$	473.4	$	—	$	473.4
Segment Assets	5,045.0		41.3		5,086.3
	Year Ended October 31, 2014
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,479.5	$	—	$	1,479.5
Interest Expense	54.7		—		54.7
Depreciation and amortization	119.0		—		119.0
Equity in earnings of unconsolidated affiliates	12.3		20.5		32.8
Income tax expense	87.0		7.8		94.8
Segment Income	131.2		12.6		143.8
Capital investments and expenditures and acquisitions	$	498.1	$	—	$	498.1
Segment Assets	4,678.8		41.0		4,719.8

81

Products and Services

The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.

(in millions)	2016		2015		2014
Retail Natural Gas	$	1,066.3	$	1,237.4	$	1,300.5
Wholesale Natural Gas	72.3		134.3		169.5
Other	10.1		11.4		9.5
Total Revenues	$	1,148.7	$	1,383.1	$	1,479.5

14. Related Party Transactions with Duke Energy

Effective with the consummation of the Acquisition on October 3, 2016, we engage in related party transactions with Duke Energy and its subsidiary registrants in accordance with applicable state and federal regulations. Upon consummation of the Acquisition, our 2018 plan was converted to a Duke Energy RSU Award. Related to this conversion, $6.1 million is included in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets. See Note 9 for further information.

Amounts related to transactions with Duke Energy occurring subsequent to the consummation of the Acquisition are included in the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The following financial information reflects amounts for the years ended October 31, 2016, 2015 and 2014 related to transactions, assuming the Acquisition had taken place November 1, 2013.

(in millions)	2016		2015		2014
Revenue from Duke Energy (1)	$	80.8	$	83.2	$	86.2
Corporate governance and shared service expenses (2)	0.2
(1) We provide long-term natural gas delivery service to several of Duke Energy's subsidiaries' natural gas-fired power generation facilities in our market area. This intercompany profit on sales is not eliminated in accordance with accounting regulations prescribed under rate-based regulation, as discussed in Note 1.
(2) We are charged our proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. Certain Piedmont executives are responsible for all of Duke Energy's natural gas operations and related infrastructure. A proportionate share of these individuals' payroll and employee benefits is charged to Duke Energy's subsidiary registrants. These amounts are recorded in "Operations, maintenance and other" in the Consolidated Statements of Operations and Comprehensive Income.

See Note 10 for discussion of related party income taxes.

15. Severance

In conjunction with the Acquisition, certain Piedmont senior executives terminated their employment from Piedmont effective with the closing of the Acquisition. The severance benefits owed to these executives were provided under contracts between the individual and Piedmont, effective upon a change in control. These severances will be paid in April 2017.

In September 2016, Piedmont announced a severance plan covering certain eligible employees whose employment will be involuntarily terminated without cause during the twelve-month period (or twenty-four months for certain senior level employees) following the close of the Acquisition. Upon the close of the Acquisition, positions within Piedmont began to be eliminated. These reductions are a part of the synergies expected to be realized with the Acquisition. The severance benefit payments will be made in accordance with the severance plan.

We recorded $18.7 million severance and related expenses that are included in "Operations, maintenance and other" on the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The severance liability was also $18.7 million as of October 31, 2016 and is included in "Other" within "Current Liabilities" on the Consolidated Balance Sheets. Additional accruals can continue through October 3, 2018 as more positions are eliminated.

82

16. Reclassification of Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows

Reclassifications have been made to prior year Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows.

In the first quarter of 2016, we early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. With the retrospective adoption of the new pronouncement, the fiscal year 2015 current line item of "Deferred income taxes" of $32.4 million was reclassified to net with the noncurrent line item "Deferred income taxes," similarly reducing "Total Assets" and "Total Liabilities and Equity."

Reclassifications have also been made to conform to the presentation currently used by Piedmont’s new parent company, Duke Energy. None of these reclassifications had a significant effect on the previously reported results of operations, financial position or cash flows of Piedmont but were rather the movement of line items or accounts to conform to Duke Energy’s presentation.

The effect on our Consolidated Statements of Operations and Comprehensive Income was largely related to the statement presentation. Piedmont previously used a utility income statement presentation showing a line item of "Margin" on the face of the income statement that is defined as natural gas revenues less natural gas commodity and fixed gas costs. With Duke Energy’s presentation, the line item of "Cost of natural gas" is presented within "Operating Expenses" with no presentation of regulated margin. See the discussion of regulated margin in "Results of Operations" presented in Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K. Also, we reclassified previously reported utility income taxes of $76.9 million and $83.2 million from line item "Total operating expenses" and non-utility income taxes of $13.3 million and $11.6 million from line item “Total other income (expense)” to the new line item "Income Tax Expense" for the years ended October 31, 2015 and 2014, respectively. These two changes in presentation had no effect on net income.

The effect on our Consolidated Statements of Cash Flows for the years ended October 31, 2015 and 2014 reflects the reclassifications of the balance sheet line items. These reclassifications had no effect on previously reported amounts for net cash provided by operating activities and by financing activities or net cash used in investing activities for the periods previously presented.

17. 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. See Note 3 for information on subsequent event disclosure items related to regulatory matters.

18. Quarterly Financial Data (In millions except per share amounts) (Unaudited)

On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. As a result of the Acquisition, the Consolidated Financial Statements for our fiscal year ended October 31, 2015 have been reclassified to conform to the presentation of Duke Energy, our parent.

83

The following table reflects the reclassification of our Consolidated Statements of Operations and Comprehensive Income to conform to Duke Energy's presentation.

			Operating				Net
	Operating		Income				Income
	Revenues		(Loss)				(Loss)
Fiscal Year 2016
January 31	$	463.5	$	171.3			$	97.8
April 30	352.9		103.9				63.4
July 31	160.4		0.5				(6.7		)
October 31	171.9		(50.3		)	(1)	38.7			(2)
Fiscal Year 2015
January 31	$	609.5	$	162.2			$	93.0
April 30	427.3		111.1				66.4
July 31	162.2		(1.7		)		(8.3		)
October 31	184.1		(8.8		)		(14.1		)
(1) The quarter loss is primarily due to Acquisition and integration-related expenses incurred in 2016. See Note 2 for further information.
(2) The increase is primarily due to the gain on the sale of our 15% ownership interest in SouthStar, partially offset by Acquisition and integration-related expenses. See Note 11 for further information on the sale of SouthStar.

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share were calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities and Exchange Act 1934 (Exchange Act) is recorded, processed, summarized and reported, within the time periods specified by the SEC rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of October 31, 2016, and based upon this evaluation, the Chief Executive Officer and the Executive Vice President and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

84

Changes in Internal Control Over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and the Executive Vice President and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended October 31, 2016, and have concluded no change has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

85

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

December 22, 2016

Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). The Company’s 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 in the United States. Due to inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness of internal controls over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Our management, including the Chief Executive Officer and the Executive Vice President and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of October 31, 2016, based upon the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that its internal controls over financial reporting were effective as of October 31, 2016.

86

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information for this item has been omitted as Piedmont Natural Gas Company, Inc. is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and afforded relief under General Instruction I (2)(c) to such Form 10-K.

Item 11. Executive Compensation

Information for this item has been omitted as Piedmont Natural Gas Company, Inc. is a wholly owned subsidiary of Duke Energy and afforded relief under General Instruction I (2)(c) to such Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information for this item has been omitted as Piedmont Natural Gas Company, Inc. is a wholly owned subsidiary of Duke Energy and afforded relief under General Instruction I (2)(c) to such Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information for this item has been omitted as Piedmont Natural Gas Company, Inc. is a wholly owned subsidiary of Duke Energy and afforded relief under General Instruction I (2)(c) to such Form 10-K.

Item 14. Principal Accounting Fees and Services

The aggregate fees and reimbursable expenses for professional services provided by Deloitte & Touche LLP (Deloitte) that were billed or accrued for the fiscal years ended October 31, 2016 and 2015, are:

(in millions)	2016			2015
Fees for Services
Audit Fees	$	1.3		$	1.1
Audit-Related Fees	0.1		(a)	0.2		(b)
Tax Fees	—			—
All Other Fees	—			—
Total Fees	$	1.4		$	1.3
(a) Consists of services related to the issuance by Deloitte of comfort and bring-down letters in relation to our 2016 debt offering and at-the-market (ATM) offering and consultation services.
(b) Consists of services related to the issuance by Deloitte of comfort and bring-down letters in relation to our 2015 debt offering and ATM offering, our registration statement on Form S-8 and consultation services.

On October 3, 2016, the merger was consummated between Duke Energy and Piedmont and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Agreement and Plan of Merger provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). Prior to the consummation of the Acquisition, our Audit Committee approved, in advance, all services by the independent registered public accounting firm during fiscal years 2016 and 2015, whether or not related to the audit. The Audit Committee delegated to the Chair of the Audit Committee (Chair) the authority to grant such approvals. Services approved by the Chair were required to be presented to the full Audit Committee for ratification at the next regularly scheduled Audit Committee meeting. There were no services performed during fiscal 2016 requiring approval after the consummation of the Acquisition.

87

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	1.	Financial Statements
The following Consolidated Financial Statements for the year ended October 31, 2016, are included in Item 8 of this report as follows:
Consolidated Statements of Operations and Comprehensive Income – Years Ended October 31, 2016, 2015 and
2014
Consolidated Balance Sheets – October 31, 2016 and 2015 Consolidated Statements of Cash Flows – Years Ended October 31, 2016, 2015 and 2014 Consolidated Statements of Changes in Equity – Years Ended October 31, 2016, 2015 and 2014 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 incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.
	2.1	Agreement and Plan of Merger, dated as of October 24, 2015, by and among Duke Energy Corporation, Forest Subsidiary, Inc. and Piedmont Natural Gas Company, Inc. (incorporated by reference to Exhibit 2.1, Form 8-K dated October 26, 2015).
	3.1	Amended and Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of October 3, 2016.
	3.2	Bylaws of Piedmont Natural Gas Company, Inc., as amended and restated effective October 3, 2016 (incorporated by reference to Exhibit 3.2, Form 8-K dated October 3, 2016).
	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, Form 10-K for the fiscal year ended October 31, 1992).
	4.2	Amendment to September 1992 Note Agreement, dated as of September 16, 2005, by and between Piedmont and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
	4.3	Indenture, dated as of April 1, 1993, between Piedmont and The Bank of New York Mellon Trust Company, N.A. (as successor to Citibank, N.A.), Trustee (incorporated by reference to Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).

88

4.4	Medium-Term Note, Series A, dated as of October 6, 1993 (incorporated by reference to Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).
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	Medium-Term Note, Series A, dated as of September 19, 1994 (incorporated by reference to Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).
4.7	Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 33-59369).
4.8	Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (incorporated by reference to Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).
4.9	Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (incorporated by reference to Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).
4.10	Form of Master Global Note (incorporated by reference to Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).
4.11	Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (incorporated by reference to Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).
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	Agreement of Resignation, Appointment and Acceptance dated as of March 29, 2007, by and among Piedmont Natural Gas Company, Inc., Citibank, N.A., and The Bank of New York Trust Company, N.A. (incorporated by reference to Exhibit 4.1, Form 10-Q for quarter ended April 30, 2007).
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 4.24% Series B Senior Notes due June 6, 2021 (incorporated by reference to Exhibit 4.2, Form 8-K dated May 12, 2011).
4.18	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).

89

4.19	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, Form 10-Q for the quarter ended April 30, 2011).
4.20	Note Purchase Agreement, dated as of March 27, 2012, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1, Form 8-K dated March 29, 2012).
4.21	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).
4.22	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).
4.23	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).
4.24	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).
4.25	Form of 4.65% Senior Notes due 2043 (incorporated by reference to Exhibit 4.2, Form 8-K dated August 1, 2013).
4.26	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).
4.27	Form of 4.10% Senior Notes due 2034 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 18, 2014).
4.28	Third Amendment to September 1992 Note Agreement, dated as of October 15, 2014, between the Company and Provident Life and Accident Insurance Company (incorporated by reference to Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 2014).
4.29	Seventh Supplemental Indenture, dated September 14, 2015, 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 14, 2015).
4.30	Form of 3.60% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, Form 8-K dated September 14, 2015).
4.31	Eighth Supplemental Indenture, dated July 28, 2016, 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 July 28, 2016).
4.32	Form of 3.64% Senior Notes due 2046 (incorporated by reference to Exhibit 4.2, Form 8-K dated July 28, 2016).

90

10.1	Form of Commercial Paper Dealer Agreement between Piedmont Natural Gas Company, Inc. and Dealers party thereto (incorporated by reference to Exhibit 10.3, Form 10-Q for the quarter ended April 30, 2012).
10.2	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).
10.3	Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC dated April 9, 2012, by and among Williams Partners Operating LLC and Cabot Pipeline Holdings LLC (incorporated by reference to Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2013).
10.4	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, Form 10-Q for the quarter ended January 31, 2013).
10.5	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, Form 8-K filed September 4, 2013).
10.6	Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated as of September 1, 2013, by and between Georgia Natural Gas Company and Piedmont Energy Company (incorporated by reference to Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 2013).
10.7	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).
10.8 *	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, Form 10-K for the fiscal year ended October 31, 2014).
10.9	ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 1.1, Form 8-K dated January 7, 2015).
10.10	ATM Equity Offering Sales Agreement dated January 7, 2015 between the Company and J.P. Morgan Securities LLC (incorporated by reference to Exhibit 1.2, Form 8-K dated January 7, 2015).
10.11	Second Amended and Restated Credit Agreement, dated as of December 14, 2015, among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender, L/C Issuer and a Lender, and 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 a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated December 16, 2015).

91

10.12	Letter Agreement between Georgia Natural Gas Company and Piedmont Energy Company dated February 12, 2016 (incorporated by reference to Exhibit 10.1, Form 8-K dated February 18, 2016).
10.13	Assignment of Membership Interests dated as of October 3, 2016 between Piedmont ACP Company, LLC and Dominion Atlantic Coast Pipeline, LLC, (incorporated by reference to Exhibit 10.1, Form 8-K dated October 7, 2016).
10.14	Conveyance and Assignment Agreement, dated as of October 3, 2016, by and between Piedmont Energy Company and Georgia Natural Gas Company (incorporated by reference to Exhibit 10.1, Form 8-K dated October 3, 2016).
12	Computation of Ratio of Earnings to Fixed Charges.
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.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
*	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.
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 Statements of Operations and Comprehensive Income for the years ended October 31, 2016, 2015 and 2014; (3) Consolidated Balance Sheets as of October 31, 2016 and 2015; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2016, 2015 and 2014; (5) Consolidated Statements of Changes in Equity for the years ended October 31, 2016, 2015 and 2014; and Notes to Consolidated Financial Statements.

92

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:	December 22, 2016
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 dates indicated.

	Signature
(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.
	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: December 22, 2016

93

	Piedmont Natural Gas Company, Inc.
	Form 10-K
	For the Fiscal Year Ended October 31, 2016
	Exhibits
3.1	Amended and Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of October 3, 2016
12	Computation of Ratio of Earnings to Fixed Charges
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

94

EX-3.1

Exhibit 3.1

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

PIEDMONT NATURAL GAS COMPANY, INC.

Pursuant to § 55-2-02 of the North Carolina Business Corporation Act (the “Act”), Piedmont Natural Gas Company, Inc., a North Carolina corporation, does hereby submit these Amended and Restated Articles of Incorporation.

FIRST: The name of the corporation is Piedmont Natural Gas Company, Inc.

SECOND: The number of shares the corporation is authorized to issue is one hundred (100) shares of common stock, no par value per share.

THIRD: The street and mailing address and county of the registered office of the corporation is 160 Mine Lake Court, Suite 200, Wake County, Raleigh, NC 27615. The name of the registered agent of the corporation at such address is CT Corporation System. The mailing address of the corporation’s registered office is the same as its street address.

FOURTH: The street and mailing address and county of the principal office of the corporation is 4720 Piedmont Row Drive, Mecklenburg County, Charlotte, North Carolina 28210.

FIFTH: (a) A director of the corporation shall not be personally liable to the corporation or any of its shareholders for monetary damages for any breach of duty as a director, except for liability with respect to (i) acts or omissions not made in good faith that the director at the time of such breach knew or believed were in conflict with the best interests of the corporation; (ii) any liability under § 55-8-33 of the Act (liability for unlawful distributions); (iii) any transaction from which such director derived an improper personal benefit; or (iv) acts or omissions occurring prior to the date on which this Article 5 became effective. As used herein, the term “improper personal benefit” does not include a director’s compensation or other incidental benefit for or on account of service as a director, officer, employee, independent contractor, attorney or consultant of the corporation. If the North Carolina General Statutes are amended to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director of the corporation shall be eliminated or limited to the fullest extent permitted by the North Carolina General Statutes, as so amended. No amendment or repeal of the provisions of this Article 5 shall apply to or have any effect on the liability or alleged liability of any director of the corporation for or with respect to any act or failure to act on the part of such director occurring prior to such amendment or repeal. The provisions of this Article 5 shall not be deemed to limit or preclude indemnification of a director by the corporation for any liability which has not been eliminated by the provisions of this Article 5.

(b)    The provisions of Article 9 and Article 9A of the Act, entitled “The North Carolina Shareholder Protection Act” and “The North Carolina Control Share Acquisition Act,” respectively, shall not be applicable to the corporation.

(c)    To the extent permitted by the Act, any action required or permitted to be taken at a meeting of the shareholders may be taken without a meeting and without prior notice, if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take the action at a meeting at which all shareholders entitled to vote thereon were present and voted. A shareholder’s consent to action taken without meeting may be by electronic mail or in any other electronic form and delivered by electronic means. Except as expressly set forth in these Restated Articles of Incorporation, if shareholder approval is obtained by action without meeting for (i) an amendment to the corporation’s articles of incorporation, (ii) a plan of merger or share exchange, (iii) a plan of conversion, (iv) the sale, lease, exchange or other disposition of all, or substantially all, of the corporation’s property, or (v) a proposal for dissolution, the corporation shall not be required to give any shareholder notice of the proposed action at any time before the action is taken.

EX-12

									Exhibit 12
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
For Fiscal Years Ended October 31, 2012 through 2016
(in millions except ratio amounts)
	2016		2015		2014		2013		2012
Earnings:
Pre-tax income from continuing operations	$	153.5	$	191.9	$	205.1	$	193.1	$	171.7
Distributed income of unconsolidated affiliates	43.8		26.4		28.8		26.8		25.0
Fixed charges	82.4		81.3		72.6		57.5		47.0
Total Adjusted Earnings	$	279.7	$	299.6	$	306.5	$	277.4	$	243.7
Fixed Charges:
Interest	$	79.4	$	78.4	$	69.9	$	54.8	$	43.9
Amortization of debt expense	1.4		1.3		1.2		1.0		1.4
Amortization of loss - reacquired debt	0.2		0.2		0.2		0.2		0.2
One-third of rental expense	1.4		1.4		1.3		1.5		1.5
Total Fixed Charges	$	82.4	$	81.3	$	72.6	$	57.5	$	47.0
Ratio of Earnings to Fixed Charges	3.40		3.68		4.22		4.82		5.19

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-196561 on Form S-3ASR of our report dated December 22, 2016, relating to the consolidated financial statements of Piedmont Natural Gas Company, Inc. and subsidiaries (a wholly owned subsidiary of Duke Energy Corporation), appearing in this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc. and subsidiaries for the year ended October 31, 2016.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 22, 2016

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Lynn J. Good, certify that:

1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	December 22, 2016
/s/ LYNN J. GOOD
Lynn J. Good
Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Steven K. Young, certify that:

1. I have reviewed this Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	December 22, 2016
/s/ STEVEN K. YOUNG
Steven K. Young
Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”) on Form 10-K for the period ending October 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lynn J. Good, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ LYNN J. GOOD

Lynn J. Good

Chief Executive Officer

December 22, 2016

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Annual Report of Piedmont Natural Gas Company, Inc. (the “Company”) on Form 10-K for the period ending October 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Steven K. Young, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ STEVEN K. YOUNG

Steven K. Young

Executive Vice President and Chief Financial Officer

December 22, 2016

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - USD ($)	12 Months Ended
	Oct. 31, 2016	Oct. 03, 2016	Apr. 30, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	0000078460
Current Fiscal Year End Date	--10-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Oct. 31, 2016
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2016
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		0
Entity Public Float			$ 0

XML

Consolidated Statements of Operations and Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Oct. 31, 2016		Oct. 31, 2015	Oct. 31, 2014
Operating Revenues
Regulated natural gas (1)	[1]	$ 1,131.6		$ 1,371.7	$ 1,470.0
Nonregulated and other		10.1		11.4	9.5
Related party revenue from Duke Energy (2)		7.0	[2]
Total operating revenues		1,148.7		1,383.1	1,479.5
Operating Expenses
Cost of natural gas (1)	[1]	390.5		644.4	779.8
Operations, maintenance and other		352.9		304.8	279.9
Depreciation and amortization		137.3		128.7	119.0
Property and other taxes		42.6		42.4	37.7
Total operating expenses		923.3		1,120.3	1,216.4
Operating Income		225.4		262.8	263.1
Other Income and Expense
Equity in earnings of unconsolidated affiliates		28.6		34.5	32.8
Gain on sale of unconsolidated affiliates		132.8		0.0	0.0
Other expense, net		0.8		1.5	2.6
Total other income and expense		160.6		33.0	30.2
Interest Expense		68.6		68.6	54.7
Income Before Income Taxes		317.4		227.2	238.6
Income Tax Expense		124.2		90.2	94.8
Net Income		193.2		137.0	143.8
Unrealized (loss) gain from hedging activities, net of tax of ($2.5), ($1.0) and $0.2 for the years ended October 31, 2016, 2015 and 2014, respectively		(2.8)		(1.6)	0.3
Reclassification adjustment of realized loss (gain) from hedging activities of equity method investments included in net income, net of tax of $2.0, $0.7 and ($0.2) for the years ended October 31, 2016, 2015 and 2014, respectively		3.4		1.0	(0.3)
Other Comprehensive Income (Loss), net of tax		0.6		(0.6)	0.0
Comprehensive Income		$ 193.8		$ 136.4	$ 143.8

[1] See Note 11 for amounts attributable to investments in unconsolidated affiliates.

[2] See Note 14 for details on related party transactions with Duke Energy.

XML

Consolidated Statements of Operations and Comprehensive Income (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Statement of Comprehensive Income [Abstract]
Unrealized (loss) gain from hedging activities, tax	$ (2.5)	$ (1.0)	$ 0.2
Reclassification adjustment of realized loss (gain) from hedging activities of equity method investments included in net income, tax	$ 2.0	$ 0.7	$ (0.2)

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Oct. 31, 2016	Oct. 31, 2015
Current Assets
Cash and cash equivalents		$ 16.6	$ 13.7
Receivables (less allowance for doubtful accounts of $1.9 in 2016 and $1.6 in 2015)		75.2	86.9
Receivables from affiliated companies (1) (2)	[1],[2]	7.0	0.2
Inventory		55.6	69.5
Regulatory assets		113.7	19.1
Prepaids		27.2	28.9
Other		12.0	12.8
Total current assets		307.3	231.1
Investments and Other Assets
Investments in equity method unconsolidated affiliates		199.2	207.0
Goodwill		48.9	48.9
Other		10.9	53.1
Total investments and other assets		259.0	309.0
Property, Plant and Equipment
Cost		6,079.1	5,601.3
Accumulated depreciation and amortization		(1,329.5)	(1,252.9)
Net property, plant and equipment		4,749.6	4,348.4
Regulatory Assets and Deferred Debits
Regulatory assets		373.3	196.7
Other		1.8	1.1
Total regulatory assets and deferred debits		375.1	197.8
Total Assets		5,691.0	5,086.3
Current Liabilities
Accounts payable		130.5	120.3
Accounts payable to affiliated companies (1) (2)	[1],[2]	8.7	2.5
Notes payable and commercial paper		145.0	340.0
Taxes accrued		68.4	30.3
Interest accrued		29.3	29.5
Current maturities of long-term debt		35.0	40.0
Regulatory liabilities		0.0	21.5
Gas supply derivative liabilities, at fair value		41.5	0.0
Other		61.7	59.3
Total current liabilities		520.1	643.4
Long-Term Debt		1,786.0	1,523.7
Deferred Credits and Other Liabilities
Deferred income taxes		904.1	829.2
Investment tax credits		0.9	1.0
Accrued pension and other post-retirement benefit costs		23.4	15.1
Asset retirement obligations		14.1	19.7
Regulatory liabilities		617.0	590.3
Other		180.5	37.6
Total deferred credits and other liabilities		1,740.0	1,492.9
Commitments and Contingencies
Equity
Common stock, no par value: 100 shares authorized and outstanding in 2016 and 200.0 million authorized and 80.9 million outstanding in 2015		859.8	721.4
Retained earnings		785.3	705.7
Accumulated other comprehensive loss		(0.2)	(0.8)
Total equity		1,644.9	1,426.3
Total Liabilities and Equity		$ 5,691.0	$ 5,086.3

[1] See Note 11 for amounts attributable to investments in unconsolidated affiliates.

[2] See Note 14 for details on related party transactions with Duke Energy.

XML

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Millions	Oct. 31, 2016	Oct. 31, 2015
Allowance for doubtful accounts	$ 1.9	$ 1.6
Common stock par value	$ 0	$ 0
Common stock shares authorized		200,000,000
Common stock shares outstanding		80,900,000
Successor
Common stock shares authorized	100
Common stock shares outstanding	100

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITES
Net income	$ 193.2	$ 137.0	$ 143.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	148.3	140.2	129.3
Provision for doubtful accounts	4.9	5.1	7.0
Impairment charges	0.0	0.0	2.0
Net gain on sale of property	0.0	0.0	(0.8)
Net gain on sale of interests in unconsolidated affiliates, net of tax	(80.9)	0.0	0.0
Deferred income taxes, net	74.2	73.0	87.2
Equity in earnings of unconsolidated affiliates	(28.6)	(34.5)	(32.8)
Distributions of earnings from unconsolidated affiliates	25.8	24.9	24.8
Accrued/deferred postretirement benefit costs	12.4	2.2	5.9
Contributions to benefit plans	(14.0)	(12.7)	(22.5)
Settlement of legal asset retirement obligations	(6.4)	(5.6)	(3.5)
Receivables, net	6.9	(2.6)	9.7
Receivables from affiliated companies	(7.0)
Inventory	13.9	16.3	(10.1)
Regulatory assets	(291.6)	(24.0)	21.2
Other current assets	2.4	38.4	(12.0)
Accounts payable	6.2	(5.1)	(4.7)
Accounts payable to affiliated companies	6.3
Taxes accrued	(13.7)	3.8	3.6
Gas supply derivatives, at fair value	187.9	0.0	0.0
Other current liabilities	(13.5)	(20.5)	51.1
Other assets	58.2	7.4	20.7
Other liabilities	23.5	28.3	10.7
Net cash provided by operating activities	308.4	371.6	430.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(521.8)	(443.7)	(460.5)
Allowance for borrowed funds used during construction	(12.3)	(11.1)	(16.4)
Investment expenditures	(47.4)	(29.7)	(37.6)
Distributions of capital from unconsolidated affiliates	18.0	1.5	3.9
Net proceeds from the sales of interests in unconsolidated affiliates and other assets	174.5	0.7	1.9
Other	15.3	3.9	4.2
Net cash used in investing activities	(373.7)	(478.4)	(504.5)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	299.6	149.9	249.6
Issuance of common stock related to employee benefit plans	17.0	27.0	25.6
Issuance of common stock, net of expense	104.6	53.7	47.3
Redemptions of long-term debt	(40.0)	0.0	(100.0)
Expenses related to issuance of debt	(4.3)	(1.3)	(2.9)
Notes payable and commercial paper	(195.0)	(15.0)	(45.0)
Dividends paid	(113.7)	(103.4)	(99.2)
Net cash provided by financing activities	68.2	110.9	75.4
Net increase in cash and cash equivalents	2.9	4.1	1.5
Cash and cash equivalents at beginning of period	13.7	9.6	8.1
Cash and cash equivalents at end of period	16.6	13.7	9.6
Supplemental Disclosures:
Cash paid for interest, net of amount capitalized	81.4	71.5	64.3
Cash (received from) paid for income taxes	(24.5)	3.2	10.8
Significant non-cash transactions:
Accrued capital expenditures	$ 62.8	$ 58.9	$ 38.9

XML

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Stockholders' Equity, beginning balance at Oct. 31, 2013	$ 1,188.6	$ 561.6	$ 627.2	$ (0.2)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	143.8		143.8
Other comprehensive income (loss), net of tax	0.0			0.0
Common stock issuances, including dividend reinvestment and employee benefits	75.2	75.2
Expenses from Issuance of Common Stock	0.0	0.0
Tax Benefit from Dividends Paid on ESOP Shares	0.2		0.2
Common stock dividends	(99.2)		(99.2)
Stockholders' Equity, ending balance at Oct. 31, 2014	1,308.6	636.8	672.0	(0.2)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	137.0		137.0
Other comprehensive income (loss), net of tax	(0.6)			(0.6)
Common stock issuances, including dividend reinvestment and employee benefits	85.0	85.0
Expenses from Issuance of Common Stock	(0.4)	(0.4)
Tax Benefit from Dividends Paid on ESOP Shares	0.1		0.1
Common stock dividends	(103.4)		(103.4)
Stockholders' Equity, ending balance at Oct. 31, 2015	1,426.3	721.4	705.7	(0.8)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	(0.8)
Net income	193.2		193.2
Other comprehensive income (loss), net of tax	0.6			0.6
Common stock issuances, including dividend reinvestment and employee benefits	138.5	138.5
Expenses from Issuance of Common Stock	(0.1)	(0.1)
Tax Benefit from Dividends Paid on ESOP Shares	0.1		0.1
Common stock dividends	(113.7)		(113.7)
Stockholders' Equity, ending balance at Oct. 31, 2016	1,644.9	$ 859.8	$ 785.3	$ (0.2)
Income Loss Hedging Activities Of Equity Method Investments [Abstract]
Hedging activities of equity method investments	$ (0.2)

XML

Summary of Significant Accounting Policies

12 Months Ended

Oct. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont Natural Gas Company, Inc. is an energy services company 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 regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. With the October 3, 2016 sale of our 15% membership interest in SouthStar Energy Services, LLC (SouthStar), we are no longer invested in the unregulated retail natural gas marketing business; see Note 11 for further information on this sale. Our utility operations are regulated by three state regulatory commissions; see Note 3 for further information on regulatory matters. Unless the context requires otherwise, references to "we," "us," "our," "the Company" or "Piedmont" means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

The Consolidated Financial Statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The Consolidated Financial Statements reflect 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. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

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 "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. Gain from the sale of membership interests in our joint ventures are recorded in "Gain on sale of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. See Note 11 for further information on investments in unconsolidated affiliates and related party transactions with these affiliates.

On October 24, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy). On October 3, 2016, the merger was consummated between Duke Energy and Piedmont and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provided for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). The Acquisition was recorded using the acquisition method of accounting. Under SEC regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements. These adjustments will be recorded by Duke Energy. See Note 2 for further information.

The information presented in this Form 10-K for the fiscal years ended October 31, 2016, 2015 and 2014 are presented solely for the registrant Piedmont on a stand-alone basis. The Consolidated Financial Statements for the 2015 and 2014 periods have been reclassified to conform to Duke Energy's financial statement format. See Note 16 for further information on the reclassification of our Consolidated Financial Statements. Also, Duke Energy and Piedmont performed a comparative analysis of accounting policies with no significant differences except for actuarial assumptions for pension and other postretirement benefit plans. See Note 8 for the discussion of the change of the discount rate in actuarial assumptions.

Use of Estimates

In accordance with GAAP, we 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 during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by 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 effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, 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 by 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 the 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 by the state regulatory commissions.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are probable of recovery in current rates or in future rate proceedings.

Net Property, Plant and Equipment

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, where the costs of homogeneous assets are aggregated 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 that is recorded in "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income.

The classification of net property, plant and equipment for the years ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Intangible plant	$	3.4		$	3.4
Other storage plant	189.1			181.0
Transmission plant	2,315.8			2,024.3
Distribution plant	2,864.7			2,766.9
General plant	469.7			452.3
Asset retirement cost	—			4.1
Contributions in aid of construction	(5.6		)	(5.4		)
Total utility plant in service	5,837.1			5,426.6
Construction work in progress	233.0			170.3
Plant held for future use	7.7			3.1
Other property	1.3			1.3
Total cost	6,079.1			5,601.3
Utility plant in service accumulated depreciation	(1,328.6		)	(1,252.0		)
Other property accumulated depreciation and amortization	(0.9		)	(0.9		)
Total accumulated depreciation and amortization	(1,329.5		)	(1,252.9		)
Total net property, plant and equipment	$	4,749.6		$	4,348.4

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.

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 reduces "Interest Expense" on the Consolidated Statements of Operations and Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. For the three years ended October 31, 2016, 2015 and 2014, all of our AFUDC was attributable to borrowed funds.

AFUDC for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
AFUDC	$	12.3	$	11.1	$	16.4

In accordance with utility accounting practice, we classify costs incurred for utility plant that is not in service to be "Plant held for future use" in "Cost" within "Property, Plant and Equipment" on the Consolidated Balance Sheets. Since March 2009 when construction was suspended, we classified real estate and development costs associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina as "Plant held for future use." 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 are recorded as a regulatory asset with amortization over 38 months beginning January 1, 2014 through February 2017. During fiscal 2016, we reclassified $4.6 million of project costs recorded as "Construction work in progress" to "Plant held for future use." We intend to resume the project when future economic conditions become more favorable.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 80 years. The composite weighted average depreciation rates were 2.44% for 2016, 2.48% for 2015 and 2.54% for 2014.

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 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;" see Note 3 for the amount of these removal costs in "Rate-Regulated Basis of Accounting." See "Asset Retirement Obligations" in this Note 1 for further discussion of this regulatory liability.

Cash and Cash Equivalents

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents. We have no material restrictions on our cash balances as of October 31, 2016 and 2015.

Receivables and Allowance for Doubtful Accounts

Receivables consist of natural gas sales and transportation services, unbilled revenues, and other miscellaneous receivables, including merchandise and service work, construction related receivables and other miscellaneous receivables. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based 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 Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual 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 regulated 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" within "Investments and Other Assets" on the Consolidated Balance Sheets.

We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2016 and 2015, our receivables and allowance for doubtful accounts consisted of the following.

(in millions)	2016			2015
Gas receivables	$	43.1		$	57.6
Unbilled revenues	13.4			17.4
Other miscellaneous receivables	20.6			13.5
Allowance for doubtful accounts	(1.9		)	(1.6		)
Receivables and Allowance for Doubtful Accounts	$	75.2		$	86.9

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Balance at beginning of year	$	1.6		$	2.2		$	1.6
Additions charged to uncollectibles expense	4.9			5.1			7.0
Accounts written off, net of recoveries	(4.6		)	(5.7		)	(6.4		)
Balance at end of year	$	1.9		$	1.6		$	2.2

See Note 6 for further information on credit risk in "Credit and Counterparty Risk."

Inventory

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 release the transportation capacity and storage capacity to the asset manager and may assign the gas supply and/or storage inventory 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 "Inventory." From the period of April through October, the inventory that is not available for our use is reclassified on the Consolidated Balance Sheets in "Prepaids," and the inventory that is available for our use remains in "Inventory."

As of October 31, 2016 and 2015, such counterparties held natural gas storage assets as recorded in "Prepaids," with a value of $21.3 million and $24.8 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 us. The AMAs expire at various times through January 31, 2026. See Note 3 for further information on the revenue sharing of secondary market transactions.

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 value in the Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option 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. As discussed below, beginning with the year ended October 31, 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.

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 for the specific instrument, location or commodity being valued. 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 maturity and settlement of our 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 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 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.

Beginning with the year ended October 31, 2016, we have long-dated, fixed quantity natural gas supply contracts for our regulated utility operations which are accounted for as derivatives. We have classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third-party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. See Note 6 for further information on our fair value measurements of our derivatives and marketable securities. See Note 8 for further information for the fair value measurements of our benefit plan assets.

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.

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, 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. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segment as discussed in Note 13. 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 our regulated utility operations.

Our annual goodwill impairment assessment as of October 31, 2016 was performed using a qualitative approach. As part of our qualitative assessment, we considered macroeconomic conditions such as general deterioration in economic condition, limitations on accessing capital and other developments in equity and credit markets. We evaluated industry and market considerations for any deterioration in the environment in which we operate, the increased competitive environment, a decline (both absolute and relative to our peers) in market-dependent multiples or metrics, any changes in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors, such as increases in utility construction expenditures, labor or other costs, that would have a negative effect on earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility operations which would have a negative effect on the carrying value of the reporting unit.

Based on our qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test of our 2016 goodwill. The annual goodwill impairment assessments performed have indicated that it is more likely than not that the fair value of the reporting unit is substantially in excess of carrying value and not at risk of failing step one of the quantitative goodwill impairment test. No impairment was recognized during the years ended October 31, 2016, 2015 and 2014.

On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. Each equity method investment is recorded at cost plus its post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. See Note 11 for further information on our OTTI assessment of one of our equity method investments.

In April 2014, we recorded a $2.0 million write-off for an investment that was accounted for on the cost basis. The write-off was recorded to "Other expense, net" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income. There were no events or circumstances during the years ended October 31, 2016 and 2015 that resulted in any impairment charges.

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. See Note 8 for further information on the deferred compensation plans.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets in "Other" within "Investments and Other Assets" with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their deemed investments at any time.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2016 and 2015 is as follows.

	2016				2015
(in millions)	Cost		Fair Value		Cost		Fair Value
Money markets	$	0.5	$	0.5	$	0.5	$	0.5
Mutual funds	3.2		3.7		3.8		4.4
Total trading securities	$	3.7	$	4.2	$	4.3	$	4.9

Issuances and Repurchases of Common Stock

As discussed in Note 4, prior to the consummation of the Acquisition on October 3, 2016, from time to time, we have repurchased shares on the open market and such shares were then canceled and became authorized but unissued shares. It was our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. In anticipation of the Acquisition by Duke Energy, we suspended new investments in our employee plans effective July 31, 2016.

We present net shares issued under these awards and plans in "Common stock issuances, including dividend reinvestment and employee benefits" in the Consolidated Statements of Changes in Equity.

Upon consummation of the Acquisition, our common stock was delisted from the New York Stock Exchange (NYSE).

Asset Retirement Obligations

The accounting guidance for asset retirement obligations (AROs) addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that conditional AROs exist for our underground mains and services.

We have costs of removal that are non-legal obligations as defined by the accounting guidance. The costs of removal are a component of our depreciation rates in accordance with long-standing regulatory treatment. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs in "Regulatory Liabilities" as presented in Note 3. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which our regulated utility operations have the opportunity to earn its allowed rate of return. See "Net Property, Plant and Equipment" in this Note 1, for further discussion of these costs of removal as a component of depreciation.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Operations and Comprehensive Income as the regulatory treatment provides for deferral of the accretion as a regulatory asset with a corresponding deferral of the accretion recorded as a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the regulatory liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage 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 4.62% to 5.89% with a time value weighted average of 5.69% for the twelve months ended October 31, 2016. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016		2015
Regulatory non-legal AROs	$	538.0	$	521.5
Conditional AROs	14.1		19.7
Total cost of removal obligations	$	552.1	$	541.2

A reconciliation of the changes in conditional AROs for the year ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Beginning of period	$	19.7		$	14.7
Liabilities incurred during the period	5.5			4.7
Liabilities settled during the period	(6.5		)	(5.6		)
Accretion	1.1			0.9
Adjustment to estimated cash flows	(5.7		)	5.0
End of period	$	14.1		$	19.7

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 expense 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. Long-term debt is presented net of unamortized debt expenses in the accompanying Consolidated Balance Sheets. For further information on the effects on regulatory assets and our long-term debt, see Note 3 and Note 5, respectively.

We amortize bank debt expense over the life of the syndicated revolving credit facility, which is 5 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 debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability 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.

Revenue Recognition and Unbilled Revenue

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 gas component of rates may be adjusted periodically under PGA provisions. In North Carolina, a margin decoupling mechanism provides for 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 margin or to recover any under-collection of margin. In South Carolina, a rate stabilization adjustment (RSA) mechanism achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA 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 October through April. 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 initially approved in December 2013 in the settlement of our 2013 general rate case and subsequently revised in November 2015. Under the revised North Carolina IMR tariff, we make filings semi-annually each October 31 and April 30 for certain costs closed to plant through September and March, respectively, with revised rates effective the following December 1 and June 1, respectively. Under the Tennessee IMR, we 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. See Note 3 for further discussion of the IMRs.

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. 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. As of October 31, 2016 and 2015, unbilled revenues of $13.4 million and $17.4 million, respectively, are included within "Receivables" on the Consolidated Balance Sheets.

Secondary market revenues 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 sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 3 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. See "Taxes" in this Note 1 for further information regarding taxes.

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 on a monthly basis based on principal, rate and term.

Cost of Natural 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 natural 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 regulated margin is recognized related to these costs, are deferred and included in "Amounts due from customers" in "Current Regulatory Assets" or "Amounts due to customers" in "Current Regulatory Liabilities" as presented in Note 3 in "Rate-Regulated Basis of Accounting." 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 categories of income taxes in the Consolidated Statements of Operations and 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 natural 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 property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Operations and Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded within "Property and other taxes" on the Consolidated Statements of Operations and Comprehensive Income. Property and other taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

Consolidated Statements of Cash Flows

With respect to cash, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Accounting Standards Update (ASU)

We early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes in our first fiscal quarter 2016. The core principle of this revised accounting guidance is that all deferred tax assets and liabilities should be classified as noncurrent. Due to the adoption of the new accounting guidance, the balance sheet classification of deferred tax assets and liabilities were retrospectively classified as noncurrent. See Note 16 for the effect of the reclassification of deferred income taxes on the presentation on our Consolidated Balance Sheets. See Note 10 for information related to the presentation of deferred tax assets and liabilities.

We prospectively adopted ASU 2015-05 Intangibles - Goodwill and Other (Topic 350) Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement in our fourth fiscal quarter 2016. The core principle of this revised accounting guidance is determining the accounting for internal-use software for cloud computing arrangements containing a software license. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

Recently Issued Accounting Guidance

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606), including subsequent ASUs clarifying the guidance	Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from any entity's contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of first period of adoption.	Annual periods (and interim periods within those periods) beginning after December 15, 2017, with early adoption permitted for annual periods beginning after December 15, 2016.	As a Duke Energy registrant, we intend to adopt the revised accounting guidance effective for the interim and annual periods beginning January 1, 2018. We are currently evaluating the effect on our financial position and results of operations, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are monitoring specific developments for our industry.

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted.	We are currently evaluating the effect on our financial position and results of operations. We do expect an increase in assets and liabilities from the recording of our operating leases.
ASU 2016-15, August 2016, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments	The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle.	Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.	We are currently evaluating the effect on the presentation of our cash flows.

XML

Acquisition by Duke Energy Corporation

12 Months Ended

Oct. 31, 2016

Business Combinations [Abstract]

Acquisition by Duke Energy Corporation

Acquisition by Duke Energy Corporation

On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated. Under the terms of the Merger Agreement, each share of Piedmont common stock issued and outstanding immediately prior to the closing (other than shares owned by Duke Energy or its wholly owned subsidiaries) was converted automatically into the right to receive $60 in cash per share, without interest, less any applicable withholding taxes. Each share of the Merger Sub's issued and outstanding stock was converted into one share of no par value common stock for a total of 100 shares owned by Duke Energy. As a result of the merger, the legacy Piedmont common stock outstanding was canceled, and Piedmont's common stock was delisted from the NYSE.

Acquisition-related Regulatory Matters

In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. Subsequently, we, Duke Energy and the NCUC Public Staff reached an agreement of stipulation and settlement setting forth stipulations and conditions for approval of the proposed Acquisition, which was originally filed with the NCUC in June 2016. Among the stipulations contained in the agreement are:    

• Funding by the combined company of annual charitable contributions totaling at least $17.5 million in North Carolina during each of the four years after the Acquisition;

• Commitment by the combined company of $7.5 million for low-income household energy assistance and workforce development programs in North Carolina during the first year after the Acquisition;

• Exclusion of certain expenses related to the Acquisition, including severance costs, from customer bills;

• Withdrawal of our March 2016 petition requesting approval of deferred accounting treatment for certain distribution integrity management program expenses; and

• A one-time bill credit to our North Carolina customers collectively of $10.0 million.

A hearing was held on July 18 and 19, 2016. In September 2016, the NCUC approved the Acquisition pursuant to the terms of the stipulation and settlement agreement.

In October 2016, we reduced customers' bills by $4.7 million as a result of the one-time bill credit with the remainder to be reflected on November bills.

Also in January 2016, we and Duke Energy discussed the Acquisition of Piedmont by Duke Energy with the PSCSC pursuant to its procedures for an allowable ex-parte communication briefing in accordance with state statute. The PSCSC's approval of the Acquisition was not required.

In January 2016, we and Duke Energy filed a joint application with the TRA seeking approval to transfer Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statute due to the change in control. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition.

Costs to Achieve the Acquisition

The following table summarizes pre-tax acquisition consummation costs, integration and other related costs (collectively referred to as costs to achieve) that we recorded in connection with the Acquisition and are included in "Operations, maintenance and other" within "Operating Expenses" in the Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016 and 2015.

(in millions)	2016		2015
Financial and legal advisory costs	$	22.4	$	8.6
Severance costs (1)	18.7		—
Charitable contributions and community support (2)	8.8		—
Acceleration of incentive plans (3)	5.3		—
Key employee retention payments	3.5		—
Other	2.9		—
Total	$	61.6	$	8.6
(1) See Note 15 for further information on severance costs.
(2) Charitable contributions and community support reflect: 1) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years, and 2) the unconditional obligation to provide funding for low-income household energy assistance and workforce development programs in North Carolina over the next year.
(3) See Note 9 for further information on the accelerated vesting, payment and taxation of certain share-based awards.

XML

Regulatory Matters

12 Months Ended

Oct. 31, 2016

Public Utilities, Rate Matters [Abstract]

Regulatory Matters

Regulatory Matters

Rate-Regulated Basis of Accounting

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.

(in millions)	2016		2015
REGULATORY ASSETS
Current Regulatory Assets
Unamortized debt expense on reacquired debt	$	0.2	$	0.2
Amounts due from customers	61.9		8.2
Environmental costs	1.5		1.5
Deferred operations and maintenance expenses	0.9		0.8
Deferred pipeline integrity expenses	3.5		3.5
Deferred pension and other retirement benefit costs	2.8		2.8
Robeson LNG development costs	0.1		0.4
Derivatives - gas supply contracts held for utility operations	41.5		—
Other	1.3		1.7
Total current regulatory assets	113.7		19.1
Noncurrent Regulatory Assets
Unamortized debt expense on reacquired debt	4.4		4.7
Environmental costs	3.6		5.1
Deferred operations and maintenance expenses	3.1		4.0
Deferred pipeline integrity expenses	32.4		29.8
Deferred pension and other retirement benefits costs	16.8		17.9
Amounts not yet recognized as a component of pension and other retirement benefit costs	151.6		114.8
Regulatory cost of removal asset	14.1		19.1
Robeson LNG development costs	—		0.1
Derivatives - gas supply contracts held for utility operations	146.4		—
Other	0.9		1.2
Total noncurrent regulatory assets	373.3		196.7
Total Regulatory Assets	$	487.0	$	215.8

REGULATORY LIABILITIES
Current Regulatory Liabilities
Amounts due to customers	$	—	$	21.5
Noncurrent Regulatory Liabilities
Regulatory cost of removal obligations	538.0		521.5
Deferred income taxes	78.9		68.7
Amounts not yet recognized as a component of pension and other retirement benefit costs	0.1		0.1
Total noncurrent regulatory liabilities	617.0		590.3
Total Regulatory Liabilities	$	617.0	$	611.8

As of October 31, 2016, we have $14.1 million of AROs and $344.9 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 funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the TRA on a deferred cash basis.

Regulatory Oversight and Rate and Regulatory Actions

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 securities.

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 regulated margin, portion of uncollectibles is included in base rates and uncollectibles expense.

See Note 2 for further information on our regulatory filings and hearings related to the Acquisition.

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 $200.0 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 operations, 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 EasternNC to defer its operation and maintenance (O&M) expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with the deferred amounts accruing interest per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred O&M expenses of $9.0 million as of 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, 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, 2016 and 2015, we had unamortized balances, including accrued interest, of $4.0 million and $4.8 million, respectively.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and 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 was $17.3 million to be amortized over a five-year period from January 1, 2014 through December 31, 2018. As of October 31, 2016 and 2015, we had unamortized regulatory asset balances for deferred pipeline integrity expenses of $35.9 million and $33.3 million, respectively. The existing regulatory asset treatment for ongoing pipeline integrity management costs is expected to continue until another recovery mechanism is established in a future rate proceeding.

As approved in the settlement of the 2013 NCUC general rate proceeding, certain capital expenditures that are incurred to comply with federal pipeline safety and integrity requirements are separately tracked and recovered on an annual basis through an IMR, as revised by a subsequent settlement approved by the NCUC in November 2015. The settlement of the 2013 NCUC general rate proceeding 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 disallowed on the basis of prudence.

In November 2014, the NCUC approved our accounting of gas costs for 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.

In November 2015, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2015. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In November 2016, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2016. 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 up 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, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under 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 November 2014, November 2015 and November 2016 found our hedging activities during the review periods to be reasonable and prudent.

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 2013 general rate case proceeding as discussed above. The IMR provided 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. In February 2014, the NCUC approved as filed the initial IMR adjustment totaling $0.8 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 capital investments in integrity and safety projects through October 31, 2014. In January 2015, the NCUC issued an order authorizing the requested IMR rate adjustments, subject to further review and determination of the reasonableness and prudence of the capital investments and associated costs reflected in the adjustments in our annual IMR adjustment proceedings or next general rate case, with any adjustments to be implemented through a prospective rate adjustment at or after the time such adjustment is approved by the NCUC. We subsequently engaged in discussions with the NCUC Public Staff regarding the completion of their review of the IMR costs and the development of a future procedural schedule for the IMR audit and rate approval process. In September 2015, we and the NCUC Public Staff filed an agreement with the NCUC seeking approval of the following stipulations regarding the operation of the IMR:

• Semi-annual IMR rate adjustments each December 1 and June 1, starting December 1, 2015, based on eligible capital investments in integrity and safety projects closed to plant as of September 30 and March 31.

• Extension of the IMR tariff from October 31, 2017 to October 31, 2019.

• An established procedural process and time line for NCUC Public Staff’s annual review of our IMR filings.

• Fixed percentages to quantify various classes of system integrity expenditures to be recovered through the IMR with the remaining to be recovered through a future rate case:

• Transmission integrity: 85% IMR / 15% rate case.

• Distribution integrity: 90% IMR / 10% rate case.

• Right-of-way clearing for integrity projects: 15% IMR / 85% rate case.

• Work and asset management system: 68% IMR / 32% rate case.

• Tax-related adjustments.

• An immaterial reduction in IMR margin, which we recorded in the fourth fiscal quarter of 2015.

Based on the IMR agreement, in November 2015, we filed a petition with the NCUC seeking authority to adjust our rates effective December 1, 2015 to collect an additional $13.4 million in annual IMR margin revenues, based on IMR-eligible capital investments in integrity and safety projects through September 30, 2015. In November 2015, the NCUC approved the IMR settlement agreement and the requested December 2015 IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers, which we began recording in January 2016. In May 2016, we filed a petition to adjust our rates effective June 1, 2016 to collect an additional $7.4 million in annual IMR margin revenues from that approved by the NCUC in December 2015. The June 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through March 31, 2016. In May 2016, the NCUC approved the requested rate increase. In October 2016, we filed a petition to adjust our rates effective December 1, 2016 to collect an additional $8.2 million in annual IMR margin revenues from that approved by the NCUC in May 2016. The December 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through September 30, 2016, which total $513.1 million since inception of the IMR mechanism. In November 2016, the NCUC approved the requested rate increase.

In April 2014, the NCUC issued an order granting us the authority to issue up to $1.0 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. See Note 5 for further information on this shelf registration statement.

In March 2015, we filed a petition with the NCUC seeking authority for a one-time gas cost bill credit, including applicable sales taxes, for our retail sales and transportation customers in North Carolina to reduce the balance of our amounts due to customers. In March 2015, the NCUC issued an order approving our request. The bill credit of $45.5 million was reflected on customers' April 2015 bills, reducing amounts due to customers in North Carolina.

In March 2016, we filed a petition with the NCUC requesting approval of deferred accounting treatment for certain distribution integrity management program expenses. We proposed this accounting treatment as an extension of the regulatory asset accounting treatment approved by the NCUC in December 2004 for our transmission integrity management program expenses. In June 2016, we agreed to withdraw this deferral request upon the NCUC’s approval of the agreement of stipulation and settlement in the proceeding seeking approval of the Acquisition as discussed above, contingent upon the closing of the Acquisition. In October 2016, we withdrew the petition pursuant to the terms of the NCUC-approved agreement of stipulation and settlement for the Acquisition.

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 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 October 2013. In October 2014, the PSCSC issued an order approving a settlement agreement between the Office of Regulatory Staff (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 $0.1 million of our deferred South Carolina environmental costs and $0.5 million of certain non-real estate costs associated with the initial development of the Robeson County LNG facility located in North Carolina, both with amortization periods of one year beginning November 2014 and ending October 2015.

In June 2015, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2015 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2014 order. In October 2015, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in a $1.65 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2015.

In June 2016, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2016 and a cost and revenue study under the RSA requesting a change in rates from those approved by the PSCSC in the October 2015 order. In October 2016, the PSCSC issued an order approving a settlement agreement between the ORS and us that resulted in an $8.3 million annual increase in margin based on a stipulated allowed return on equity of 10.2%, effective November 1, 2016. Also in this proceeding, the PSCSC approved the use of revised depreciation rates effective November 1, 2016.

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 up 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 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 September 2015, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2015.

In August 2016, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2016.

Tennessee

In Tennessee, we operate under the Tennessee Incentive Plan (TIP) that benchmarks gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. Under the TIP, the TRA established an allocation of secondary marketing gains and losses to ratepayers and shareholders with a uniform 75/25 sharing ratio with a $1.6 million annual incentive cap for us on these gains and losses. The TIP includes procedures for asset management transactions and provides for a triennial review of TIP operations by an independent consultant. Although the TIP replaced annual prudence reviews of our gas purchasing activities, we undergo an annual compliance audit on the accuracy of our calculations and compliance with all TRA orders and directives regarding the calculation of our deferred gas cost account balances under the Actual Cost Adjustment (ACA) mechanism.

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 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. In March 2015, the Audit Staff submitted their report with which we concurred. In April 2015, the TRA approved and adopted the Audit Staff's report. The TRA's written order was issued in May 2015.

In August 2015, 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, 2015 under the TIP. In March 2016, the TRA’s audit staff submitted their report, including immaterial adjustments, with which we concurred. In April 2016, the TRA approved and adopted the audit staff’s report.

In August 2016, 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, 2016 under the TIP. We are waiting on a ruling from the TRA at this time.

In November 2015, we filed an annual report for the twelve months ended June 30, 2014 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In February 2016, the TRA approved the deferred gas cost account balances and issued its written order.

In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In June 2016, the TRA approved the deferred gas cost account balances and issued its written order.

In August 2016, we filed an annual report for the twelve months ended June 30, 2016 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 a petition with the TRA seeking authority to implement an IMR to recover 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 $13.1 million in annual margin revenue from tariff customers based on capital expenditures of $100.4 million incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. In November 2013, we and the Tennessee Attorney General's Consumer Advocate and Protection Division (CAD) filed an IMR settlement with the TRA. A hearing on this matter was held in December 2013, and the TRA approved the IMR settlement as filed for $13.1 million with the IMR rate adjustments beginning January 2014. A written order was issued in May 2014.

In December 2014, we filed a petition with the TRA seeking authority to collect an additional $6.5 million in annual IMR margin revenues effective January 2015 based on $54.0 million of capital investments in integrity and safety projects over the twelve-month period ended October 31, 2014. In January 2015, the TRA accepted and approved the requested IMR rate adjustment and issued its written order in February 2015.

In November 2015, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2016 based on $18.4 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2015. In December 2015, the TRA approved the IMR rate increase to be effective January 2016 and issued its written order in February 2016.

In November 2016, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2017 based on $20.1 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2016. We are waiting on a ruling from the TRA at this time.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. In November 2015, we filed a settlement agreement with the CAD stipulating that Piedmont refund the $4.7 million to customers over a twelve month period. In December 2015, the TRA approved the settlement agreement, and we began refunding the $4.7 million to customers through a rate decrement over the twelve month period beginning January 2016. The TRA’s written order was issued in February 2016.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas (CNG) infrastructure rider to recover the costs of our capital investments 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, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general 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. A hearing on this matter was held in January 2015. In February 2015, the TRA (1) denied approval of the proposed tariff rider, (2) ruled that our retail CNG motor fuel service should be unregulated and no longer provided under our regulated tariff, and (3) approved the proposed modification to our tariff providing natural gas for motor fuel purposes at customer premises. The TRA indicated that we may seek recovery of our prior investments in CNG equipment of $4.7 million since our last rate proceeding in utility rate base in our next general rate case proceeding as the investments were made in good faith under the assumption retail CNG motor fuel would be a regulated service. The TRA's written order was issued in October 2015.

In July 2016, the TRA Staff filed its compliance audit report for operation of our WNA rider during the 2015 – 2016 heating season, concluding that we had correctly implemented the WNA rider in all material aspects. The TRA Staff identified an immaterial error that resulted in an under-collection of our WNA revenues and recommended a correcting adjustment through the ACA mechanism which we recorded in August 2016. In August 2016, the TRA approved and adopted the TRA Staff’s compliance audit report. The TRA’s written order was issued in September 2016.

All States

Due to the seasonal nature of our business and as approved by our state regulatory commissions, we contract with customers in the secondary market to sell supply and capacity assets when market conditions permit. These sales normally 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 are favorable and when the supply and capacity are not required to serve our retail distribution system. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Effective October 3, 2016, secondary market margins generated through off-system sales and capacity release activity to Duke Energy are 100% credited to customers. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2016, 2015, and 2014 is presented below.

(in millions)	2016		2015		2014
Allocated to customers as gas cost reductions	$	52.0	$	60.1	$	72.2
Margin allocated to us	17.7		21.1		25.4
Margin from secondary market activity	$	69.7	$	81.2	$	97.6

We currently have commission approval in all three states that place tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system in order to mitigate the risk exposure to the financial condition of the marketers.

XML

Common Stock

12 Months Ended

Oct. 31, 2016

Stockholders' Equity Note [Abstract]

Common Stock

Common Stock

With the consummation of the Acquisition on October 3, 2016, each share of Piedmont's outstanding common stock (other than shares owned by Duke Energy and its wholly owned subsidiaries) was converted into the right to receive $60 in cash per share, and all of Piedmont's outstanding common stock was canceled and delisted from the NYSE. Our Restated Articles of Incorporation were amended on the consummation date to change the number of authorized shares to 100 shares of common stock, no par value. The issued and outstanding shares of the Merger Sub became the issued and outstanding shares of Piedmont, a wholly owned subsidiary of Duke Energy.

Common Stock

Changes in common stock for the years ended October 31, 2016, 2015 and 2014 are as follows.

(in millions)	Shares		Amount
Balance, October 31, 2013	76.1		$	561.6
Issued to participants in the Employee Stock Purchase Plan (ESPP)	—		1.1
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP)	0.7		23.5
Issued to incentive compensation plan (ICP)	0.1		3.3
Issuance of common stock through forward sale agreements (FSAs), net of expenses	1.6		47.3
Balance, October 31, 2014	78.5		636.8
Issued to ESPP	—		1.2
Issued to DRIP	0.7		24.7
Issued to ICP	0.2		5.0
Issuance of common stock through FSAs, net of expenses	1.5		53.7
Balance, October 31, 2015	80.9		721.4
Issued to ESPP *	—		1.0
Issued to DRIP *	0.3		14.5
Issued to ICP	0.3		18.3
Issuance of common stock through FSAs, net of expenses	1.8		104.6
Outstanding shares of common stock converted into the right to receive cash	(83.3	)
Balance, October 31, 2016	—		$	859.8
*In anticipation of the Acquisition, we suspended new investments in our DRIP and ESPP, effective July 31, 2016.

Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we could issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of $170.0 million (subject to certain exceptions) during the period beginning January 7, 2015 and ending October 31, 2016.

In addition to the issuance and sale of shares by us through the Agents, we could also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers would, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge. Under the Sales Agreements, we specified the maximum number of our shares to be sold and the minimum price per share. We paid each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of 1.5% of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements could be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs.

The table below presents equity transactions that were settled in shares under the open registration statements over the two-year period ended October 31, 2016.

(in millions, except per share amounts)
Equity Issuance Transaction	Number of Shares	Settled	Net Proceeds Before Issuance Costs (1)		Net Settlement Price Per Share (2)
FSA - executed March 2015	0.6	October 2015	$	21.8	$35.50
FSA - executed June 2015	0.8	October 2015	28.2		$35.49
FSA - executed September 2015	0.1	October 2015	4.1		$36.03
Total 2015 ATM program	1.5		$	54.1
FSA - executed January 2016	0.4	September 2016	$	20.2	$56.25
FSA - executed March 2016	0.6	September 2016	36.2		$58.35
FSA - executed June 2016	0.8	September 2016	48.3		$58.87
Total 2016 ATM program	1.8		$	104.7
(1) Issuance costs incurred as follows: October 2015 shares $0.4 million and September 2016 shares $0.1 million.
(2) Net of 1.5% commission plus other adjustments.

In accordance with accounting guidance, we classified the FSAs as equity transactions because the forward sale transactions were indexed to our own stock and the physical settlement was within our control. As a result of this classification, no amounts were recorded in the Consolidated Financial Statements until the final settlement of the FSAs, which were all physically settled. We recorded the FSA amounts in "Equity" as an addition to "Common stock" on the Consolidated Balance Sheets. Upon settlement, we used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our commercial paper (CP) program and for general corporate purposes.

As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances.

Other Comprehensive Income (Loss)

Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and retirement benefits from our investments in unconsolidated affiliates. See Note 11 for further information on our investments in unconsolidated affiliates. Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2016 and 2015.

Changes in Accumulated OCIL (1)
(in millions)	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(0.8	)	$	(0.2	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(2.8		)	(1.6		)
Amounts reclassified from accumulated OCIL, net of tax	3.4			1.0
Total current period activity of hedging activities of equity method investments, net of tax	0.6			(0.6		)
Accumulated OCIL ending balance, net of tax	$	(0.2	)	$	(0.8	)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2016 and 2015.

Reclassification Out of Accumulated OCIL (1)
	Years Ended					Affected Line Items on Statement of Operations and Comprehensive Income
	October 31,
(in millions)	2016		2015
Hedging activities of equity method investments	$	1.4	$	1.7		Equity in earnings of unconsolidated affiliates
Income tax expense	2.0		(0.7		)	Income tax expense
Total reclassification for the period, net of tax	$	3.4	$	1.0
(1) Amounts in parentheses indicate debits to accumulated OCIL.

XML

Debt and Credit Facilities

12 Months Ended

Oct. 31, 2016

Debt Disclosure [Abstract]

Debt and Credit Facilities

Debt and Credit Facilities

Summary of Long-Term Debt

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. None of our debt is actively traded. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.

	Long-Term Debt as of October 31, 2016
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
8.51%, due September 30, 2017	$	35.0	$	—		$	35.0
4.24%, due June 6, 2021	160.0		(0.6		)	159.4
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.2		)	198.8
4.10%, due September 18, 2034	250.0		(2.5		)	247.5
4.65%, due August 1, 2043	300.0		(2.9		)	297.1
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
3.64%, due November 1, 2046	300.0		(3.4		)	296.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.2		)	59.8
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,835.0		(14.0		)	1,821.0
Less current maturities	35.0		—			35.0
Total	$	1,800.0	$	(14.0	)	$	1,786.0

	Long-Term Debt as of October 31, 2015
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
2.92%, due June 6, 2016	$	40.0	$	(0.1	)	$	39.9
8.51%, due September 30, 2017	35.0		—			35.0
4.24%, due June 6, 2021	160.0		(0.8		)	159.2
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.3		)	198.7
4.10%, due September 18, 2034	250.0		(2.6		)	247.4
4.65%, due August 1, 2043	300.0		(3.0		)	297.0
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.3		)	59.7
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,575.0		(11.3		)	1,563.7
Less current maturities	40.0		—			40.0
Total	$	1,535.0	$	(11.3	)	$	1,523.7

Current maturities for the next five years ending October 31 and thereafter are as follows.

(in millions)
2017	$	35.0
2018	—
2019	—
2020	—
2021	160.0
Thereafter	1,640.0
Total	$	1,835.0

In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration statement up to $1.0 billion during its three-year life. As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances.

On September 14, 2015, we issued $150.0 million of ten-year, unsecured senior notes with an interest rate of 3.60% and at a discount of .065% or $0.1 million 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 June 1, 2025, 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 to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 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 June 1, 2025, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $148.9 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

On June 6, 2016, we repaid $40.0 million of our 2.92% senior notes at maturity.

On July 28, 2016, we issued $300.0 million of unsecured senior notes maturing November 1, 2046 with an interest rate of 3.64% and at a discount of .122% or $0.4 million under the registration statement in effect noted above. We have the option to redeem all or part of the notes before May 1, 2046, at a redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and 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 25 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 on or after May 1, 2046, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We used the net proceeds of $297.0 million from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

The amount of cash dividends that may be paid on 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, 2016, our net earnings available for restricted payments were $1.3 billion.

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, 2016, we are in compliance with all default provisions.

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 $1.0 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 4.65 times as of October 31, 2016;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 55% of total capitalization as of October 31, 2016;

• 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, 2016;

• Restrictions on permitted liens;

• Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and

• Restrictions on burdensome agreements.

The Acquisition constituted a change in control under the note agreements under which our 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition did not constitute an event of default, upon the closing of the Acquisition, we were required to offer to prepay 100% of the principal amounts plus accrued interest to these noteholders. None of the noteholders exercised the prepayment option.

Available Credit Facilities

At October 31, 2016, we have an $850.0 million five-year revolving syndicated credit facility that expires on December 14, 2020 that has an option to request an expansion up to an additional $200.0 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10.0 million, of which $1.7 million and $1.6 million were issued and outstanding as of October 31, 2016 and 2015, respectively. These letters of credit are used 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 112.5 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020 provided that we are in compliance with all terms of the agreement. The facility expressly permitted the Acquisition by Duke Energy.

We have an $850.0 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 $850.0 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based 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, 2016, we had $145.0 million of notes outstanding under the CP program, as included in "Notes payable and commercial paper" within "Current Liabilities" on the Consolidated Balance Sheets, with original maturities ranging from 1 to 6 days from their dates of issuance at a weighted average interest rate of .64%. As of October 31, 2015, our outstanding notes under the CP program, included on the Consolidated Balance Sheets as stated above, were $340.0 million at a weighted average interest rate of .22%.

Other than outstanding CP balances, we did not have any borrowings under the revolving syndicated credit facility for the twelve months ended October 31, 2016. A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2016 is as follows.

(in millions)
Minimum amount outstanding	$	110.0
Maximum amount outstanding	$	530.0
Minimum interest rate	.20		%
Maximum interest rate	.75		%
Weighted average interest rate	.55		%

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 55% at October 31, 2016.

XML

Financial Instruments & Related Fair Value

12 Months Ended

Oct. 31, 2016

Financial Instruments & Related Fair Value [Abstract]

Financial Instruments and Related Fair Value

Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans with the purchase of financial gas call option derivative instruments (gas purchase options). The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase options. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2016 and 2015, we had long gas purchase options providing total coverage of 15.4 million dekatherms and 34.7 million dekatherms, respectively. The long gas purchase options held as of October 31, 2016 are for the period from December 2016 through May 2017.

Derivative Assets and Liabilities - Gas Supply Contracts

We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Beginning with the year ended October 31, 2016, we have certain long-dated, fixed quantity forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "Other" in "Current Liabilities" and "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

Fair Value Measurements and Quantitative and Qualitative Disclosures

We use gas purchase options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these long-dated, fixed quantity gas supply contracts that became effective beginning with the year ended October 31, 2016 should be recorded at fair value.

The costs of our gas cost hedging plans 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, we present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of our gas purchase options held for our utility operations. There are no gas purchaseoptions 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 gas purchase options held for utility operations. Our gas purchase options held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivative contracts presented at fair value that are held for our utility operations.

We also have trading securities that are held in rabbi trusts established for certain deferred compensation plans and are included in "Other" within "Investments and Other Assets" on the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in "Fair Value Measurements" in Note 1.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2016 and 2015. 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 to the fair value measurement requires judgment 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, 2016 and 2015.

Recurring Fair Value Measurements as of October 31, 2016
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.5	$	—	$	—	$	—	$	1.5
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	3.7		—		—		—		3.7
Total fair value assets	$	5.7	$	—	$	—	$	—	$	5.7
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	187.9	$	—	$	187.9

Recurring Fair Value Measurements as of October 31, 2015
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.3	$	—	$	—	$	—	$	1.3
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	4.4		—		—		—		4.4
Total fair value assets	$	6.2	$	—	$	—	$	—	$	6.2

In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our gas supply derivative contracts in the mid to later years of contract terms ranged from $2.60 to $4.47 per dekatherm.

The fair value of our gas supply derivative contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain.

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.

(in millions)	2016
Gas supply derivative liabilities, beginning balance	$	—
Realized and unrealized losses:
Recorded to regulatory assets *	187.9
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Gas supply derivative liabilities, ending balance	$	187.9
* Included are the actual costs recorded within "Cost of natural gas" on the Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing.

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 are to use these financial instruments to reduce gas cost volatility for our customers.

Our regulated utility operations gas purchase options are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These gas purchase options are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these gas purchase options 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 operation of the hedging programs of the regulated utility operations as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as "Current Regulatory Assets" or amounts due to customers included as "Current Regulatory Liabilities" in Note 3 and recognized on the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" when the related costs are recovered through our rates. These gas purchase options are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "Derivatives - gas supply contracts held for utility operations" in Note 3.

The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of October 31, 2016 and 2015.

Fair Value of Derivative Instruments
(in millions)	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Financial Asset Instruments:
Current Assets - Gas purchase derivative assets	$	1.5	$	1.3
Nonfinancial Liabilities Instruments:
Current Liabilities - Gas supply derivative liabilities	41.5
Noncurrent Liabilities - Gas supply derivative liabilities	146.4

The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016 and 2015, 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 millions)	2016			2015			2016			2015
Gas purchase options	$	(5.2	)	$	(4.4	)	$	(5.2	)	$	(4.4	)	Cost of natural 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 as 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 as 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.

We would have recorded an unrealized loss of $187.9 million related to our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivative contracts in the Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of natural gas" in the month purchased.

Our long-term debt is presented at net 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. The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.

(in millions)	Principal		Fair Value
As of October 31, 2016	$	1,835.0	$	2,061.2
As of October 31, 2015	1,575.0		1,720.6

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 have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations 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 "Receivables" within "Current Assets" on the Consolidated Balance Sheets attributable to these entities amounted to $14.2 million, or approximately 31% of our gross receivables as of October 31, 2016. 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, 2016, 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 receivables 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 receivables; however, we believe that our provision for possible losses on uncollectible receivables are 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 established comprehensive risk management policies under the direction of Duke Energy’s Chief Executive Officer (CEO) and Chief Financial Officer. The Finance and Risk Management Committee of Duke Energy's Board of Directors receives periodic updates from Duke Energy's Chief Risk Officer and other members of management on market risk positions, corporate exposures, and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits.

XML

Commitments & Contingencies

12 Months Ended

Oct. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

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, 2016, 2015 and 2014 are as follows.

(in millions)	2016		2015		2014
Operating lease payments (1)	$	4.8	$	5.0	$	4.7
(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 millions)
2017	$	4.7
2018	4.6
2019	4.4
2020	4.5
2021	4.6
Thereafter	19.8
Total	$	42.6

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 fully recoverable subject to 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 nineteen years. The time periods for fixed payments of reservation fees under gas supply contracts are up to two years. The time period for the gas supply purchase commitments is up to fifteen 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, 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 on the Consolidated Statements of Operations and Comprehensive Income as part of gas purchases and included within "Cost of natural gas."

As of October 31, 2016, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Gas Supply		Telecommunications
	and Storage		Reservation		Purchase		and Information
(in millions)	Capacity		Fees		Commitments		Technology		Other		Total
2017	$	170.0	$	2.2	$	124.4	$	9.6	$	62.1	$	368.3
2018	143.8		—		96.8		5.4		—		246.0
2019	133.4		—		96.8		5.2		—		235.4
2020	115.4		—		97.1		4.5		—		217.0
2021	113.7		—		96.8		1.1		—		211.6
Thereafter	405.5		—		896.1		—		—		1,301.6
Total	$	1,081.8	$	2.2	$	1,408.0	$	25.8	$	62.1	$	2,579.9

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters 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 $1.7 million in letters of credit that were issued and outstanding as of October 31, 2016. See Note 5 for additional information concerning letters of credit.

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, 2016, we had open surety bonds with a total contingent obligation of $6.4 million.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).

We share environmental responsibility for various MGP sites with Duke Energy, and one of its subsidiaries. In 1997, we entered into a settlement with Duke Energy 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 our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition and prior to its closing, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress), a subsidiary of Duke Energy since July 2012. Progress has complete responsibility for performing all of the former 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 were 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.

As of October 31, 2016, our estimated undiscounted environmental liability totaled $1.0 million, and consisted of $0.8 million for MGP sites for which we retain responsibility and $0.2 million for USTs, our Huntersville LNG facility and other environmental costs. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others. For the period ending October 31, 2016, we incurred $0.1 million of remediation costs related to our MGP sites and Huntersville LNG facility.

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, 2016, our regulatory assets for unamortized environmental costs in our three-state territory totaled $5.1 million. We received approval from the TRA to recover $2.0 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.

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.

XML

Employee Benefit Plans

12 Months Ended

Oct. 31, 2016

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Employee Benefit Plans

Employee Benefit Plans

We recognize all obligations related to our 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. We measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. Our plans’ assets are recorded at fair value. In accordance with accounting guidance, 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.

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 is 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 an applicable year. 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.

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 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, where applicable.

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 the following types of investments:

• Fixed income securities: includes U.S. treasuries, corporate bonds, high yield debt (bank loans), 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.

• Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as international equity.

• Real estate: includes a diversified global real estate investment trust fund.

• Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies.

The target and actual allocations of the qualified pension plan's assets are as follows.

	Target		Assets as of October 31,
Asset Allocations	Allocation		2016		2015
Fixed income securities	45	%	46	%	46	%
Equity securities	35	%	33	%	34	%
Real estate	5	%	5	%	5	%
Cash and cash equivalents	—	%	2	%	1	%
Other investments	15	%	14	%	14	%
Total	100	%	100	%	100	%

Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee 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, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2016, 2015 and 2014, we contributed $1.8 million, $1.4 million and $0.9 million, respectively, to the MPP plan.

OPEB Plan

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees hired prior to January 1, 2008 are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees hired after January 1, 2008 have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs. Employees who meet the eligibility requirements to retire also receive a life insurance benefit of $15,000.

Prior to January 1, 2016, employees who met the eligibility requirement noted above or were part of a "grandfathered" group received either full or partial retiree coverage paid by us, subject to certain participation limits. Retirees were responsible for the full cost of dependent coverage.

Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). Under the new HRA, participating eligible retirees and their dependents may qualify for a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical and dental expenses.

OPEB plan assets are comprised of mutual funds within a 401(h) account and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the investment philosophy of the qualified pension plan as discussed above, except the OPEB fixed income portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

The target and actual allocations of the OPEB plan's assets are as follows.

	Target			Assets as of October 31,
Asset Allocations	Allocation			2016		2015
Fixed income securities	45	%	(1)	47	%	47	%
Equity securities	47	%		44	%	44	%
Real estate	5	%		5	%	5	%
Cash and cash equivalents	3	%		4	%	4	%
Total	100	%		100	%	100	%
(1) Includes 5% target allocation to high yield fixed income.

Supplemental Executive Retirement Plans

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are no assets related to these SERPs, 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.

We have a non-qualified defined contribution restoration plan (DCR plan) for certain officers at 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% 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. In accordance with the Merger Agreement, the account balances were subject to accelerated vesting effective with the consummation of the Acquisition with distribution occurring upon the participant's separation of service from the Company.

Prior to the Acquisition, we had a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we made no contributions to this plan. Participants could defer a percentage of their base salary and annual incentive pay in accordance with the plan. Benefits under this plan, known as the Voluntary Deferral Plan, were informally funded monthly through a rabbi trust with a bank as the trustee. In accordance with the Merger Agreement, the account balances were subject to accelerated distribution effective with the consummation of the Acquisition.

Our funding to the DCR plan account for the years ended October 31, 2016 and 2015, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2016 and 2015, are presented below.

(in millions)	2016		2015
Funding	$	0.5	$	0.5
Liability	4.7		5.3

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 was $0.1 million for the years ended October 31, 2016, 2015 and 2014.

Actuarial Plan Information

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2016 and 2015, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2016 and 2015, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension						Other Benefits
(in millions)	2016			2015			2016			2015			2016			2015
Accumulated benefit obligation at year end	$	296.3		$	263.1		$	4.6		$	5.5		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	311.5		$	302.7		$	5.5		$	5.9		$	37.6		$	37.8
Service cost	10.6			11.4			—			—			1.2			1.2
Interest cost	9.5			12.0			0.2			0.2			1.3			1.5
Plan amendments	—			—			—			—			—			(1.9		)
Plan settlements	—			—			(0.9		)	—			—			—
Actuarial loss (gain)	34.1			3.5			0.3			(0.1		)	1.6			1.7
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Obligation at end of year	351.7			311.5			4.6			5.5			39.3			37.6
Change in fair value of plan assets:
Fair value at beginning of year	329.3			336.4			—			—			27.5			27.7
Actual return on plan assets	17.6			1.0			—			—			1.1			0.3
Employer contributions	10.0			10.0			1.4			0.5			2.6			2.2
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Plan settlements	—			—			(0.9		)	—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Fair value at end of year	342.9			329.3			—			—			28.8			27.5
Funded status at year end - (under) over	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Noncurrent assets	$	—		$	17.8		$	—		$	—		$	—		$	—
Current liabilities	—			—			(0.5		)	(0.5		)	—			—
Noncurrent liabilities	(8.8		)	—			(4.1		)	(5.0		)	(10.5		)	(10.1		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized prior service credit (cost)	$	10.7		$	12.8		$	—		$	(0.2	)	$	1.5		$	1.9
Unrecognized actuarial loss	(153.1		)	(120.5		)	(1.5		)	(1.6		)	(9.1		)	(7.2		)
Regulatory asset	(142.4		)	(107.7		)	(1.5		)	(1.8		)	(7.6		)	(5.3		)
Cumulative employer contributions in
excess of cost	133.6			125.5			(3.1		)	(3.7		)	(2.9		)	(4.8		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Weighted average assumptions used in the measurement of
the benefit obligations:
Discount rate	3.80		%	4.34		%	3.80		%	3.85		%	3.80		%	4.38		%
Rate of compensation increase	4.05		%	4.07		%	N/A			N/A			N/A			N/A

Net periodic benefit cost components for the years ended October 31, 2016, 2015 and 2014 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2016, 2015 and 2014 are presented below.

	Qualified Pension									Nonqualified Pension									Other Benefits
(in millions)	2016			2015			2014			2016			2015			2014			2016			2015			2014
Service cost	$	10.6		$	11.4		$	10.9		$	—		$	—		$	—		$	1.2		$	1.2		$	1.1
Interest cost	9.5			12.0			11.7			0.2			0.2			0.2			1.3			1.5			1.5
Expected return on plan assets	(24.0		)	(23.6		)	(22.5		)	—			—			—			(1.8		)	(1.8		)	(1.8		)
Amortization of prior service (credit)
cost	(2.2		)	(2.2		)	(2.2		)	0.2			0.2			0.2			(0.3		)	—			—
Amortization of net loss	8.0			8.7			7.7			—			0.1			0.1			0.4			—			—
Settlement loss recognized	—			—			—			0.3			—			—			—			—			—
Net periodic benefit cost	1.9			6.3			5.6			0.7			0.5			0.5			0.8			0.9			0.8
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost (credit)	—			—			—			—			—			0.5			—			(1.9		)	—
Net loss (gain)	40.5			26.2			14.4			0.3			(0.1		)	1.0			2.4			3.2			3.6
Amounts recognized as a component of
net periodic benefit cost:
Amortization of net loss	(8.0		)	(8.7		)	(7.7		)	—			(0.1		)	(0.1		)	(0.4		)	—			—
Settlement loss recognized	—			—			—			(0.3		)	—			—			—			—			—
Prior service credit (cost)	2.2			2.2			2.2			(0.2		)	(0.2		)	(0.2		)	0.3			—			—
Total recognized in regulatory asset
(liability)	34.7			19.7			8.9			(0.2		)	(0.4		)	1.2			2.3			1.3			3.6
Total recognized in net periodic benefit
and regulatory asset	$	36.6		$	26.0		$	14.5		$	0.5		$	0.1		$	1.7		$	3.1		$	2.2		$	4.4
Weighted average assumptions used to determine the net periodic benefit cost:
Discount rate	4.34		%	4.13		%	4.55		%	3.85		%	3.69		%	3.98		%	4.38		%	4.03		%	4.44		%
Expected long-term rate of return on plan assets	7.25		%	7.50		%	7.75		%	N/A			N/A			N/A			7.25		%	7.50		%	7.75		%
Rate of compensation increase	4.07		%	3.68		%	3.72		%	N/A			N/A			N/A			N/A			N/A			N/A

The 2017 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 millions)	Pension			Pension		Benefits
Amortization of unrecognized prior service credit	$	(2.2	)	$	—	$	(0.3	)
Amortization of unrecognized actuarial loss	11.3			0.1		0.7

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.

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. Our assumed mortality rates incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. We also applied the updated projection scale issued by the Society of Actuaries in October 2016.

We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31, 2017.

(in millions)
Qualified pension plan	$	10.0
Nonqualified pension plans	0.5
MPP plan	2.1
OPEB plan	2.2

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. We are in compliance with the 100% funding target established in the PPA.

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 millions)	Pension		Pension		Benefits
2017	$	39.6	$	0.5	$	1.9
2018	25.2		0.5		2.1
2019	25.0		0.5		2.2
2020	24.8		0.4		2.4
2021	24.9		0.4		2.4
2022 – 2026	126.8		1.7		13.1

Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2016 and 2015.

In fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our plans. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. This change improved the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provided a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Effective with the consummation of the Acquisition, we changed the methodology we use to calculate the discount rate for the current year benefit obligation and next year's periodic net benefit cost for our plans. We replaced our full yield curve methodology with a bond selection-settlement portfolio approach used by Duke Energy. 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, which was 3.80% as of October 31, 2016, 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. This change decreased our total benefit obligations on our plans as of October 31, 2016 by $2.4 million.

Fair Value Measurements

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 are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.

Fixed income securities – These assets include:

• 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.

• 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.

• Derivatives – The Level 1 assets are valued using a compilation of observable market information on an active market. The Level 2 assets are valued using broker quotes on a non-active market.

Equity securities – These are level 1 assets valued at the market price of the active market on which the individual security is traded.

Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2.

Common trust fund – These are Level 2 assets held in a common trust fund 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 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; $2.6 million of the original $12.0 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 Standard & Poor's 500 Stock Index. Our investment is in various funds that invest in North American companies, allocate capital to private equity funds, invest in venture capital partnerships and private equity partnerships in emerging markets.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Hedge fund of funds – 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.

Commodities fund of funds – These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers. Currently, there are no restrictions on redemptions for the fund.

High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund.

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, 2016.	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 business 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 8 to 10 years.

The qualified pension plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment 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.

	Qualified Pension Plan as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	5.1	$	0.8	$	—	$	5.9
Fixed income securities	—		78.9		—		78.9
Equity securities	44.4		—		—		44.4
Mutual funds	78.2		55.0		—		133.2
Common trust fund	—		25.0		—		25.0
Private equity fund of funds	—		—		8.9		8.9
Other Investments:
Hedge fund of funds							20.0		(1)
Commodities fund of funds							9.2		(1)
High yield debt (bank loans)							17.4		(1)
Total assets at fair value	$	127.7	$	159.7	$	8.9	$	342.9

	Qualified Pension Plan as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	2.8	$	0.1	$	—	$	2.9
Fixed income securities	—		84.1		—		84.1
Equity securities	44.7		—		—		44.7
Mutual funds	78.9		42.9		—		121.8
Common trust fund	—		23.6		—		23.6
Private equity fund of funds	—		—		8.3		8.3
Other Investments:
Hedge fund of funds							19.8		(1)
Commodities fund of funds							7.7		(1)
High yield debt (bank loans)							16.4		(1)
Total assets at fair value	$	126.4	$	150.7	$	8.3	$	329.3
(1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
(in millions)	of Funds
Balance, October 31, 2014	$	7.2
Actual return on plan assets:
Relating to assets still held at the reporting date	0.4
Relating to assets sold during the period	0.6
Purchases, sales and settlements (net)	0.1
Transfer in/out of Level 3	—
Balance, October 31, 2015	8.3
Actual return on plan assets:
Relating to assets still held at the reporting date	0.1
Relating to assets sold during the period	0.5
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, October 31, 2016	$	8.9

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.

Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.

Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date.

The OPEB plan’s asset allocations by level within the fair value hierarchy as of October 31, 2016 and 2015 are presented below. Our assessment of 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 1.

	Other Benefits as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.2	$	—	$	—	$	1.2
Mutual funds	27.6		—		—		27.6
Total assets at fair value	$	28.8	$	—	$	—	$	28.8

	Other Benefits as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.1	$	—	$	—	$	1.1
Mutual funds	26.4		—		—		26.4
Total assets at fair value	$	27.5	$	—	$	—	$	27.5

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. Prior to the Acquisition, participants could 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, 2016, 2015 and 2014, we made matching contributions to participant accounts as follows.

(in millions)	2016		2015		2014
401(k) matching contributions	$	6.9	$	6.6	$	6.1

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. Prior to the Acquisition, former ESOP participants could remain invested in Piedmont common stock in their 401(k) plan or could 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 Statements of Changes in Equity as an increase in retained earnings.

XML

Employee Share Based Plans

12 Months Ended

Oct. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employee Share-Based Plans

Employee Share-Based Plans

Prior to the Acquisition, under our shareholder approved ICP, eligible officers and other participants were awarded units that paid out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards were made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans required that a minimum threshold performance level be achieved in order for any award to be distributed.

During 2016, we had three series of awards that were outstanding under the approved ICP, with a three-year performance period that ended October 31, 2016 (2016 plan), October 31, 2017 (2017 plan) and October 31, 2018 (2018 plan). For the years ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. We re-measured the liability to market value each quarter and at the settlement date of the award.

The Merger Agreement provided for the conversion of the 2016 and 2017 plans shares subject to the ICP awards at the performance level specified in the Merger Agreement into the right to receive $60 cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at their election to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration and payout of the ICP awards, at a 96% election rate by the participants, was done for tax planning purposes and occurred on December 15, 2015. In connection with the election to accelerate the ICP awards, each respective participant executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated ICP awards. With the consummation of the Acquisition, all restrictions were lifted.

The accelerated ICP awards were priced at the NYSE composite closing price of $56.85 on December 14, 2015. Under the accelerated ICP awards, 162,390 restricted nonvested shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes.

Upon consummation of the Acquisition, the participants that did not accelerate their ICP awards, as discussed above, received $60 per share under the 2016 and 2017 plans, or $0.3 million in cash, net of applicable income taxes withheld.

The 2018 plan was approved subsequent to the execution of the Merger Agreement with Duke Energy. Under the Merger Agreement, the 2018 plan performance awards were fully converted into Duke Energy restricted stock unit awards (Duke Energy RSU Award) upon consummation of the Acquisition. Vesting under the Duke Energy RSU Award will be subject to the participant remaining continuously employed by Duke Energy or its affiliates through October 31, 2018. The Duke Energy RSU Award will be subject to 100% accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement. The Duke Energy RSU Award is recorded as an equity award on Duke Energy's balance sheet. As of October 31, 2016, our liability related to this plan is $6.1 million as reflected in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets.

Also under our approved ICP, 64,700 nonvested restricted stock units (RSUs) were granted to our President and CEO prior to the consummation of the merger (former CEO) in December 2011. During the vesting period, any dividend equivalents were accrued on these stock units and 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 vested RSUs were payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, only if he remained an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units were scheduled to vest on December 15, 2016 (2016 RSU). The Merger Agreement provided for the conversion of the 2016 RSU into the right to receive $60 cash per share upon closing of the transaction contemplated in the Merger Agreement. Similar to the accelerated ICP awards discussed above, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU (accelerated RSU) in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. Our former CEO executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated RSU. The acceleration and payout of the accelerated RSU occurred on December 15, 2015. With the consummation of the Acquisition, all restrictions were lifted. For the twelve months ended October 31, 2016, 2015 and 2014, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for nonvested RSUs as applicable, based on the fair market value of our common stock at the end of each quarter. The liability was re-measured to market value each quarter and at the settlement date of the award.

The following table summarizes the settlement of the RSUs.

	December 15, 2014 vesting (20% of the grant)			December 15, 2015 vesting (30% of the grant)			Accelerated RSU settled on December 15, 2015 (50% of the grant)
Shares of common stock issued, including accrued dividends, net of shares withheld for taxes	7,231			11,732			19,554
NYSE composite closing price	$	37.89	(1)	$	56.85	(2)	$	56.85	(2)
(1) Closing price on December 12, 2014.
(2) Closing price on December 14, 2015.

At the time of distribution of any award under the ICP, the number of shares of common stock issuable was reduced by the withholdings for payment of applicable income taxes for each participant. The participant could elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. We present the net shares issued in the Consolidated Statements of Changes in Equity and in Note 4.

The compensation expense related to the awards under the ICP for the years ended October 31, 2016, 2015 and 2014, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016			2015		2014
Compensation expense	$	16.1	(1)	$	14.2	$	8.5
Tax benefit	6.1			4.0		2.5
Liability	—			22.0
(1) Includes $5.3 million incremental expense related to the accelerated ICP and RSU awards, and the conversion of the 2018 plan to a Duke Energy RSU Award. See Note 2 for further information.

Equity Plan

Prior to the Acquisition, on a quarterly basis, we issued shares of common stock under the ESPP and accounted for the issuance as an equity transaction. The exercise price was calculated as 95% of the fair market value on the purchase date of each quarter where the fair value was determined by calculating the average of the high and low trading prices on the purchase date.

In anticipation of the Acquisition, we suspended new investments in our ESPP and resulting issuances of common stock under this plan, effective July 31, 2016. The ESPP was terminated at the closing date of the Acquisition on October 3, 2016.

XML

Income Taxes

12 Months Ended

Oct. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The components of income tax expense for the years ended October 31, 2016, 2015 and 2014 are presented below.

	2016					2015					2014
(in millions)	Federal			State		Federal			State		Federal			State
Charged (Credited) to income:
Current	$	27.2		$	11.8	$	(0.7	)	$	1.1	$	2.5		$	1.8
Deferred (1) (2)	79.6			5.8		77.9			12.1		76.5			14.2
Tax Credits:
Amortization	(0.2		)	—		(0.2		)	—		(0.2		)	—
Total	$	106.6		$	17.6	$	77.0		$	13.2	$	78.8		$	16.0
(1) Includes benefits from net operating loss (NOL) and tax carryforwards of $91.4 million and $64.3 million for the years ended October 31, 2016 and 2015, respectively.
(2) Includes the anticipated utilization of NOL and tax carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.

The Protecting Americans from Tax Hikes Act of 2015 enacted in December 2015 and the Tax Increase Prevention Act of 2014, enacted in December 2014, retroactively extended the 50% bonus depreciation which had expired the December of the year preceding the enactments. As a result of the retroactive extensions of bonus depreciation, we were able to claim additional depreciation deductions on our tax returns for the years ended October 31, 2015 and 2014. Prior to the retroactive extensions, we had anticipated utilizing NOL and tax carryforwards to offset taxable income generated in our fiscal years 2015 and 2014 as discussed in note ⁽²⁾ in the table above. The benefits from NOL and tax carryforwards in note ⁽¹⁾ in the table above include $46.8 million and $61.1 million to record the retroactive impact of the passage of bonus depreciation for the years ended October 31, 2016 and 2015, respectively.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Federal taxes at 35%	$	111.1		$	79.5		$	83.5
State income taxes, net of federal benefit	11.4			8.6			10.4
Amortization of investment tax credits	(0.2		)	(0.2		)	(0.2		)
Other, net	1.9			2.3			1.1
Total	$	124.2		$	90.2		$	94.8
Effective Tax Rate	39.1		%	39.7		%	39.7		%

We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. Effective with the Acquisition, our tax year end will change to December 31, 2016, and we and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns. Accordingly, Piedmont and its subsidiaries will file final consolidated income tax returns for the short tax year November 1, 2015 through October 3, 2016. We and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns for the period October 4, 2016 through December 31, 2016. Piedmont and each of our subsidiaries have entered into a tax sharing agreement with Duke Energy and subsidiaries. The tax sharing agreement provides allocation of consolidated tax liabilities and benefits based on amounts participants would incur as separate C-Corporations. Income taxes recorded for the period October 4, 2016 through October 31, 2016 are based on amounts we and our subsidiaries would incur as separate C-Corporations. Current and deferred income tax expense (benefit) of $40.4 million and $(8.7) million, respectively, was recorded for the period October 4 through October 31, 2016. "Taxes accrued" on the Consolidated Balance Sheets as of October 31, 2016 includes $31.5 million payable to Duke Energy for federal income taxes due under the tax sharing agreement. In accordance with IRS regulations, we and our subsidiaries are jointly and severally liable for the federal tax liability.

As of October 31, 2016 and 2015, deferred income taxes consists of the following temporary differences. As discussed in Note 1 and Note 16, Piedmont early adopted ASU 2015-17, providing guidance that deferred tax assets and liabilities be classified as noncurrent. With this retrospective adoption, the balance sheet classification of deferred tax assets and liabilities were classified as noncurrent.

(in millions)	2016			2015
Deferred tax assets:
Benefit of tax carryforwards	$	175.4		$	84.0
Revenues and cost of natural gas	—			3.5
Employee benefits and compensation	28.6			22.1
Revenue requirement	30.1			26.1
Property, plant and equipment	5.3			7.5
Regulatory asset - gas supply derivative contracts held for utility operations	70.6			—
Other	13.8			10.5
Total deferred tax assets	323.8			153.7
Valuation allowance	(0.8		)	(0.8		)
Total deferred tax assets, net	323.0			152.9
Deferred tax liabilities:
Property, plant and equipment	1,010.8			849.8
Revenues and cost of natural gas	20.0			—
Investments in equity method unconsolidated affiliates	34.8			44.8
Deferred costs	85.0			73.9
Gas supply derivative liabilities	70.6			—
Other	5.9			13.6
Total deferred tax liabilities	1,227.1			982.1
Net deferred income tax liabilities	$	904.1		$	829.2

As of October 31, 2016 and 2015, 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.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
Balance at beginning of year	$	0.8	$	0.5	$	0.5
Charged to income tax expense	—		0.3		—
Balance at end of year	$	0.8	$	0.8	$	0.5

The following table presents the expiration of tax carryforwards.

(in millions)	Amount		Expiration Year
Federal NOL	$	163.5	2020	–	2036
State NOL	8.4		2027	–	2036
Capital loss carryforward	0.3				2017
Charitable carryforward	3.2		2016	–	2019
Total NOL and charitable carryforwards	$	175.4

Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of $159.6 million are subject to an effective annual limitation of $31.8 million.

There were no unrecognized tax benefits for the years ended October 31, 2016 and 2015.

During our 2016 fiscal year, we finalized the federal income tax examinations for tax years ended October 31, 2010, 2011 and 2012. We are no longer subject to federal examination and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2012. The statute of limitations for the tax year ending October 31, 2012 expires February 28, 2017.

During fiscal year 2016, we recognized $0.5 million in net interest income related to income taxes.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.

North Carolina Corporate Income Tax Rate *	Tax Year Rate is Effective
6.9%	Prior to November 1, 2014
6.0%	November 1, 2014 to October 31, 2015
5.0%	November 1, 2015 to October 3, 2016
4.0%	October 4, 2016 to December 31, 2016
3.0%	Beginning January 1, 2017
* We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse.

As a result of the state income tax rate reductions, we adjusted our deferred income tax balances during fiscal year 2016 and 2015 by approximately $15.7 million and $17.5 million, respectively, for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit during fiscal years 2016 and 2015 in net income of approximately $0.6 million and $0.5 million and recorded the remainder of approximately $15.1 million and $17.0 million during fiscal 2016 and 2015, respectively, as regulatory "Deferred income taxes" as presented in "Noncurrent Regulatory Liabilities" in Note 3, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional $3.0 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. As of October 31, 2016, we have approximately $58.6 million related to the North Carolina tax rate change included in our "Deferred income taxes" recorded in "Noncurrent Regulatory Liabilities." The NCUC will determine the recovery period of this regulatory liability in future proceedings.

XML

Investments in Unconsolidated Affiliates

12 Months Ended

Oct. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

The Consolidated Financial Statements include the accounts of our wholly owned subsidiaries who have investments in unconsolidated affiliates. These investments are in joint venture, energy-related businesses that are accounted for under the equity method. Our ownership interest in each entity is included in "Investments in equity method unconsolidated affiliates" within "Investments and Other Assets" on the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" in the Consolidated Statements of Operations and Comprehensive Income.

As of October 31, 2016, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

Ownership Interests

We have the following membership interests in these companies as of October 31, 2016.

Entity Name	Interest	Activity
Cardinal Pipeline Company, LLC (Cardinal)	21.49%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Pine Needle LNG Company, LLC (Pine Needle)	45%	Interstate LNG storage facility located in North Carolina; regulated by the FERC
SouthStar *	—%	Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
Hardy Storage Company, LLC (Hardy Storage)	50%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
Constitution Pipeline Company LLC (Constitution)	24%	To develop, construct, own and operate 124 miles of interstate 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 the FERC
Atlantic Coast Pipeline, LLC (ACP) **	7%	To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC
* On October 3, 2016, we sold our 15% interest in SouthStar, effective with the consummation of the Acquisition.
** On October 3, 2016, as a result of the Acquisition, we sold 3% of our interest, reducing our ownership from 10% to 7%.

As of October 31, 2016 and 2015, our investment balances are as follows.

(in millions)	2016		2015
Cardinal	$	14.2	$	15.1
Pine Needle	16.6		18.4
SouthStar	—		41.3
Hardy Storage	42.1		39.7
Constitution	93.1		82.4
ACP	33.2		10.1
Total investments in equity method unconsolidated affiliates	$	199.2	$	207.0

For the years ended October 31, 2016, 2015 and 2014, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income as follows.

(in millions)	2016			2015			2014
Cardinal	$	1.5		$	1.7		$	1.7
Pine Needle	2.8			2.7			2.7
SouthStar	18.8			19.4			20.4
Hardy Storage	5.1			5.2			5.3
Constitution	(1.3		)	6.1			2.7
ACP	1.7			(0.6		)	—
Equity in earnings of unconsolidated affiliates	$	28.6		$	34.5		$	32.8

Accumulated Other Comprehensive Income (Loss)

As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. Until the sale of our interest in SouthStar as discussed above, we recorded OCIL from this investment from financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts was based on selected market indices. For these transactions with these unconsolidated affiliates, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in "Accumulated other comprehensive loss" within "Equity" on the Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments are presented in "Other Comprehensive Income (Loss), net of tax" on the Consolidated Statements of Operations and Comprehensive Income.

Related Party Transactions

We have related party transactions as a customer of our investments. For the years ended October 31, 2016, 2015 and 2014, these gas costs and the amounts we owed to our unconsolidated affiliates, as of October 31, 2016 and 2015, are as follows.

Related Party	Type of Expense	Cost of Natural Gas (1)						Accounts Payable to Affiliated Companies (2)
(in millions)		2016		2015		2014		2016		2015
Cardinal	Transportation costs	$	8.7	$	8.8	$	8.8	$	0.7	$	0.7
Pine Needle	Gas storage costs	10.7		11.4		11.4		0.9		1.0
Hardy Storage	Gas storage costs	9.3		9.3		9.5		0.8		0.8
Totals		$	28.7	$	29.5	$	29.7	$	2.4	$	2.5
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Through October 3, 2016, we had related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended October 31, 2016, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2016 and 2015, are as follows.

	Operating Revenues (1)						Receivables from Affiliated Companies (2)
(in millions)	2016		2015		2014		2016		2015
Operating revenues	$	0.3	$	1.6	$	3.5	$	—	$	0.2
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Information on Our Equity Method Investments

Cardinal

Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and SCANA Corporation. 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.

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	10.3	$	9.5
Noncurrent assets	101.5		106.4
Current liabilities	46.0		1.2
Noncurrent liabilities	0.3		45.4
Revenues	16.6		16.6		$	16.7
Gross profit	16.6		16.6		16.7
Income before income taxes	7.7		7.7		8.0

Pine Needle

Pine Needle is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Pine Needle has firm, long-term service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%. We are dependent on the Williams – Transco pipeline system for redelivery of Pine Needle volumes to our system for service to our customers.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	7.7	$	9.9
Noncurrent assets	68.1		71.6
Current liabilities	3.0		5.4
Noncurrent liabilities	35.2		35.1
Revenues	17.1		16.9		$	18.0
Gross profit	15.4		15.3		15.3
Income before income taxes	6.8		6.0		6.0

SouthStar

SouthStar is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly owned subsidiary of Southern Company Gas (effective July 1, 2016 following its acquisition of AGL Resources, Inc. (AGL)). In September 2015, under the terms of the SouthStar limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to remain a member of SouthStar.

In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. In December 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective upon the consummation of the Acquisition. On October 3, 2016, we sold our 15% interest in SouthStar, and at closing, we received $160.0 million from GNGC resulting in an after-tax gain of $80.9 million.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	212.2	$	204.2
Noncurrent assets	126.8		132.3
Current liabilities	47.1		46.0
Noncurrent liabilities	—		—
Revenues	638.3		769.3		$	845.7
Gross profit	216.4		244.6		234.6
Income before income taxes	125.5		129.3		136.6

Hardy Storage

Hardy Storage is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission, LLC, an indirect subsidiary of TransCanada Corporation. 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 are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery of Hardy Storage volumes to our system for service to our customers.

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	6.6	$	11.7
Noncurrent assets	151.8		156.8
Current liabilities	14.4		19.1
Noncurrent liabilities	59.1		70.0
Revenues	23.5		23.4		$	23.8
Gross profit	23.5		23.4		23.8
Income before income taxes	11.0		10.4		10.5

Constitution

Constitution is 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 will be the operator of the pipeline. In December 2014, the FERC issued an order granting Constitution a certificate of public convenience and necessity.

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 District Court for the Northern District of New York and 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. Both courts granted Constitution's motions to expedite the schedules for the legal actions. On November 16, 2016, oral arguments were heard in the U.S. Court of Appeals.

Constitution has stated that it remains steadfastly committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC's decision. In light of the denial of the certification, Constitution revised its target in-service date of the project to be as early as the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded.

In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. On November 22, 2016, the FERC denied the NYAG's request for reconsideration of this order.

As a result of the NYSDEC's actions, beginning in April 2016, Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved. We evaluated our investment in the Constitution project for OTTI. 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. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are in early stages given the actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. See Note 1 for information on our fair value evaluation process.

Pending the outcome of the matters described above, and when construction proceeds, we remain 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 $955.0 million, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately $229.3 million. As of October 31, 2016, our fiscal year contributions were $12.1 million, with our total equity contributions for the project totaling $84.8 million to date. 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, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016			2015		2014
Current assets	$	6.6		$	6.2
Noncurrent assets	380.9			330.2
Current liabilities	1.2			4.4
Noncurrent liabilities	—			—
Revenues	—			—		$	—
Gross profit	—			—		—
Income (Loss) before income taxes	(3.4		)	24.6		10.1

ACP

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary is the operator of the pipeline. The pipeline is being designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date sometime in the second half of 2019, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under twenty-year contracts.

The total cost for the project is expected to be between $4.5 billion to $5.0 billion, excluding financing costs. Members anticipate obtaining project financing for 60% of the total costs during the construction period, and a project capitalization ratio of 50% debt and 50% equity when operational. As of October 31, 2016, our fiscal year contributions were $35.3 million, with our total equity contributions for the project totaling $46.0 million to date.

In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 to request FERC authorization to construct and operate the project facilities under the previously FERC-approved pre-filing process, including the environmental review for the natural gas pipeline. FERC approval of the application of the certificate of public convenience and necessity is expected in late 2017 with construction projected to begin thereafter.

On April 15, 2016, Dominion, on behalf of ACP, filed an updated application with the FERC. The filing included, among other items, updated alignment sheets, tables and information regarding the alternative routes adopted by the partners since filing a certificate application in September.

On August 12, 2016, the FERC issued its notice of schedule for environmental review of the project. Under the notice of schedule, we anticipate that the FERC will issue its final environmental impact statement by June 30, 2017.

On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. Based on our reduced ownership percentage, this commitment is capped at $10.6 million. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP.

On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.

Under a provision in the ACP limited liability company agreement, Dominion had an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. On October 3, 2016, in connection with the consummation of the Acquisition, Dominion purchased 3% of our 10% membership interest in ACP at book value for $13.9 million, whereby our interest in ACP was reduced to 7%.

Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.

(in millions)	2016		2015
Current assets	$	134.3	$	23.4
Noncurrent assets	376.3		86.1
Current liabilities	47.9		9.1
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income (Loss) before income taxes	17.3		(5.2		)

XML

Variable Interest Entities

12 Months Ended

Oct. 31, 2016

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Variable Interest Entities

Variable Interest Entities

On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. As of October 31, 2016, 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 11. 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, and we will continue to apply equity method accounting to these investments.

Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity, as presented in Note 11.

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.

XML

Business Segments

12 Months Ended

Oct. 31, 2016

Segment Reporting [Abstract]

Business Segments

Business Segments

Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure 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.

The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses. See Note 11 for further information on the sale of SouthStar.

All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Prior periods' segment information has been reclassified to conform to the current year presentation. None of these segment changes impact our reported consolidated revenues or net income. Segment assets as presented in the tables that follow exclude all intercompany assets.

Operations by segment for the years ended October 31, 2016, 2015 and 2014, and related assets as of October 31, 2016, 2015 and 2014, are presented below.

	Year Ended October 31, 2016
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated revenues	$	1,141.7	$	—	$	1,141.7
Related party revenue from Duke Energy	7.0		—		7.0
Total Revenues	$	1,148.7	$	—	$	1,148.7
Interest Expense	$	68.6	$	—	$	68.6
Depreciation and amortization	137.3		—		137.3
Equity in earnings of unconsolidated affiliates	9.8		18.8		28.6
Gain on sale of unconsolidated affiliates	—		132.8		132.8
Income tax expense	85.2		39.0		124.2
Segment income	143.3		49.9		193.2
Capital investments and expenditures and acquisitions	$	569.2	$	—	$	569.2
Segment Assets	5,691.0		—		5,691.0
	Year Ended October 31, 2015
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,383.1	$	—	$	1,383.1
Interest Expense	68.6		—		68.6
Depreciation and amortization	128.7		—		128.7
Equity in earnings of unconsolidated affiliates	15.1		19.4		34.5
Income tax expense	85.9		4.3		90.2
Segment Income	131.1		5.9		137.0
Capital investments and expenditures and acquisitions	$	473.4	$	—	$	473.4
Segment Assets	5,045.0		41.3		5,086.3
	Year Ended October 31, 2014
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,479.5	$	—	$	1,479.5
Interest Expense	54.7		—		54.7
Depreciation and amortization	119.0		—		119.0
Equity in earnings of unconsolidated affiliates	12.3		20.5		32.8
Income tax expense	87.0		7.8		94.8
Segment Income	131.2		12.6		143.8
Capital investments and expenditures and acquisitions	$	498.1	$	—	$	498.1
Segment Assets	4,678.8		41.0		4,719.8

Products and Services

The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.

(in millions)	2016		2015		2014
Retail Natural Gas	$	1,066.3	$	1,237.4	$	1,300.5
Wholesale Natural Gas	72.3		134.3		169.5
Other	10.1		11.4		9.5
Total Revenues	$	1,148.7	$	1,383.1	$	1,479.5

XML

Related Party Transactions with Duke Energy

12 Months Ended

Oct. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions with Duke Energy

Related Party Transactions with Duke Energy

Effective with the consummation of the Acquisition on October 3, 2016, we engage in related party transactions with Duke Energy and its subsidiary registrants in accordance with applicable state and federal regulations. Upon consummation of the Acquisition, our 2018 plan was converted to a Duke Energy RSU Award. Related to this conversion, $6.1 million is included in "Accounts payable to affiliated companies" within "Current Liabilities" on the Consolidated Balance Sheets. See Note 9 for further information.

Amounts related to transactions with Duke Energy occurring subsequent to the consummation of the Acquisition are included in the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The following financial information reflects amounts for the years ended October 31, 2016, 2015 and 2014 related to transactions, assuming the Acquisition had taken place November 1, 2013.

(in millions)	2016		2015		2014
Revenue from Duke Energy (1)	$	80.8	$	83.2	$	86.2
Corporate governance and shared service expenses (2)	0.2
(1) We provide long-term natural gas delivery service to several of Duke Energy's subsidiaries' natural gas-fired power generation facilities in our market area. This intercompany profit on sales is not eliminated in accordance with accounting regulations prescribed under rate-based regulation, as discussed in Note 1.
(2) We are charged our proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. Certain Piedmont executives are responsible for all of Duke Energy's natural gas operations and related infrastructure. A proportionate share of these individuals' payroll and employee benefits is charged to Duke Energy's subsidiary registrants. These amounts are recorded in "Operations, maintenance and other" in the Consolidated Statements of Operations and Comprehensive Income.

See Note 10 for discussion of related party income taxes.

XML

Severance

12 Months Ended

Oct. 31, 2016

Restructuring Charges [Abstract]

Severance

Severance

In conjunction with the Acquisition, certain Piedmont senior executives terminated their employment from Piedmont effective with the closing of the Acquisition. The severance benefits owed to these executives were provided under contracts between the individual and Piedmont, effective upon a change in control. These severances will be paid in April 2017.

In September 2016, Piedmont announced a severance plan covering certain eligible employees whose employment will be involuntarily terminated without cause during the twelve-month period (or twenty-four months for certain senior level employees) following the close of the Acquisition. Upon the close of the Acquisition, positions within Piedmont began to be eliminated. These reductions are a part of the synergies expected to be realized with the Acquisition. The severance benefit payments will be made in accordance with the severance plan.

We recorded $18.7 million severance and related expenses that are included in "Operations, maintenance and other" on the Consolidated Statements of Operations and Comprehensive Income for the year ended October 31, 2016. The severance liability was also $18.7 million as of October 31, 2016 and is included in "Other" within "Current Liabilities" on the Consolidated Balance Sheets. Additional accruals can continue through October 3, 2018 as more positions are eliminated.

XML

Reclassification of Consolidated Financial Statements

12 Months Ended

Oct. 31, 2016

Accounting Changes and Error Corrections [Abstract]

Reclassification of Consolidated Financial Statements

Reclassification of Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows

Reclassifications have been made to prior year Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows.

In the first quarter of 2016, we early adopted ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. With the retrospective adoption of the new pronouncement, the fiscal year 2015 current line item of "Deferred income taxes" of $32.4 million was reclassified to net with the noncurrent line item "Deferred income taxes," similarly reducing "Total Assets" and "Total Liabilities and Equity."

Reclassifications have also been made to conform to the presentation currently used by Piedmont’s new parent company, Duke Energy. None of these reclassifications had a significant effect on the previously reported results of operations, financial position or cash flows of Piedmont but were rather the movement of line items or accounts to conform to Duke Energy’s presentation.

The effect on our Consolidated Statements of Operations and Comprehensive Income was largely related to the statement presentation. Piedmont previously used a utility income statement presentation showing a line item of "Margin" on the face of the income statement that is defined as natural gas revenues less natural gas commodity and fixed gas costs. With Duke Energy’s presentation, the line item of "Cost of natural gas" is presented within "Operating Expenses" with no presentation of regulated margin. See the discussion of regulated margin in "Results of Operations" presented in Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K. Also, we reclassified previously reported utility income taxes of $76.9 million and $83.2 million from line item "Total operating expenses" and non-utility income taxes of $13.3 million and $11.6 million from line item “Total other income (expense)” to the new line item "Income Tax Expense" for the years ended October 31, 2015 and 2014, respectively. These two changes in presentation had no effect on net income.

The effect on our Consolidated Statements of Cash Flows for the years ended October 31, 2015 and 2014 reflects the reclassifications of the balance sheet line items. These reclassifications had no effect on previously reported amounts for net cash provided by operating activities and by financing activities or net cash used in investing activities for the periods previously presented.

XML

Subsequent Events

12 Months Ended

Oct. 31, 2016

Subsequent Events [Abstract]

Subsequent Events

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. See Note 3 for information on subsequent event disclosure items related to regulatory matters.

XML

Quarterly Financial Data

12 Months Ended

Oct. 31, 2016

Quarterly Financial Data [Abstract]

Quarterly Financial Data

Quarterly Financial Data (In millions except per share amounts) (Unaudited)

On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. As a result of the Acquisition, the Consolidated Financial Statements for our fiscal year ended October 31, 2015 have been reclassified to conform to the presentation of Duke Energy, our parent.

The following table reflects the reclassification of our Consolidated Statements of Operations and Comprehensive Income to conform to Duke Energy's presentation.

			Operating				Net
	Operating		Income				Income
	Revenues		(Loss)				(Loss)
Fiscal Year 2016
January 31	$	463.5	$	171.3			$	97.8
April 30	352.9		103.9				63.4
July 31	160.4		0.5				(6.7		)
October 31	171.9		(50.3		)	(1)	38.7			(2)
Fiscal Year 2015
January 31	$	609.5	$	162.2			$	93.0
April 30	427.3		111.1				66.4
July 31	162.2		(1.7		)		(8.3		)
October 31	184.1		(8.8		)		(14.1		)
(1) The quarter loss is primarily due to Acquisition and integration-related expenses incurred in 2016. See Note 2 for further information.
(2) The increase is primarily due to the gain on the sale of our 15% ownership interest in SouthStar, partially offset by Acquisition and integration-related expenses. See Note 11 for further information on the sale of SouthStar.

The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share were calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year.

XML

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Oct. 31, 2016

Accounting Policies [Abstract]

Consolidation, Policy

The Consolidated Financial Statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). The Consolidated Financial Statements reflect 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. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

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.

The Acquisition was recorded using the acquisition method of accounting. Under SEC regulations, Duke Energy elected to not apply push down accounting to the stand alone Piedmont financial statements.

Use of Estimates, Policy

In accordance with GAAP, we 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 during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.

Rate-Regulated Basis of Accounting, Policy

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by 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 effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. Generally, 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 by 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 the regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (OCI).

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential legislation that would affect the regulatory environment.

Utility Plant and Depreciation, Policy

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, where the costs of homogeneous assets are aggregated 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

Depreciation rates for utility plant are approved by our regulatory commissions.

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.

We compute depreciation expense using the straight-line method

Allowance for Funds Used During Construction, Policy

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.

Cash and Cash Equivalents, Policy

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents.

With respect to cash, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

Receivables and Allowance For Doubtful Accounts, Policy

Receivables consist of natural gas sales and transportation services, unbilled revenues, and other miscellaneous receivables, including merchandise and service work, construction related receivables and other miscellaneous receivables. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity.

We write off our customers’ accounts when they are deemed to be uncollectible. Pursuant to orders issued by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), we are authorized to recover actual uncollected gas costs through the purchased gas adjustment (PGA).

Inventories, Policy

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

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.

Fair Value Measurements, Policy

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.

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.

In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third-party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return.

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 for the specific instrument, location or commodity being valued. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

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.

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.

we have long-dated, fixed quantity natural gas supply contracts for our regulated utility operations which are accounted for as derivatives.

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.

Goodwill, Policy

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, 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. When we test goodwill, we use a fair value approach at a reporting unit level, generally equivalent to our operating segment as discussed in Note 13. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value.

Equity Method Investments, Policy

On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment. Each equity method investment is recorded at cost plus its post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment.

Long-Lived Assets, Policy

On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our unconsolidated affiliates and long-lived assets for impairment.

Marketable Securities, Policy

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets in "Other" within "Investments and Other Assets" with any gains or losses recognized currently in earnings.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges.

Issuances and Repurchases of Common Stock, Policy

we have repurchased shares on the open market and such shares were then canceled and became authorized but unissued shares. It was our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.

Asset Retirement Obligations, Policy

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs

The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate

Unamortized Debt Expense, Policy

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 expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt

We amortize bank debt expense over the life of the syndicated revolving credit facility

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 debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt as a regulatory asset or liability 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.

Revenue Recognition, Policy

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 us.

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 on a monthly basis based on principal, rate and term.

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.

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees.

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 gas component of rates may be adjusted periodically under PGA provisions.

Secondary market revenues 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 sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term.

Cost of Gas and Deferred Purchased Gas Adjustments, Policy

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 natural gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives.

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, Policy

We have two categories of income taxes in the Consolidated Statements of Operations and 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.

We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Operations and Comprehensive Income.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions.

Property and other taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

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.

Derivatives, Policy

We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes.

We have included gas supply contracts requiring fair value accounting in "Other" in "Current Liabilities" and "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.

Variable Interest Entities, Policy

On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary.

Segment Reporting, Policy

Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure 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.

The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses.

Subsequent Events, Policy

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.

XML

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Oct. 31, 2016

Accounting Policies [Abstract]

Schedule of Public Utility Property, Plant, and Equipment

The classification of net property, plant and equipment for the years ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Intangible plant	$	3.4		$	3.4
Other storage plant	189.1			181.0
Transmission plant	2,315.8			2,024.3
Distribution plant	2,864.7			2,766.9
General plant	469.7			452.3
Asset retirement cost	—			4.1
Contributions in aid of construction	(5.6		)	(5.4		)
Total utility plant in service	5,837.1			5,426.6
Construction work in progress	233.0			170.3
Plant held for future use	7.7			3.1
Other property	1.3			1.3
Total cost	6,079.1			5,601.3
Utility plant in service accumulated depreciation	(1,328.6		)	(1,252.0		)
Other property accumulated depreciation and amortization	(0.9		)	(0.9		)
Total accumulated depreciation and amortization	(1,329.5		)	(1,252.9		)
Total net property, plant and equipment	$	4,749.6		$	4,348.4

AFUDC for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
AFUDC	$	12.3	$	11.1	$	16.4

Schedule of Trade Account Receivables

As of October 31, 2016 and 2015, our receivables and allowance for doubtful accounts consisted of the following.

(in millions)	2016			2015
Gas receivables	$	43.1		$	57.6
Unbilled revenues	13.4			17.4
Other miscellaneous receivables	20.6			13.5
Allowance for doubtful accounts	(1.9		)	(1.6		)
Receivables and Allowance for Doubtful Accounts	$	75.2		$	86.9

Schedule of Changes in Allowance for Doubtful Accounts

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Balance at beginning of year	$	1.6		$	2.2		$	1.6
Additions charged to uncollectibles expense	4.9			5.1			7.0
Accounts written off, net of recoveries	(4.6		)	(5.7		)	(6.4		)
Balance at end of year	$	1.9		$	1.6		$	2.2

Schedule of Marketable Securities

The composition of these securities as of October 31, 2016 and 2015 is as follows.

	2016				2015
(in millions)	Cost		Fair Value		Cost		Fair Value
Money markets	$	0.5	$	0.5	$	0.5	$	0.5
Mutual funds	3.2		3.7		3.8		4.4
Total trading securities	$	3.7	$	4.2	$	4.3	$	4.9

Schedule of Asset Retirement Obligations

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016		2015
Regulatory non-legal AROs	$	538.0	$	521.5
Conditional AROs	14.1		19.7
Total cost of removal obligations	$	552.1	$	541.2

Schedule of Change in Asset Retirement Obligation

A reconciliation of the changes in conditional AROs for the year ended October 31, 2016 and 2015 is presented below.

(in millions)	2016			2015
Beginning of period	$	19.7		$	14.7
Liabilities incurred during the period	5.5			4.7
Liabilities settled during the period	(6.5		)	(5.6		)
Accretion	1.1			0.9
Adjustment to estimated cash flows	(5.7		)	5.0
End of period	$	14.1		$	19.7

Schedule of New Accounting Pronouncements

Recently Issued Accounting Guidance

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2014-09, May 2014, Revenue from Contracts with Customers (Topic 606), including subsequent ASUs clarifying the guidance	Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from any entity's contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of first period of adoption.	Annual periods (and interim periods within those periods) beginning after December 15, 2017, with early adoption permitted for annual periods beginning after December 15, 2016.	As a Duke Energy registrant, we intend to adopt the revised accounting guidance effective for the interim and annual periods beginning January 1, 2018. We are currently evaluating the effect on our financial position and results of operations, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are monitoring specific developments for our industry.

Guidance	Description	Effective date	Effect on the financial statements or other significant matters
ASU 2016-02, February 2016, Leases (Topic 842)	Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.	Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted.	We are currently evaluating the effect on our financial position and results of operations. We do expect an increase in assets and liabilities from the recording of our operating leases.
ASU 2016-15, August 2016, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments	The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle.	Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.	We are currently evaluating the effect on the presentation of our cash flows.

XML

Acquisition by Duke Energy Corporation (Tables)

12 Months Ended

Oct. 31, 2016

Business Combinations [Abstract]

Schedule Of Merger And Integration Costs

The following table summarizes pre-tax acquisition consummation costs, integration and other related costs (collectively referred to as costs to achieve) that we recorded in connection with the Acquisition and are included in "Operations, maintenance and other" within "Operating Expenses" in the Consolidated Statements of Operations and Comprehensive Income for the years ended October 31, 2016 and 2015.

(in millions)	2016		2015
Financial and legal advisory costs	$	22.4	$	8.6
Severance costs (1)	18.7		—
Charitable contributions and community support (2)	8.8		—
Acceleration of incentive plans (3)	5.3		—
Key employee retention payments	3.5		—
Other	2.9		—
Total	$	61.6	$	8.6
(1) See Note 15 for further information on severance costs.
(2) Charitable contributions and community support reflect: 1) the unconditional obligation to provide funding at a level comparable to historic practices over the next four years, and 2) the unconditional obligation to provide funding for low-income household energy assistance and workforce development programs in North Carolina over the next year.
(3) See Note 9 for further information on the accelerated vesting, payment and taxation of certain share-based awards.

XML

Regulatory Matters (Tables)

12 Months Ended

Oct. 31, 2016

Public Utilities, Rate Matters [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.

(in millions)	2016		2015
REGULATORY ASSETS
Current Regulatory Assets
Unamortized debt expense on reacquired debt	$	0.2	$	0.2
Amounts due from customers	61.9		8.2
Environmental costs	1.5		1.5
Deferred operations and maintenance expenses	0.9		0.8
Deferred pipeline integrity expenses	3.5		3.5
Deferred pension and other retirement benefit costs	2.8		2.8
Robeson LNG development costs	0.1		0.4
Derivatives - gas supply contracts held for utility operations	41.5		—
Other	1.3		1.7
Total current regulatory assets	113.7		19.1
Noncurrent Regulatory Assets
Unamortized debt expense on reacquired debt	4.4		4.7
Environmental costs	3.6		5.1
Deferred operations and maintenance expenses	3.1		4.0
Deferred pipeline integrity expenses	32.4		29.8
Deferred pension and other retirement benefits costs	16.8		17.9
Amounts not yet recognized as a component of pension and other retirement benefit costs	151.6		114.8
Regulatory cost of removal asset	14.1		19.1
Robeson LNG development costs	—		0.1
Derivatives - gas supply contracts held for utility operations	146.4		—
Other	0.9		1.2
Total noncurrent regulatory assets	373.3		196.7
Total Regulatory Assets	$	487.0	$	215.8

Schedule of Regulatory Liabilities

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2016 and 2015 are as follows.

REGULATORY LIABILITIES
Current Regulatory Liabilities
Amounts due to customers	$	—	$	21.5
Noncurrent Regulatory Liabilities
Regulatory cost of removal obligations	538.0		521.5
Deferred income taxes	78.9		68.7
Amounts not yet recognized as a component of pension and other retirement benefit costs	0.1		0.1
Total noncurrent regulatory liabilities	617.0		590.3
Total Regulatory Liabilities	$	617.0	$	611.8

Schedule of Secondary Market Activity

This sharing mechanism for secondary market activity in all three jurisdictions for the twelve months ended October 31, 2016, 2015, and 2014 is presented below.

(in millions)	2016		2015		2014
Allocated to customers as gas cost reductions	$	52.0	$	60.1	$	72.2
Margin allocated to us	17.7		21.1		25.4
Margin from secondary market activity	$	69.7	$	81.2	$	97.6

XML

Common Stock (Tables)

12 Months Ended

Oct. 31, 2016

Stockholders' Equity Note [Abstract]

Schedule of Common Stock Outstanding Roll Forward

Changes in common stock for the years ended October 31, 2016, 2015 and 2014 are as follows.

(in millions)	Shares		Amount
Balance, October 31, 2013	76.1		$	561.6
Issued to participants in the Employee Stock Purchase Plan (ESPP)	—		1.1
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP)	0.7		23.5
Issued to incentive compensation plan (ICP)	0.1		3.3
Issuance of common stock through forward sale agreements (FSAs), net of expenses	1.6		47.3
Balance, October 31, 2014	78.5		636.8
Issued to ESPP	—		1.2
Issued to DRIP	0.7		24.7
Issued to ICP	0.2		5.0
Issuance of common stock through FSAs, net of expenses	1.5		53.7
Balance, October 31, 2015	80.9		721.4
Issued to ESPP *	—		1.0
Issued to DRIP *	0.3		14.5
Issued to ICP	0.3		18.3
Issuance of common stock through FSAs, net of expenses	1.8		104.6
Outstanding shares of common stock converted into the right to receive cash	(83.3	)
Balance, October 31, 2016	—		$	859.8
*In anticipation of the Acquisition, we suspended new investments in our DRIP and ESPP, effective July 31, 2016.

Schedule of Forward Contracts Indexed to Issuer's Equity

The table below presents equity transactions that were settled in shares under the open registration statements over the two-year period ended October 31, 2016.

(in millions, except per share amounts)
Equity Issuance Transaction	Number of Shares	Settled	Net Proceeds Before Issuance Costs (1)		Net Settlement Price Per Share (2)
FSA - executed March 2015	0.6	October 2015	$	21.8	$35.50
FSA - executed June 2015	0.8	October 2015	28.2		$35.49
FSA - executed September 2015	0.1	October 2015	4.1		$36.03
Total 2015 ATM program	1.5		$	54.1
FSA - executed January 2016	0.4	September 2016	$	20.2	$56.25
FSA - executed March 2016	0.6	September 2016	36.2		$58.35
FSA - executed June 2016	0.8	September 2016	48.3		$58.87
Total 2016 ATM program	1.8		$	104.7
(1) Issuance costs incurred as follows: October 2015 shares $0.4 million and September 2016 shares $0.1 million.
(2) Net of 1.5% commission plus other adjustments.

Schedule of Accumulated Other Comprehensive Income (Loss)

Changes in each component of accumulated OCIL are presented below for the years ended October 31, 2016 and 2015.

Changes in Accumulated OCIL (1)
(in millions)	2016			2015
Accumulated OCIL beginning balance, net of tax	$	(0.8	)	$	(0.2	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(2.8		)	(1.6		)
Amounts reclassified from accumulated OCIL, net of tax	3.4			1.0
Total current period activity of hedging activities of equity method investments, net of tax	0.6			(0.6		)
Accumulated OCIL ending balance, net of tax	$	(0.2	)	$	(0.8	)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

Reclassification out of Accumulated Other Comprehensive Income

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended October 31, 2016 and 2015.

Reclassification Out of Accumulated OCIL (1)
	Years Ended					Affected Line Items on Statement of Operations and Comprehensive Income
	October 31,
(in millions)	2016		2015
Hedging activities of equity method investments	$	1.4	$	1.7		Equity in earnings of unconsolidated affiliates
Income tax expense	2.0		(0.7		)	Income tax expense
Total reclassification for the period, net of tax	$	3.4	$	1.0
(1) Amounts in parentheses indicate debits to accumulated OCIL.

XML

Debt and Credit Facilities (Tables)

12 Months Ended

Oct. 31, 2016

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.

	Long-Term Debt as of October 31, 2016
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
8.51%, due September 30, 2017	$	35.0	$	—		$	35.0
4.24%, due June 6, 2021	160.0		(0.6		)	159.4
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.2		)	198.8
4.10%, due September 18, 2034	250.0		(2.5		)	247.5
4.65%, due August 1, 2043	300.0		(2.9		)	297.1
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
3.64%, due November 1, 2046	300.0		(3.4		)	296.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.2		)	59.8
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,835.0		(14.0		)	1,821.0
Less current maturities	35.0		—			35.0
Total	$	1,800.0	$	(14.0	)	$	1,786.0

	Long-Term Debt as of October 31, 2015
(in millions)	Principal		Unamortized Debt Issuance Expenses and Discounts			Total
Senior Notes:
2.92%, due June 6, 2016	$	40.0	$	(0.1	)	$	39.9
8.51%, due September 30, 2017	35.0		—			35.0
4.24%, due June 6, 2021	160.0		(0.8		)	159.2
3.47%, due July 16, 2027	100.0		(0.6		)	99.4
3.57%, due July 16, 2027	200.0		(1.3		)	198.7
4.10%, due September 18, 2034	250.0		(2.6		)	247.4
4.65%, due August 1, 2043	300.0		(3.0		)	297.0
3.60%, due September 1, 2025	150.0		(1.4		)	148.6
Medium-Term Notes:
6.87%, due October 6, 2023	45.0		(0.1		)	44.9
8.45%, due September 19, 2024	40.0		(0.1		)	39.9
7.40%, due October 3, 2025	55.0		(0.2		)	54.8
7.50%, due October 9, 2026	40.0		(0.1		)	39.9
7.95%, due September 14, 2029	60.0		(0.3		)	59.7
6.00%, due December 19, 2033	100.0		(0.7		)	99.3
Total	1,575.0		(11.3		)	1,563.7
Less current maturities	40.0		—			40.0
Total	$	1,535.0	$	(11.3	)	$	1,523.7

Schedule of Maturities of Long-term Debt

Current maturities for the next five years ending October 31 and thereafter are as follows.

(in millions)
2017	$	35.0
2018	—
2019	—
2020	—
2021	160.0
Thereafter	1,640.0
Total	$	1,835.0

Schedule of Short-term Debt Activities

A summary of the short-term debt activity under our CP program for the twelve months ended October 31, 2016 is as follows.

(in millions)
Minimum amount outstanding	$	110.0
Maximum amount outstanding	$	530.0
Minimum interest rate	.20		%
Maximum interest rate	.75		%
Weighted average interest rate	.55		%

XML

Financial Instruments & Related Fair Value (Tables)

12 Months Ended

Oct. 31, 2016

Financial Instruments & Related Fair Value [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of October 31, 2016 and 2015.

We have had no transfers between any level during the years ended October 31, 2016 and 2015.

Recurring Fair Value Measurements as of October 31, 2016
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.5	$	—	$	—	$	—	$	1.5
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	3.7		—		—		—		3.7
Total fair value assets	$	5.7	$	—	$	—	$	—	$	5.7
Liabilities:
Derivatives - gas supply contracts held for utility operations	$	—	$	—	$	187.9	$	—	$	187.9

Recurring Fair Value Measurements as of October 31, 2015
			Significant				Effects of
	Quoted Prices		Other		Significant		Netting and
	in Active		Observable		Unobservable		Cash Collateral		Total
	Markets		Inputs		Inputs		Receivables/		Carrying
(in millions)	(Level 1)		(Level 2)		(Level 3)		Payables		Value
Assets:
Derivatives held for distribution operations	$	1.3	$	—	$	—	$	—	$	1.3
Debt and equity securities held as trading securities:
Money markets	0.5		—		—		—		0.5
Mutual funds	4.4		—		—		—		4.4
Total fair value assets	$	6.2	$	—	$	—	$	—	$	6.2

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.

(in millions)	2016
Gas supply derivative liabilities, beginning balance	$	—
Realized and unrealized losses:
Recorded to regulatory assets *	187.9
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Gas supply derivative liabilities, ending balance	$	187.9
* Included are the actual costs recorded within "Cost of natural gas" on the Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing.

Amount Of Gain Loss Recognized On Derivatives And Deferred Under PGA Procedures

The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended October 31, 2016 and 2015, 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 millions)	2016			2015			2016			2015
Gas purchase options	$	(5.2	)	$	(4.4	)	$	(5.2	)	$	(4.4	)	Cost of natural gas

The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of October 31, 2016 and 2015.

Fair Value of Derivative Instruments
(in millions)	2016		2015
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Financial Asset Instruments:
Current Assets - Gas purchase derivative assets	$	1.5	$	1.3
Nonfinancial Liabilities Instruments:
Current Liabilities - Gas supply derivative liabilities	41.5
Noncurrent Liabilities - Gas supply derivative liabilities	146.4

Fair Value, by Balance Sheet Grouping

The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.

(in millions)	Principal		Fair Value
As of October 31, 2016	$	1,835.0	$	2,061.2
As of October 31, 2015	1,575.0		1,720.6

XML

Commitments & Contingencies (Tables)

12 Months Ended

Oct. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of Operating Lease Payments

Operating lease payments for the years ended October 31, 2016, 2015 and 2014 are as follows.

(in millions)	2016		2015		2014
Operating lease payments (1)	$	4.8	$	5.0	$	4.7
(1) Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

(in millions)
2017	$	4.7
2018	4.6
2019	4.4
2020	4.5
2021	4.6
Thereafter	19.8
Total	$	42.6

Schedule of Future Unconditional Purchase Obligations

As of October 31, 2016, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

	Pipeline		Gas Supply		Gas Supply		Telecommunications
	and Storage		Reservation		Purchase		and Information
(in millions)	Capacity		Fees		Commitments		Technology		Other		Total
2017	$	170.0	$	2.2	$	124.4	$	9.6	$	62.1	$	368.3
2018	143.8		—		96.8		5.4		—		246.0
2019	133.4		—		96.8		5.2		—		235.4
2020	115.4		—		97.1		4.5		—		217.0
2021	113.7		—		96.8		1.1		—		211.6
Thereafter	405.5		—		896.1		—		—		1,301.6
Total	$	1,081.8	$	2.2	$	1,408.0	$	25.8	$	62.1	$	2,579.9

XML

Employee Benefit Plans (Tables)

12 Months Ended

Oct. 31, 2016

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Schedule of Defined Benefit Plans Disclosures

We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31, 2017.

(in millions)
Qualified pension plan	$	10.0
Nonqualified pension plans	0.5
MPP plan	2.1
OPEB plan	2.2

The target and actual allocations of the OPEB plan's assets are as follows.

	Target			Assets as of October 31,
Asset Allocations	Allocation			2016		2015
Fixed income securities	45	%	(1)	47	%	47	%
Equity securities	47	%		44	%	44	%
Real estate	5	%		5	%	5	%
Cash and cash equivalents	3	%		4	%	4	%
Total	100	%		100	%	100	%
(1) Includes 5% target allocation to high yield fixed income.

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2016 and 2015, a statement of the funded status and the amounts reflected in the Consolidated Balance Sheets for the years ended October 31, 2016 and 2015, and the weighted average assumptions used in the measurement of the benefit obligations as of October 31, 2016 and 2015 are presented below.

	Qualified Pension						Nonqualified Pension						Other Benefits
(in millions)	2016			2015			2016			2015			2016			2015
Accumulated benefit obligation at year end	$	296.3		$	263.1		$	4.6		$	5.5		N/A			N/A
Change in projected benefit obligation:
Obligation at beginning of year	$	311.5		$	302.7		$	5.5		$	5.9		$	37.6		$	37.8
Service cost	10.6			11.4			—			—			1.2			1.2
Interest cost	9.5			12.0			0.2			0.2			1.3			1.5
Plan amendments	—			—			—			—			—			(1.9		)
Plan settlements	—			—			(0.9		)	—			—			—
Actuarial loss (gain)	34.1			3.5			0.3			(0.1		)	1.6			1.7
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Obligation at end of year	351.7			311.5			4.6			5.5			39.3			37.6
Change in fair value of plan assets:
Fair value at beginning of year	329.3			336.4			—			—			27.5			27.7
Actual return on plan assets	17.6			1.0			—			—			1.1			0.3
Employer contributions	10.0			10.0			1.4			0.5			2.6			2.2
Participant contributions	—			—			—			—			0.1			0.6
Administrative expenses	(0.5		)	(0.6		)	—			—			—			—
Plan settlements	—			—			(0.9		)	—			—			—
Benefit payments	(13.5		)	(17.5		)	(0.5		)	(0.5		)	(2.5		)	(3.3		)
Fair value at end of year	342.9			329.3			—			—			28.8			27.5
Funded status at year end - (under) over	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Noncurrent assets	$	—		$	17.8		$	—		$	—		$	—		$	—
Current liabilities	—			—			(0.5		)	(0.5		)	—			—
Noncurrent liabilities	(8.8		)	—			(4.1		)	(5.0		)	(10.5		)	(10.1		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Amounts Not Yet Recognized as a Component
of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized prior service credit (cost)	$	10.7		$	12.8		$	—		$	(0.2	)	$	1.5		$	1.9
Unrecognized actuarial loss	(153.1		)	(120.5		)	(1.5		)	(1.6		)	(9.1		)	(7.2		)
Regulatory asset	(142.4		)	(107.7		)	(1.5		)	(1.8		)	(7.6		)	(5.3		)
Cumulative employer contributions in
excess of cost	133.6			125.5			(3.1		)	(3.7		)	(2.9		)	(4.8		)
Net amount recognized	$	(8.8	)	$	17.8		$	(4.6	)	$	(5.5	)	$	(10.5	)	$	(10.1	)
Weighted average assumptions used in the measurement of
the benefit obligations:
Discount rate	3.80		%	4.34		%	3.80		%	3.85		%	3.80		%	4.38		%
Rate of compensation increase	4.05		%	4.07		%	N/A			N/A			N/A			N/A

The 2017 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 millions)	Pension			Pension		Benefits
Amortization of unrecognized prior service credit	$	(2.2	)	$	—	$	(0.3	)
Amortization of unrecognized actuarial loss	11.3			0.1		0.7

The target and actual allocations of the qualified pension plan's assets are as follows.

	Target		Assets as of October 31,
Asset Allocations	Allocation		2016		2015
Fixed income securities	45	%	46	%	46	%
Equity securities	35	%	33	%	34	%
Real estate	5	%	5	%	5	%
Cash and cash equivalents	—	%	2	%	1	%
Other investments	15	%	14	%	14	%
Total	100	%	100	%	100	%

Supplemental Executive Retirement Plans

Our funding to the DCR plan account for the years ended October 31, 2016 and 2015, and the amounts recorded as liabilities for these two deferred compensation plans as of October 31, 2016 and 2015, are presented below.

(in millions)	2016		2015
Funding	$	0.5	$	0.5
Liability	4.7		5.3

Components Of Net Periodic Benefit Cost

Net periodic benefit cost components for the years ended October 31, 2016, 2015 and 2014 and the weighted average assumptions used to determine net period benefit cost as of October 31, 2016, 2015 and 2014 are presented below.

	Qualified Pension									Nonqualified Pension									Other Benefits
(in millions)	2016			2015			2014			2016			2015			2014			2016			2015			2014
Service cost	$	10.6		$	11.4		$	10.9		$	—		$	—		$	—		$	1.2		$	1.2		$	1.1
Interest cost	9.5			12.0			11.7			0.2			0.2			0.2			1.3			1.5			1.5
Expected return on plan assets	(24.0		)	(23.6		)	(22.5		)	—			—			—			(1.8		)	(1.8		)	(1.8		)
Amortization of prior service (credit)
cost	(2.2		)	(2.2		)	(2.2		)	0.2			0.2			0.2			(0.3		)	—			—
Amortization of net loss	8.0			8.7			7.7			—			0.1			0.1			0.4			—			—
Settlement loss recognized	—			—			—			0.3			—			—			—			—			—
Net periodic benefit cost	1.9			6.3			5.6			0.7			0.5			0.5			0.8			0.9			0.8
Other changes in plan assets and benefit
obligation recognized through
regulatory asset or liability:
Prior service cost (credit)	—			—			—			—			—			0.5			—			(1.9		)	—
Net loss (gain)	40.5			26.2			14.4			0.3			(0.1		)	1.0			2.4			3.2			3.6
Amounts recognized as a component of
net periodic benefit cost:
Amortization of net loss	(8.0		)	(8.7		)	(7.7		)	—			(0.1		)	(0.1		)	(0.4		)	—			—
Settlement loss recognized	—			—			—			(0.3		)	—			—			—			—			—
Prior service credit (cost)	2.2			2.2			2.2			(0.2		)	(0.2		)	(0.2		)	0.3			—			—
Total recognized in regulatory asset
(liability)	34.7			19.7			8.9			(0.2		)	(0.4		)	1.2			2.3			1.3			3.6
Total recognized in net periodic benefit
and regulatory asset	$	36.6		$	26.0		$	14.5		$	0.5		$	0.1		$	1.7		$	3.1		$	2.2		$	4.4
Weighted average assumptions used to determine the net periodic benefit cost:
Discount rate	4.34		%	4.13		%	4.55		%	3.85		%	3.69		%	3.98		%	4.38		%	4.03		%	4.44		%
Expected long-term rate of return on plan assets	7.25		%	7.50		%	7.75		%	N/A			N/A			N/A			7.25		%	7.50		%	7.75		%
Rate of compensation increase	4.07		%	3.68		%	3.72		%	N/A			N/A			N/A			N/A			N/A			N/A

Expected Benefit Payments For The Next Ten Years

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 millions)	Pension		Pension		Benefits
2017	$	39.6	$	0.5	$	1.9
2018	25.2		0.5		2.1
2019	25.0		0.5		2.2
2020	24.8		0.4		2.4
2021	24.9		0.4		2.4
2022 – 2026	126.8		1.7		13.1

Redemption Limitations, Restrictions and Notice Requirements

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, 2016.	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 business 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 8 to 10 years.

The Qualified Pension and The OPEB Plan's Asset Allocations By Level Within the Fair Value Hierarchy

	Qualified Pension Plan as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	5.1	$	0.8	$	—	$	5.9
Fixed income securities	—		78.9		—		78.9
Equity securities	44.4		—		—		44.4
Mutual funds	78.2		55.0		—		133.2
Common trust fund	—		25.0		—		25.0
Private equity fund of funds	—		—		8.9		8.9
Other Investments:
Hedge fund of funds							20.0		(1)
Commodities fund of funds							9.2		(1)
High yield debt (bank loans)							17.4		(1)
Total assets at fair value	$	127.7	$	159.7	$	8.9	$	342.9

	Qualified Pension Plan as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	2.8	$	0.1	$	—	$	2.9
Fixed income securities	—		84.1		—		84.1
Equity securities	44.7		—		—		44.7
Mutual funds	78.9		42.9		—		121.8
Common trust fund	—		23.6		—		23.6
Private equity fund of funds	—		—		8.3		8.3
Other Investments:
Hedge fund of funds							19.8		(1)
Commodities fund of funds							7.7		(1)
High yield debt (bank loans)							16.4		(1)
Total assets at fair value	$	126.4	$	150.7	$	8.3	$	329.3
(1) In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

	Other Benefits as of October 31, 2016
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.2	$	—	$	—	$	1.2
Mutual funds	27.6		—		—		27.6
Total assets at fair value	$	28.8	$	—	$	—	$	28.8

	Other Benefits as of October 31, 2015
(in millions)	Quoted Prices In Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Cash and cash equivalents	$	1.1	$	—	$	—	$	1.1
Mutual funds	26.4		—		—		26.4
Total assets at fair value	$	27.5	$	—	$	—	$	27.5

Level 3 Qualified Pension Plan Reconciliation

The following is a reconciliation of the assets in the qualified pension plan that are classified as Level 3 in the fair value hierarchy.

	Private
	Equity Fund
(in millions)	of Funds
Balance, October 31, 2014	$	7.2
Actual return on plan assets:
Relating to assets still held at the reporting date	0.4
Relating to assets sold during the period	0.6
Purchases, sales and settlements (net)	0.1
Transfer in/out of Level 3	—
Balance, October 31, 2015	8.3
Actual return on plan assets:
Relating to assets still held at the reporting date	0.1
Relating to assets sold during the period	0.5
Purchases, sales and settlements (net)	—
Transfer in/out of Level 3	—
Balance, October 31, 2016	$	8.9

401(k) Matching Contributions

For the years ended October 31, 2016, 2015 and 2014, we made matching contributions to participant accounts as follows.

(in millions)	2016		2015		2014
401(k) matching contributions	$	6.9	$	6.6	$	6.1

XML

Employee Share Based Plans (Tables)

12 Months Ended

Oct. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity

The following table summarizes the settlement of the RSUs.

	December 15, 2014 vesting (20% of the grant)			December 15, 2015 vesting (30% of the grant)			Accelerated RSU settled on December 15, 2015 (50% of the grant)
Shares of common stock issued, including accrued dividends, net of shares withheld for taxes	7,231			11,732			19,554
NYSE composite closing price	$	37.89	(1)	$	56.85	(2)	$	56.85	(2)
(1) Closing price on December 12, 2014.
(2) Closing price on December 14, 2015.

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

The compensation expense related to the awards under the ICP for the years ended October 31, 2016, 2015 and 2014, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the Consolidated Balance Sheets as of October 31, 2016 and 2015 are presented below.

(in millions)	2016			2015		2014
Compensation expense	$	16.1	(1)	$	14.2	$	8.5
Tax benefit	6.1			4.0		2.5
Liability	—			22.0
(1) Includes $5.3 million incremental expense related to the accelerated ICP and RSU awards, and the conversion of the 2018 plan to a Duke Energy RSU Award. See Note 2 for further information.

XML

Income Taxes (Tables)

12 Months Ended

Oct. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of income tax expense for the years ended October 31, 2016, 2015 and 2014 are presented below.

	2016					2015					2014
(in millions)	Federal			State		Federal			State		Federal			State
Charged (Credited) to income:
Current	$	27.2		$	11.8	$	(0.7	)	$	1.1	$	2.5		$	1.8
Deferred (1) (2)	79.6			5.8		77.9			12.1		76.5			14.2
Tax Credits:
Amortization	(0.2		)	—		(0.2		)	—		(0.2		)	—
Total	$	106.6		$	17.6	$	77.0		$	13.2	$	78.8		$	16.0
(1) Includes benefits from net operating loss (NOL) and tax carryforwards of $91.4 million and $64.3 million for the years ended October 31, 2016 and 2015, respectively.
(2) Includes the anticipated utilization of NOL and tax carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016			2015			2014
Federal taxes at 35%	$	111.1		$	79.5		$	83.5
State income taxes, net of federal benefit	11.4			8.6			10.4
Amortization of investment tax credits	(0.2		)	(0.2		)	(0.2		)
Other, net	1.9			2.3			1.1
Total	$	124.2		$	90.2		$	94.8
Effective Tax Rate	39.1		%	39.7		%	39.7		%

Schedule of Deferred Tax Assets and Liabilities

As of October 31, 2016 and 2015, deferred income taxes consists of the following temporary differences.

(in millions)	2016			2015
Deferred tax assets:
Benefit of tax carryforwards	$	175.4		$	84.0
Revenues and cost of natural gas	—			3.5
Employee benefits and compensation	28.6			22.1
Revenue requirement	30.1			26.1
Property, plant and equipment	5.3			7.5
Regulatory asset - gas supply derivative contracts held for utility operations	70.6			—
Other	13.8			10.5
Total deferred tax assets	323.8			153.7
Valuation allowance	(0.8		)	(0.8		)
Total deferred tax assets, net	323.0			152.9
Deferred tax liabilities:
Property, plant and equipment	1,010.8			849.8
Revenues and cost of natural gas	20.0			—
Investments in equity method unconsolidated affiliates	34.8			44.8
Deferred costs	85.0			73.9
Gas supply derivative liabilities	70.6			—
Other	5.9			13.6
Total deferred tax liabilities	1,227.1			982.1
Net deferred income tax liabilities	$	904.1		$	829.2

Summary of Valuation Allowance

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2016, 2015 and 2014 is presented below.

(in millions)	2016		2015		2014
Balance at beginning of year	$	0.8	$	0.5	$	0.5
Charged to income tax expense	—		0.3		—
Balance at end of year	$	0.8	$	0.8	$	0.5

Summary of Operating Loss Carryforwards

The following table presents the expiration of tax carryforwards.

(in millions)	Amount		Expiration Year
Federal NOL	$	163.5	2020	–	2036
State NOL	8.4		2027	–	2036
Capital loss carryforward	0.3				2017
Charitable carryforward	3.2		2016	–	2019
Total NOL and charitable carryforwards	$	175.4

Schedule of Changes to Corporate State Income Tax Rates

The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.

North Carolina Corporate Income Tax Rate *	Tax Year Rate is Effective
6.9%	Prior to November 1, 2014
6.0%	November 1, 2014 to October 31, 2015
5.0%	November 1, 2015 to October 3, 2016
4.0%	October 4, 2016 to December 31, 2016
3.0%	Beginning January 1, 2017
* We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse.

XML

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Oct. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investments

For the years ended October 31, 2016, 2015 and 2014, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2016 and 2015, are as follows.

	Operating Revenues (1)						Receivables from Affiliated Companies (2)
(in millions)	2016		2015		2014		2016		2015
Operating revenues	$	0.3	$	1.6	$	3.5	$	—	$	0.2
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	212.2	$	204.2
Noncurrent assets	126.8		132.3
Current liabilities	47.1		46.0
Noncurrent liabilities	—		—
Revenues	638.3		769.3		$	845.7
Gross profit	216.4		244.6		234.6
Income before income taxes	125.5		129.3		136.6

As of October 31, 2016 and 2015, our investment balances are as follows.

(in millions)	2016		2015
Cardinal	$	14.2	$	15.1
Pine Needle	16.6		18.4
SouthStar	—		41.3
Hardy Storage	42.1		39.7
Constitution	93.1		82.4
ACP	33.2		10.1
Total investments in equity method unconsolidated affiliates	$	199.2	$	207.0

For the years ended October 31, 2016, 2015 and 2014, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "Equity in earnings of unconsolidated affiliates" within "Other Income and Expense" on the Consolidated Statements of Operations and Comprehensive Income as follows.

(in millions)	2016			2015			2014
Cardinal	$	1.5		$	1.7		$	1.7
Pine Needle	2.8			2.7			2.7
SouthStar	18.8			19.4			20.4
Hardy Storage	5.1			5.2			5.3
Constitution	(1.3		)	6.1			2.7
ACP	1.7			(0.6		)	—
Equity in earnings of unconsolidated affiliates	$	28.6		$	34.5		$	32.8

Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016			2015		2014
Current assets	$	6.6		$	6.2
Noncurrent assets	380.9			330.2
Current liabilities	1.2			4.4
Noncurrent liabilities	—			—
Revenues	—			—		$	—
Gross profit	—			—		—
Income (Loss) before income taxes	(3.4		)	24.6		10.1

For the years ended October 31, 2016, 2015 and 2014, these gas costs and the amounts we owed to our unconsolidated affiliates, as of October 31, 2016 and 2015, are as follows.

Related Party	Type of Expense	Cost of Natural Gas (1)						Accounts Payable to Affiliated Companies (2)
(in millions)		2016		2015		2014		2016		2015
Cardinal	Transportation costs	$	8.7	$	8.8	$	8.8	$	0.7	$	0.7
Pine Needle	Gas storage costs	10.7		11.4		11.4		0.9		1.0
Hardy Storage	Gas storage costs	9.3		9.3		9.5		0.8		0.8
Totals		$	28.7	$	29.5	$	29.7	$	2.4	$	2.5
(1) In the Consolidated Statements of Operations and Comprehensive Income.
(2) In the Consolidated Balance Sheets.

Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.

(in millions)	2016		2015
Current assets	$	134.3	$	23.4
Noncurrent assets	376.3		86.1
Current liabilities	47.9		9.1
Noncurrent liabilities	—		—
Revenues	—		—
Gross profit	—		—
Income (Loss) before income taxes	17.3		(5.2		)

We have the following membership interests in these companies as of October 31, 2016.

Entity Name	Interest	Activity
Cardinal Pipeline Company, LLC (Cardinal)	21.49%	Intrastate pipeline located in North Carolina; regulated by the NCUC
Pine Needle LNG Company, LLC (Pine Needle)	45%	Interstate LNG storage facility located in North Carolina; regulated by the FERC
SouthStar *	—%	Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
Hardy Storage Company, LLC (Hardy Storage)	50%	Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
Constitution Pipeline Company LLC (Constitution)	24%	To develop, construct, own and operate 124 miles of interstate 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 the FERC
Atlantic Coast Pipeline, LLC (ACP) **	7%	To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC
* On October 3, 2016, we sold our 15% interest in SouthStar, effective with the consummation of the Acquisition.
** On October 3, 2016, as a result of the Acquisition, we sold 3% of our interest, reducing our ownership from 10% to 7%.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	7.7	$	9.9
Noncurrent assets	68.1		71.6
Current liabilities	3.0		5.4
Noncurrent liabilities	35.2		35.1
Revenues	17.1		16.9		$	18.0
Gross profit	15.4		15.3		15.3
Income before income taxes	6.8		6.0		6.0

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	6.6	$	11.7
Noncurrent assets	151.8		156.8
Current liabilities	14.4		19.1
Noncurrent liabilities	59.1		70.0
Revenues	23.5		23.4		$	23.8
Gross profit	23.5		23.4		23.8
Income before income taxes	11.0		10.4		10.5

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.

(in millions)	2016		2015		2014
Current assets	$	10.3	$	9.5
Noncurrent assets	101.5		106.4
Current liabilities	46.0		1.2
Noncurrent liabilities	0.3		45.4
Revenues	16.6		16.6		$	16.7
Gross profit	16.6		16.6		16.7
Income before income taxes	7.7		7.7		8.0

XML

Business Segments (Tables)

12 Months Ended

Oct. 31, 2016

Segment Reporting [Abstract]

Business Segment Data

Operations by segment for the years ended October 31, 2016, 2015 and 2014, and related assets as of October 31, 2016, 2015 and 2014, are presented below.

	Year Ended October 31, 2016
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated revenues	$	1,141.7	$	—	$	1,141.7
Related party revenue from Duke Energy	7.0		—		7.0
Total Revenues	$	1,148.7	$	—	$	1,148.7
Interest Expense	$	68.6	$	—	$	68.6
Depreciation and amortization	137.3		—		137.3
Equity in earnings of unconsolidated affiliates	9.8		18.8		28.6
Gain on sale of unconsolidated affiliates	—		132.8		132.8
Income tax expense	85.2		39.0		124.2
Segment income	143.3		49.9		193.2
Capital investments and expenditures and acquisitions	$	569.2	$	—	$	569.2
Segment Assets	5,691.0		—		5,691.0
	Year Ended October 31, 2015
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,383.1	$	—	$	1,383.1
Interest Expense	68.6		—		68.6
Depreciation and amortization	128.7		—		128.7
Equity in earnings of unconsolidated affiliates	15.1		19.4		34.5
Income tax expense	85.9		4.3		90.2
Segment Income	131.1		5.9		137.0
Capital investments and expenditures and acquisitions	$	473.4	$	—	$	473.4
Segment Assets	5,045.0		41.3		5,086.3
	Year Ended October 31, 2014
	Gas
	Utilities and
(in millions)	Infrastructure		Other		Total
Unaffiliated Revenues	$	1,479.5	$	—	$	1,479.5
Interest Expense	54.7		—		54.7
Depreciation and amortization	119.0		—		119.0
Equity in earnings of unconsolidated affiliates	12.3		20.5		32.8
Income tax expense	87.0		7.8		94.8
Segment Income	131.2		12.6		143.8
Capital investments and expenditures and acquisitions	$	498.1	$	—	$	498.1
Segment Assets	4,678.8		41.0		4,719.8

Schedule of Revenue, By Products and Services

The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.

(in millions)	2016		2015		2014
Retail Natural Gas	$	1,066.3	$	1,237.4	$	1,300.5
Wholesale Natural Gas	72.3		134.3		169.5
Other	10.1		11.4		9.5
Total Revenues	$	1,148.7	$	1,383.1	$	1,479.5

XML

Related Party Transactions with Duke Energy (Tables)

12 Months Ended

Oct. 31, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following financial information reflects amounts for the years ended October 31, 2016, 2015 and 2014 related to transactions, assuming the Acquisition had taken place November 1, 2013.

(in millions)	2016		2015		2014
Revenue from Duke Energy (1)	$	80.8	$	83.2	$	86.2
Corporate governance and shared service expenses (2)	0.2
(1) We provide long-term natural gas delivery service to several of Duke Energy's subsidiaries' natural gas-fired power generation facilities in our market area. This intercompany profit on sales is not eliminated in accordance with accounting regulations prescribed under rate-based regulation, as discussed in Note 1.
(2) We are charged our proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. Certain Piedmont executives are responsible for all of Duke Energy's natural gas operations and related infrastructure. A proportionate share of these individuals' payroll and employee benefits is charged to Duke Energy's subsidiary registrants. These amounts are recorded in "Operations, maintenance and other" in the Consolidated Statements of Operations and Comprehensive Income.

XML

Quarterly Financial Data (Tables)

12 Months Ended

Oct. 31, 2016

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information

The following table reflects the reclassification of our Consolidated Statements of Operations and Comprehensive Income to conform to Duke Energy's presentation.

			Operating				Net
	Operating		Income				Income
	Revenues		(Loss)				(Loss)
Fiscal Year 2016
January 31	$	463.5	$	171.3			$	97.8
April 30	352.9		103.9				63.4
July 31	160.4		0.5				(6.7		)
October 31	171.9		(50.3		)	(1)	38.7			(2)
Fiscal Year 2015
January 31	$	609.5	$	162.2			$	93.0
April 30	427.3		111.1				66.4
July 31	162.2		(1.7		)		(8.3		)
October 31	184.1		(8.8		)		(14.1		)
(1) The quarter loss is primarily due to Acquisition and integration-related expenses incurred in 2016. See Note 2 for further information.
(2) The increase is primarily due to the gain on the sale of our 15% ownership interest in SouthStar, partially offset by Acquisition and integration-related expenses. See Note 11 for further information on the sale of SouthStar.

XML

Summary Of Significant Accounting Policies (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2014	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2016	Oct. 03, 2016	Oct. 31, 2015	Dec. 31, 2013	Oct. 31, 2012
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Intangible plant					$ 3,400,000		$ 3,400,000
Other storage plant					189,100,000		181,000,000
Transmission plant					2,315,800,000		2,024,300,000
Distribution plant					2,864,700,000		2,766,900,000
General plant					469,700,000		452,300,000
Asset retirement cost					0		4,100,000
Contributions in aid of construction					(5,600,000)		(5,400,000)
Total utility plant in service					5,837,100,000		5,426,600,000
Construction work in progress					233,000,000		170,300,000
Plant held for future use					7,700,000		3,100,000
Other property					1,300,000		1,300,000
Total Cost					6,079,100,000		5,601,300,000
Utility plant in service accumulated depreciation					(1,328,600,000)		(1,252,000,000)
Other property accumulated depreciation and amortization					(900,000)		(900,000)
Accumulated depreciation and amortization					(1,329,500,000)		(1,252,900,000)
Net property, plant and equipment					4,749,600,000		4,348,400,000
Public Utilities, Property, Plant and Equipment [Abstract]
Allowance for borrowed funds used during construction		$ 12,300,000	$ 11,100,000	$ 16,400,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use					7,700,000		3,100,000
Transfer From Construction Work In Progress to Plant Held For Future Use		$ 4,600,000
Composite weighted-average depreciation rates		2.44%	2.48%	2.54%
Public Utilities, General Disclosures [Line Items]
Regulatory Assets					487,000,000		215,800,000
Regulatory Assets, Current					113,700,000		19,100,000
Accounts, Notes, Loans and Financing Receivable, Net, Current [Abstract]
Gas receivables					43,100,000		57,600,000
Unbilled revenues					13,400,000		17,400,000
Other miscellaneous receivables					20,600,000		13,500,000
Allowance for doubtful accounts		$ (1,600,000)	$ (2,200,000)	$ (1,600,000)	(1,900,000)		(1,600,000)
Receivables and Allowance for Doubtful Accounts					75,200,000		86,900,000
Customers Payment Due Date		30 days
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year		$ (1,600,000)	(2,200,000)	(1,600,000)
Additions charged to uncollectibles expense		4,900,000	5,100,000	7,000,000
Accounts written off, net of recoveries		(4,600,000)	(5,700,000)	(6,400,000)
Balance at end of year		(1,900,000)	(1,600,000)	(2,200,000)
Inventory, Net [Abstract]
Natural Gas Inventories Not Available For Sale Held by Asset Manager		$ 21,300,000	24,800,000
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Near Term Redemption		180 days
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill, Impairment Loss		$ 0	0	0
Impairment charges	$ 2,000,000	0	0
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total trading securities (cost)					3,700,000		4,300,000
Marketable Securities					4,200,000		4,900,000
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Conditional AROs					14,100,000		19,700,000
Total cost of removal obligations					552,100,000		541,200,000
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of period		19,700,000	14,700,000
Liabilities incurred during the period		5,500,000	4,700,000
Liabilities settled during the period		(6,500,000)	(5,600,000)
Accretion		1,100,000	900,000
Adjustment to estimated cash flows		(5,700,000)	5,000,000
End of period		$ 14,100,000	$ 19,700,000	$ 14,700,000
Regulatory Liabilities [Line Items]
Regulatory liabilities					617,000,000		590,300,000
Debt Amortization Period [Abstract]
Long Term Debt Expense Amortization Period		5 to 30 years
Short Term Debt Expense Amortization Period		5 years
North Carolina Utilities Commission
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation Study Requirement		5 years
Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 years
Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		80 years
Asset Retirement Obligation
Regulatory Liabilities [Line Items]
Regulatory liabilities					538,000,000		521,500,000
Robeson LNG development costs
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Current					100,000		400,000
Robeson LNG development costs | General Rate Application Settlement 2013 | North Carolina Utilities Commission
Public Utilities, General Disclosures [Line Items]
Regulatory Assets								$ 1,200,000
Regulatory Asset, Amortization Period		38 months
Regulatory Noncurrent Asset, End Date for Recovery		Feb. 28, 2017
Land
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant held for future use									$ 3,200,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use									3,200,000
Non-real Estate Costs
Public Utilities, Property, Plant and Equipment, Net [Abstract]
Plant held for future use									3,500,000
Public Utility, Property, Plant and Equipment [Line Items]
Plant held for future use									$ 3,500,000
Asset Retirement Obligation | Minimum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate		4.62%
Asset Retirement Obligation | Maximum
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate		5.89%
Asset Retirement Obligation | Weighted Average
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Fair Value Assumptions, Risk Free Interest Rate		5.69%
South Star Energy Services
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage Sold						15.00%
Money Market Funds
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total trading securities (cost)					500,000		500,000
Marketable Securities					500,000		500,000
Equity Funds
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total trading securities (cost)					3,200,000		3,800,000
Marketable Securities					$ 3,700,000		$ 4,400,000

XML

Acquisition by Duke Energy Corporation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 03, 2016
Class of Stock [Line Items]
Common stock shares outstanding			80,900,000
Public Utilities, General Disclosures [Line Items]
Regulated natural gas revenue	[1]	$ 1,131.6	$ 1,371.7	$ 1,470.0
Business Acquisition, Share Price					$ 60
Financial and legal advisory costs		22.4	8.6
Severance Charges		18.7
Charitable Contributions and Community Support		8.8
Acceleration of incentive plans		5.3
Key employee retention payments		3.5
Other Integration Related Costs		2.9
Acquisition and Integration Related Costs		$ 61.6	$ 8.6
Successor
Class of Stock [Line Items]
Common Stock, Shares, Issued		100
Common stock shares outstanding		100
North Carolina Utilities Commission | Approved Stipulation and Settlement Agreement September 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Annual Charitable Contributions Commitment		$ 17.5
Low-Income Household Energy Assistance and Workforce Development Programs Commitment		7.5
One Time Customer Bill Credit		10.0
Regulated natural gas revenue		$ (4.7)

[1] See Note 11 for amounts attributable to investments in unconsolidated affiliates.

XML

Regulatory Matters - Assets and Liabilities (Details) - USD ($) $ in Millions	Oct. 31, 2016	Oct. 31, 2015
Regulatory Assets [Line Items]
Regulatory Assets, Current	$ 113.7	$ 19.1
Regulatory Assets, Noncurrent	373.3	196.7
Total Regulatory Assets	487.0	215.8
Regulatory Liabilities [Line Items]
Regulatory liabilities, Current	0.0	21.5
Regulatory liabilities, Noncurrent	617.0	590.3
Regulatory Liabilities, Total	617.0	611.8
Other Regulatory Assets On Which We Do Not Earn a Return	344.9
Amounts due to customers
Regulatory Liabilities [Line Items]
Regulatory liabilities, Current	0.0	21.5
Regulatory cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	538.0	521.5
Deferred income taxes
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	78.9	68.7
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Liabilities [Line Items]
Regulatory liabilities, Noncurrent	0.1	0.1
Unamortized debt expense on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets, Current	0.2	0.2
Regulatory Assets, Noncurrent	4.4	4.7
Amounts due from customers
Regulatory Assets [Line Items]
Regulatory Assets, Current	61.9	8.2
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	1.5	1.5
Regulatory Assets, Noncurrent	3.6	5.1
Total Regulatory Assets	5.1
Deferred operations and maintenance expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current	0.9	0.8
Regulatory Assets, Noncurrent	3.1	4.0
Deferred pipeline integrity expenses
Regulatory Assets [Line Items]
Regulatory Assets, Current	3.5	3.5
Regulatory Assets, Noncurrent	32.4	29.8
Deferred pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	2.8	2.8
Regulatory Assets, Noncurrent	16.8	17.9
Amounts not yet recognized as a component of pension and other retirement benefit costs
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	151.6	114.8
Regulatory cost of removal
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	14.1	19.1
Amount Of Regulatory Costs Approved To Be Accrued Not Included In Rate Base	14.1
Robeson LNG development costs
Regulatory Assets [Line Items]
Regulatory Assets, Current	0.1	0.4
Regulatory Assets, Noncurrent	0.0	0.1
Derivatives - gas supply contracts held for utility operations
Regulatory Assets [Line Items]
Regulatory Assets, Current	41.5	0.0
Regulatory Assets, Noncurrent	146.4	0.0
Other
Regulatory Assets [Line Items]
Regulatory Assets, Current	1.3	1.7
Regulatory Assets, Noncurrent	$ 0.9	$ 1.2

XML

Regulatory Matters (Details)	1 Months Ended				12 Months Ended							24 Months Ended
	Nov. 30, 2016 USD ($)	Oct. 31, 2016 USD ($)	Apr. 30, 2015 USD ($)	Apr. 30, 2014 USD ($)	Oct. 31, 2016 USD ($) Integer	Oct. 31, 2015 USD ($)	Oct. 31, 2014 USD ($)	Oct. 31, 2013 USD ($)	Dec. 31, 2001 USD ($)	Dec. 31, 2000 USD ($)	Dec. 31, 1998 USD ($)	Dec. 31, 2001 USD ($)	Dec. 31, 2013 USD ($)	Aug. 31, 2013 USD ($)	Oct. 31, 2008 USD ($)
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets		$ 487,000,000			$ 487,000,000	$ 215,800,000
Regulatory Assets, Current		$ 113,700,000			$ 113,700,000	19,100,000
Percentage Of Net Secondary Market Margins Flowed Through To Customers		75.00%			75.00%
Percentage Of Net Secondary Market Margins Retained		25.00%			25.00%
Allocated to customers as gas cost reductions					$ 52,000,000	60,100,000	$ 72,200,000
Margin allocated to us					17,700,000	21,100,000	25,400,000
Margin from secondary market activity					69,700,000	81,200,000	97,600,000
Percentage Of Net Secondary Market Margin Credited To Customers for Transactions with Duke Energy		100.00%
North Carolina Utilities Commission
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount					$ 1,000,000,000
North Carolina Utilities Commission | Maximum
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales					45.00%
North Carolina Utilities Commission | EasternNC Exclusive Franchise Rights
Public Utilities, Rate Matters, Requested [Abstract]
North Carolina Bond Issuance Amount									$ 149,600,000	$ 38,700,000		$ 188,300,000
Operational Feasibility Assessment Time Period					2 years
North Carolina Utilities Commission | North Carolina Public Staff Audit 2014 Gas Cost Review Period
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs					100.00%
North Carolina Utilities Commission | North Carolina Public Staff Audit 2015 Gas Cost Review Period
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs					100.00%
North Carolina Utilities Commission | North Carolina Public Staff Audit 2016 Gas Cost Review Period | Subsequent Event
Public Utilities, Rate Matters, Approved [Abstract]
Percentage Of Allowed Recovery For Gas Costs	100.00%
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters	In November 2016, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2016. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.
North Carolina Utilities Commission | North Carolina IMR Adjustment 2014
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 800,000
North Carolina Utilities Commission | NCUC Petition for IMR Rate Adjustment Filed December 2014
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 26,600,000
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Transmission Integrity
Public Utilities, Rate Matters, Requested [Abstract]
Recovery Percentage Of System Integrity Expenditures Through IMR					85.00%
Recovery Percentage Of System Integrity Expenditures Through Rate Case					15.00%
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Distribution Integrity
Public Utilities, Rate Matters, Requested [Abstract]
Recovery Percentage Of System Integrity Expenditures Through IMR					90.00%
Recovery Percentage Of System Integrity Expenditures Through Rate Case					10.00%
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Right Of Way Clearing
Public Utilities, Rate Matters, Requested [Abstract]
Recovery Percentage Of System Integrity Expenditures Through IMR					15.00%
Recovery Percentage Of System Integrity Expenditures Through Rate Case					85.00%
North Carolina Utilities Commission | NCUC Public Staff Agreement September 2015 | Work and Asset Management System
Public Utilities, Rate Matters, Requested [Abstract]
Recovery Percentage Of System Integrity Expenditures Through IMR					68.00%
Recovery Percentage Of System Integrity Expenditures Through Rate Case					32.00%
North Carolina Utilities Commission | IMR Petition Filed May 2016
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 7,400,000
North Carolina Utilities Commission | IMR Petition Filed October 2016 | Subsequent Event
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 8,200,000
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Disclosure of Rate Matters	In October 2016, we filed a petition to adjust our rates effective December 1, 2016 to collect an additional $8.2 million in annual IMR margin revenues from that approved by the NCUC in May 2016. The December 2016 rate adjustment was based on IMR-eligible capital investments in integrity and safety projects through September 30, 2016, which total $513.1 million since inception of the IMR mechanism. In November 2016, the NCUC approved the requested rate increase.
North Carolina Utilities Commission | NCUC Open Shelf Registration Statement April 2014
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount				$ 1,000,000,000
North Carolina Utilities Commission | NCUC Approved Customer Bill Credit March 2015 | Amounts due to customers
Public Utilities, Rate Matters, Requested [Abstract]
Increase (Decrease) in Regulatory Liabilities			$ (45,500,000)
North Carolina Utilities Commission | IMR Petition Filed November 2015
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 13,400,000
Public Service Commission of South Carolina
Public Utilities, Rate Matters, Requested [Abstract]
Maximum Utility Rate of Return Change Allowed Under RSA | Integer					50
Public Service Commission of South Carolina | Maximum
Public Utilities, Rate Matters, Requested [Abstract]
Target Percentage Range Normalized Sales					45.00%
Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ (2,900,000)
Public Utilities, Approved Return on Equity, Percentage					10.20%
Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2015
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 1,650,000
Public Utilities, Approved Return on Equity, Percentage					10.20%
Public Service Commission of South Carolina | Settlement With Office Of Regulatory Staff October 2016
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 8,300,000
Public Utilities, Approved Return on Equity, Percentage					10.20%
Tennessee Regulatory Authority
Public Utilities, Rate Matters, Requested [Abstract]
Annual Incentive Cap On Gains And Losses					$ 1,600,000.0
Tennessee Regulatory Authority | Tennessee IMR Petition August 2013
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					13,100,000
Tennessee Regulatory Authority | Tennessee IMR Settlement 2013
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					13,100,000
Tennessee Regulatory Authority | TRA IMR Order February 2015
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					6,500,000
Tennessee Regulatory Authority | TRA IMR Order February 2016 [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					1,700,000
Tennessee Regulatory Authority | TRA Petition Filed IMR November 2016 | Subsequent Event
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 1,700,000
Public Utilities, Disclosure of Rate Matters	In November 2016, we filed a petition with the TRA seeking authority to collect an additional $1.7 million in annual margin revenue effective January 2017 based on $20.1 million of capital investments in integrity and safety projects over the twelve-month period ending October 31, 2016. We are waiting on a ruling from the TRA at this time.
Tennessee Regulatory Authority | TRA Petition to Amortize and Refund Customers for Excess Deferred Taxes
Public Utilities, Rate Matters, Approved [Abstract]
Public Utilities, Approved Rate Increase (Decrease), Amount					(4,700,000)
Public Utilities, Rate Matters, Requested [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					(4,700,000)
Tennessee Regulatory Authority | Tennessee CNG Order October 2015
Public Utilities, Rate Matters, Requested [Abstract]
Deferral CNG Equipment In Utility Rate Base					4,700,000
North Carolina
Public Utilities, Rate Matters, Requested [Abstract]
North Carolina Bond Issuance Amount											$ 200,000,000
Capital Investments in Integrity and Safety Projects I		$ 513,100,000			513,100,000
Tennessee
Public Utilities, Rate Matters, Requested [Abstract]
Capital Investments In Integrity and Safety Projects					20,100,000	18,400,000	54,000,000	$ 100,400,000
Deferred operations and maintenance expenses
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current		900,000			$ 900,000	800,000
Deferred operations and maintenance expenses | North Carolina Utilities Commission
Public Utilities, Rate Matters, Approved [Abstract]
Deferral Time Period Of Operation And Maintenance Expense					8 years
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets		4,000,000			$ 4,000,000	4,800,000
Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Case Proceeding 2008
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					12 years
Interest Accrued On Deferred Expenses					7.84%
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets															$ 9,000,000
Deferred operations and maintenance expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					82 months
Interest Accrued On Deferred Expenses					6.55%
Regulatory Noncurrent Asset, End Date for Recovery					Oct. 31, 2020
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets													$ 6,300,000
Deferred pipeline integrity expenses
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current		3,500,000			$ 3,500,000	3,500,000
Deferred pipeline integrity expenses | North Carolina Utilities Commission
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets		35,900,000			$ 35,900,000	33,300,000
Deferred pipeline integrity expenses | North Carolina Utilities Commission | General Rate Application Settlement 2013
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					5 years
Regulatory Noncurrent Asset, End Date for Recovery					Dec. 31, 2018
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets														$ 17,300,000
Environmental costs
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets		5,100,000			$ 5,100,000
Regulatory Assets, Current		1,500,000			$ 1,500,000	1,500,000
Environmental costs | North Carolina Utilities Commission | General Rate Application Settlement 2013
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					5 years
Regulatory Noncurrent Asset, End Date for Recovery					Dec. 31, 2018
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets													6,300,000
Environmental costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					1 year
Regulatory Current Asset, End Date for Recovery					October 31, 2015
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current							100,000
Robeson LNG development costs
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current		100,000			$ 100,000	400,000
Robeson LNG development costs | North Carolina Utilities Commission | General Rate Application Settlement 2013
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					38 months
Regulatory Noncurrent Asset, End Date for Recovery					Feb. 28, 2017
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets													$ 1,200,000
Robeson LNG development costs | Public Service Commission of South Carolina | Settlement With Office of Regulatory Staff October 2014
Public Utilities, Rate Matters, Approved [Abstract]
Regulatory Asset, Amortization Period					12 months
Regulatory Current Asset, End Date for Recovery					October 31, 2015
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current							$ 500,000
Other
Public Utilities, Rate Matters, Requested [Abstract]
Regulatory Assets, Current		$ 1,300,000			$ 1,300,000	$ 1,700,000

XML

Common Stock (Details) - USD ($)	1 Months Ended		3 Months Ended								12 Months Ended
	Sep. 30, 2016	Oct. 31, 2015	Oct. 31, 2016	Jul. 31, 2016	Apr. 30, 2016	Jan. 31, 2016	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 03, 2016	Jan. 07, 2015
Stockholders' Equity Note [Abstract]
ATM Sales Agreement Amount Instant															$ 170,000,000
ATM Sales Agreement Commission Percentage											1.50%
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Equity in earnings of unconsolidated affiliates											$ (28,600,000)	$ (34,500,000)	$ (32,800,000)
Income tax expense											124,200,000	90,200,000	94,800,000
Net income			$ (38,700,000)	$ 6,700,000	$ (63,400,000)	$ (97,800,000)	$ 14,100,000	$ 8,300,000	$ (66,400,000)	$ (93,000,000)	(193,200,000)	(137,000,000)	(143,800,000)
Forward Contract Indexed to Issuer's Equity [Line Items]
Payments of Stock Issuance Costs	$ 100,000	$ 400,000
Forward Contract Indexed to Issuer's Equity, Shares	1,800,000	1,500,000
Forward Contract Amount Recorded in Consolidated Financial Statements			0								0
Common Stock Issued, Value	$ 104,700,000	$ 54,100,000									$ 138,500,000	$ 85,000,000	75,200,000
Class of Stock [Line Items]
Business Acquisition, Share Price														$ 60
Common stock shares authorized		200,000,000					200,000,000					200,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance						80,900,000					80,900,000
Common Stock, Value, Issued, Beginning Balance						$ 721,400,000				636,800,000	$ 721,400,000	$ 636,800,000	561,600,000
Issued to participants in the Employee Stock Purchase Plan (ESPP)											1,000,000	1,200,000	1,100,000
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)											14,500,000	24,700,000	23,500,000
Issued to participants in the Incentive Compensation Plan (ICP)											18,300,000	5,000,000	3,300,000
Issuance of common stock, net											104,600,000	$ 53,700,000	47,300,000
Common Stock, Shares, Outstanding, Ending Balance		80,900,000					80,900,000					80,900,000
Common Stock, Value, Issued, Ending Balance		$ 721,400,000	859,800,000				$ 721,400,000				859,800,000	$ 721,400,000	636,800,000
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated OCIL beginning balance, net of tax						$ (800,000)				$ (200,000)	(800,000)	(200,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax											(2,800,000)	(1,600,000)
Amounts reclassified, net of tax											3,400,000	1,000,000
Other Comprehensive Income (Loss), net of tax											600,000	(600,000)	0
Accumulated OCIL ending balance, net of tax		$ (800,000)	$ (200,000)				$ (800,000)				$ (200,000)	$ (800,000)	$ (200,000)
Successor
Class of Stock [Line Items]
Common stock shares authorized			100								100
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Ending Balance			100								100
Predecessor
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding, Beginning Balance						80,900,000				78,500,000	80,900,000	78,500,000	76,100,000
Issued to participants in the Employee Stock Purchase Plan (ESPP) (in shares)											0	0	0
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP) (in shares)											300,000	700,000	700,000
Issued to participants in the Incentive Compensation Plan (ICP) (in shares)											300,000	200,000	100,000
Issuance of commons stock shares											1,800,000	1,500,000	1,600,000
Stock Delisted During Period, Shares											(83,300,000)
Common Stock, Shares, Outstanding, Ending Balance		80,900,000	0				80,900,000				0	80,900,000	78,500,000
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Equity in earnings of unconsolidated affiliates											$ 1,400,000	$ 1,700,000
Income tax expense											2,000,000	(700,000)
Net income											$ 3,400,000	$ 1,000,000
FSA Executed March 2015
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		600,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Oct. 31, 2015
Common Stock Issued, Value		$ 21,800,000
Net Settlement Price Per Share		$ 35.50					$ 35.50					$ 35.50
FSA Executed June 2015
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		800,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Oct. 31, 2015
Common Stock Issued, Value		$ 28,200,000
Net Settlement Price Per Share		$ 35.49					35.49					35.49
FSA Executed September 2015
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		100,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Oct. 31, 2015
Common Stock Issued, Value		$ 4,100,000
Net Settlement Price Per Share		$ 36.03					$ 36.03					$ 36.03
FSA Executed January 2016
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares	400,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Sep. 30, 2016
Common Stock Issued, Value	$ 20,200,000
Net Settlement Price Per Share	$ 56.25
FSA Executed March 2016
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares	600,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Sep. 30, 2016
Common Stock Issued, Value	$ 36,200,000
Net Settlement Price Per Share	$ 58.35
FSA Executed June 2016
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares	800,000
Forward Contract Indexed to Issuer's Equity, Settlement Date											Sep. 30, 2016
Common Stock Issued, Value	$ 48,300,000
Net Settlement Price Per Share	$ 58.87

XML

Long Term Debt (Details) - USD ($)				12 Months Ended
	Jul. 28, 2016	Jun. 06, 2016	Sep. 14, 2015	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Debt Instrument [Line Items]
Long-term debt, principal				$ 1,835,000,000	$ 1,575,000,000
Current maturities of long-term debt				35,000,000	40,000,000
Long-Term Debt, Gross less current maturities				1,800,000,000	1,535,000,000
Long-term debt, net excluding current maturities				1,786,000,000	1,523,700,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months				35,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two				0
Long-term Debt, Maturities, Repayments of Principal in Year Three				0
Long-term Debt, Maturities, Repayments of Principal in Year Four				0
Long-term Debt, Maturities, Repayments of Principal in Year Five				160,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five				1,640,000,000
Total Long-term Debt				1,835,000,000	1,575,000,000
Repayments of Long-term Debt				40,000,000	0	$ 100,000,000
Net Earnings Available For Restricted Payments				$ 1,300,000,000
Debt Instrument, Covenant Description				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 $1.0 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. Funded debt cannot exceed 70% of total capitalization. Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. Restrictions on permitted liens; Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and Restrictions on burdensome agreements.
Senior Debt Default Provision, Interest Coverage Ratio				1.75
Interest Coverage Ratio				4.65
Senior Debt Default Provision, Ratio of Indebtedness to Net Capital				0.7
Ratio of Indebtedness to Net Capital				0.55
Senior Debt Default Provision, Funded Debt of Subsidiaries				0.15
Funded Debt Of Subsidiaries				$ 0
Debt Instrument, Change In Control, Prepayment Percentage				100.00%
Debt Instrument, Change In Control, Amount Of Prepayment Options Exercised				$ 0
North Carolina Utilities Commission
Long-term Debt, Fiscal Year Maturity [Abstract]
Public Utilities, Approved Debt Equity Securities Limit, Amount				$ 1,000,000,000
Debt and Equity Shelf Registration, Term				3 years
Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 1,835,000,000	1,575,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(14,000,000)	(11,300,000)
Long-term debt, net including current maturities				1,821,000,000	1,563,700,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 1,835,000,000	1,575,000,000
Senior Notes 2.92%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				2.92%
Debt Instrument, Maturity Date				Jun. 06, 2016
Long-term Debt, Fiscal Year Maturity [Abstract]
Repayments of Long-term Debt		$ 40,000,000
Senior Notes 2.92% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal					40,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net					(100,000)
Long-term debt, net including current maturities					39,900,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt					40,000,000
Senior Notes 8.51%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				8.51%
Debt Instrument, Maturity Date				Sep. 30, 2017
Senior Notes 8.51% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 35,000,000	35,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				0	0
Long-term debt, net including current maturities				35,000,000	35,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 35,000,000	35,000,000
Senior Notes 4.24%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.24%
Debt Instrument, Maturity Date				Jun. 06, 2021
Senior Notes 4.24% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 160,000,000	160,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(600,000)	(800,000)
Long-term debt, net including current maturities				159,400,000	159,200,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 160,000,000	160,000,000
Senior Notes 3.47%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.47%
Debt Instrument, Maturity Date				Jul. 16, 2027
Senior Notes 3.47% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 100,000,000	100,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(600,000)	(600,000)
Long-term debt, net including current maturities				99,400,000	99,400,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 100,000,000	100,000,000
Senior Notes 3.57%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.57%
Debt Instrument, Maturity Date				Jul. 16, 2027
Senior Notes 3.57% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 200,000,000	200,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(1,200,000)	(1,300,000)
Long-term debt, net including current maturities				198,800,000	198,700,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 200,000,000	200,000,000
Senior Notes 4.10%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.10%
Debt Instrument, Maturity Date				Sep. 18, 2034
Senior Notes 4.10% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 250,000,000	250,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(2,500,000)	(2,600,000)
Long-term debt, net including current maturities				247,500,000	247,400,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 250,000,000	250,000,000
Senior Notes 4.65%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.65%
Debt Instrument, Maturity Date				Aug. 01, 2043
Senior Notes 4.65% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 300,000,000	300,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(2,900,000)	(3,000,000)
Long-term debt, net including current maturities				297,100,000	297,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 300,000,000	300,000,000
Senior Notes 3.60%
Debt Instrument [Line Items]
Discount on issuance of notes			$ 100,000
Debt Instrument, Interest Rate, Stated Percentage				3.60%
Debt Instrument, Maturity Date				Sep. 01, 2025
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Issuance Date				Sep. 14, 2015
Debt Instrument, Face Amount			$ 150,000,000
Debt Instrument, Term				10 years
Debt Issuance Discount Percentage			0.065%
Proceeds from Debt, Net of Issuance Costs			$ 148,900,000
Senior Notes 3.60% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 150,000,000	150,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(1,400,000)	(1,400,000)
Long-term debt, net including current maturities				148,600,000	148,600,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 150,000,000	150,000,000
Senior Notes 3.60% | Debt Instrument, Redemption, Period One
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description				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 to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date				Sep. 14, 2015
Debt Instrument, Redemption Period, End Date				May 31, 2025
Debt Instrument, Redemption Price, Percentage				100.00%
Senior Notes 3.60% | Debt Instrument, Redemption, Period One | Base Rate
Debt Instrument, Redemption [Line Items]
Debt Instrument Redemption Interest Rate				0.25%
Senior Notes 3.60% | Debt Instrument, Redemption, Period Two
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description				100% of the principal amount plus any accrued and unpaid interest to the date of redemption
Debt Instrument, Redemption Period, Start Date				Jun. 01, 2025
Debt Instrument, Redemption Period, End Date				Sep. 01, 2025
Debt Instrument, Redemption Price, Percentage				100.00%
Senior Notes 3.64%
Debt Instrument [Line Items]
Discount on issuance of notes	$ 400,000
Debt Instrument, Interest Rate, Stated Percentage				3.64%
Debt Instrument, Maturity Date				Nov. 01, 2046
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument, Issuance Date				Jul. 28, 2016
Debt Instrument, Face Amount	$ 300,000,000
Debt Issuance Discount Percentage	0.122%
Proceeds from Debt, Net of Issuance Costs	$ 297,000,000
Senior Notes 3.64% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 300,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(3,400,000)
Long-term debt, net including current maturities				296,600,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 300,000,000
Senior Notes 3.64% | Debt Instrument, Redemption, Period One
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description				redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and 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 25 basis points and any accrued and unpaid interest to the date of redemption.
Debt Instrument, Redemption Period, Start Date				Jul. 28, 2016
Debt Instrument, Redemption Period, End Date				Apr. 30, 2046
Debt Instrument, Redemption Price, Percentage				100.00%
Debt Instrument Redemption Interest Rate				0.25%
Senior Notes 3.64% | Debt Instrument, Redemption, Period Two
Debt Instrument, Redemption [Line Items]
Debt Instrument, Redemption, Description				100% of the principal amount plus any accrued and unpaid interest to the date of redemption
Debt Instrument, Redemption Period, Start Date				May 01, 2046
Debt Instrument, Redemption Period, End Date				Oct. 31, 2046
Debt Instrument, Redemption Price, Percentage				100.00%
Medium Term Notes 6.87%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.87%
Debt Instrument, Maturity Date				Oct. 06, 2023
Medium Term Notes 6.87% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 45,000,000	45,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(100,000)	(100,000)
Long-term debt, net including current maturities				44,900,000	44,900,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 45,000,000	45,000,000
Medium Term Notes 8.45%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				8.45%
Debt Instrument, Maturity Date				Sep. 19, 2024
Medium Term Notes 8.45% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 40,000,000	40,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(100,000)	(100,000)
Long-term debt, net including current maturities				39,900,000	39,900,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 40,000,000	40,000,000
Medium Term Notes 7.40%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				7.40%
Debt Instrument, Maturity Date				Oct. 03, 2025
Medium Term Notes 7.40% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 55,000,000	55,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(200,000)	(200,000)
Long-term debt, net including current maturities				54,800,000	54,800,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 55,000,000	55,000,000
Medium Term Notes 7.50%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				7.50%
Debt Instrument, Maturity Date				Oct. 09, 2026
Medium Term Notes 7.50% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 40,000,000	40,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(100,000)	(100,000)
Long-term debt, net including current maturities				39,900,000	39,900,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 40,000,000	40,000,000
Medium Term Notes 7.95%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				7.95%
Debt Instrument, Maturity Date				Sep. 14, 2029
Medium Term Notes 7.95% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 60,000,000	60,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(200,000)	(300,000)
Long-term debt, net including current maturities				59,800,000	59,700,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 60,000,000	60,000,000
Medium Term Notes 6.00%
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.00%
Debt Instrument, Maturity Date				Dec. 19, 2033
Medium Term Notes 6.00% | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, principal				$ 100,000,000	100,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				(700,000)	(700,000)
Long-term debt, net including current maturities				99,300,000	99,300,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Total Long-term Debt				$ 100,000,000	$ 100,000,000

XML

Available Credit Facilities (Details)	12 Months Ended
	Oct. 31, 2016 USD ($)	Oct. 31, 2015 USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 850,000,000
Commercial paper	$ 145,000,000	$ 340,000,000
Ratio of Indebtedness to Net Capital	0.55
Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 850,000,000
Line of Credit Facility, Expiration Date	Dec. 14, 2020
Line Of Credit Facility, Optional Additional Expansion Amount	$ 200,000,000
Line of Credit Facility, Frequency of Commitment Fee Payment	annual
Line of Credit Facility, Commitment Fee Description	$35,000 plus 8.5 basis
Line of Credit Facility, Commitment Fee Amount	$ 35,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.085%
Line of Credit Facility, Interest Rate Description	30-day London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points
Minimum Amount Outstanding During Period	$ 0
Maximum Amount Outstanding During Period	$ 0
Line of Credit Facility, Covenant Terms	total debt to total capitalization of no greater than 70%
Line of Credit Facility, Covenant Compliance	actual ratio was 55%
Debt Covenant Total Debt To Total Capital Ratio	70.00%
Ratio of Indebtedness to Net Capital	0.55
Revolving Credit Facility | Minimum | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.75%
Revolving Credit Facility | Maximum | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	1.125%
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 10,000,000	10,000,000
Letters of Credit Outstanding, Amount	1,700,000	$ 1,600,000
Commercial Paper
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 850,000,000
Line of Credit Facility, Interest Rate Description	interest based 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
Maximum Number Of Possible Days Outstanding For Commercial Paper Program	397 days
Short-term Debt, Weighted Average Interest Rate	0.64%	0.22%
Minimum Amount Outstanding During Period	$ 110,000,000
Maximum Amount Outstanding During Period	$ 530,000,000
Commercial Paper | Base Rate
Line of Credit Facility [Line Items]
Debt Instrument Redemption Interest Rate	0.05%
Commercial Paper | Minimum
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	1 day
Line of Credit Facility, Interest Rate During Period	0.20%
Commercial Paper | Maximum
Line of Credit Facility [Line Items]
Number Days Outstanding From Issuance Until Maturity	6 days
Line of Credit Facility, Interest Rate During Period	0.75%
Commercial Paper | Weighted Average
Line of Credit Facility [Line Items]
Line of Credit Facility, Interest Rate During Period	0.55%

XML

Financial Instruments & Related Fair Value (Details) MMBTU in Millions	12 Months Ended
	Oct. 31, 2016 USD ($) MMBTU $ / MMBTU	Oct. 31, 2015 USD ($) MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Options Total Coverage | MMBTU	15.4	34.7
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0	$ 0
Fair Value Measurement Transfers Between Levels Activity	0	0
Derivative Liability		0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		0
Assets [Abstract]
Marketable Securities	4,200,000	4,900,000
Gas supply derivative liabilities, at fair value	$ 41,500,000	0
Percentage Of Annual Gas Purchase Options and All Other Costs Related To Hedging Approved For Recovery Under TIP	1.00%
Long-term debt, principal	$ 1,835,000,000	1,575,000,000
Concentration Risk [Line Items]
Concentration Risk, Benchmark Description	"Receivables" within "Current Assets" on the Consolidated Balance Sheets
Concentration Risk, Customer	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 have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations 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.
Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	$ 5,700,000	6,200,000
Money Market Funds
Assets [Abstract]
Marketable Securities	500,000	500,000
Money Market Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	500,000	500,000
Equity Funds
Assets [Abstract]
Marketable Securities	3,700,000	4,400,000
Equity Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	3,700,000	4,400,000
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	5,700,000	6,200,000
Fair Value, Inputs, Level 1 | Money Market Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	500,000	500,000
Fair Value, Inputs, Level 1 | Equity Funds | Fair Value, Measurements, Recurring
Assets [Abstract]
Marketable Securities	3,700,000	4,400,000
Fair Value, Inputs, Level 2
Assets [Abstract]
Long-term debt, fair value	2,061,200,000	1,720,600,000
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	0	0
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring
Assets [Abstract]
Total Recurring Fair Value Assets	0	0
Price Risk Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0
Assets [Abstract]
Current Assets, Gas purchase derivative assets	1,500,000	1,300,000
Amount of Gain (Loss) Recognized on Derivative Instruments	(5,200,000)	(4,400,000)
Amount Of Gain (Loss) Deferred Under PGA Procedures	(5,200,000)	(4,400,000)
Price Risk Derivative | Fair Value, Measurements, Recurring
Assets [Abstract]
Derivative Asset	1,500,000	1,300,000
Price Risk Derivative | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring
Assets [Abstract]
Derivative Asset	1,500,000	1,300,000
Energy Related Derivative
Assets [Abstract]
Gas supply derivative liabilities, at fair value	41,500,000
Derivative Liability, Noncurrent	146,400,000
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss)	187,900,000
Energy Related Derivative | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	187,900,000
Energy Related Derivative | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0
Energy Related Derivative | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0
Energy Related Derivative | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	187,900,000	$ 0
Assets [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Recorded to Regulatory Assets	187,900,000
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases, Sales, Issues, Settlements	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net	0
Energy Related Derivative | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	$ 187,900,000
Minimum | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU	2.60
Maximum | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Dekatherm | $ / MMBTU	4.47
Accounts Receivable
Concentration Risk [Line Items]
Concentration Risk Amount	$ 14,200,000
Accounts Receivable | Credit Concentration Risk
Concentration Risk [Line Items]
Concentration Risk, Percentage	31.00%

XML

Commitments & Contingencies (Details) $ in Millions	12 Months Ended
	Oct. 31, 2016 USD ($) regulatory_commission sites	Oct. 31, 2015 USD ($)	Oct. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Mar. 01, 2012 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating lease payments	$ 4.8	$ 5.0	$ 4.7
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	4.7
Operating Leases, Future Minimum Payments, Due in Two Years	4.6
Operating Leases, Future Minimum Payments, Due in Three Years	4.4
Operating Leases, Future Minimum Payments, Due in Four Years	4.5
Operating Leases, Future Minimum Payments, Due in Five Years	4.6
Operating Leases, Future Minimum Payments, Due Thereafter	19.8
Operating Leases Future Minimum Payments Due	42.6
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	368.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	246.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	235.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	217.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	211.6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,301.6
Unrecorded Unconditional Purchase Obligation	$ 2,579.9
Number Of Regulatory Commissions | regulatory_commission	3
MGP Sites Under Settlement | sites	9
Site Contingency, Unasserted Claims	0
Site Contingency [Line Items]
Undiscounted Environmental Liability	$ 1.0
Environmental Costs Incurred to Date	0.1
Regulatory Assets [Line Items]
Regulatory Assets	487.0	$ 215.8
Environmental costs
Regulatory Assets [Line Items]
Regulatory Assets	5.1
Pipeline And Storage Capacity Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	170.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	143.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	133.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	115.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	113.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	405.5
Unrecorded Unconditional Purchase Obligation	1,081.8
Gas Supply Reservation Fees
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	2.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation	2.2
Gas Supply Purchase Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	124.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	96.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	96.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	97.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	96.8
Unrecorded Unconditional Purchase Obligation, Due after Five Years	896.1
Unrecorded Unconditional Purchase Obligation	1,408.0
Telecommunications And Technology Outsourcing Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	9.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years	5.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5.2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	4.5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1.1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation	25.8
Others
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	62.1
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0.0
Unrecorded Unconditional Purchase Obligation	$ 62.1
Tennessee Regulatory Authority | Environmental costs | General Rate Application Settlement 2012
Regulatory Assets [Line Items]
Regulatory Assets					$ 2.0
Regulatory Asset, Amortization Period	8 years
North Carolina Utilities Commission | Environmental costs | General Rate Application Settlement 2013
Regulatory Assets [Line Items]
Regulatory Assets				$ 6.3
Regulatory Asset, Amortization Period	5 years
Letter of Credit
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1.7
Surety Bond
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	6.4
Manufactured Gas Plant Sites
Site Contingency [Line Items]
Undiscounted Environmental Liability	0.8
Other Environmental Remediation Sites
Site Contingency [Line Items]
Undiscounted Environmental Liability	$ 0.2

XML

Commitments & Contingencies - Long Term Contracts (Details) - Maximum	12 Months Ended
	Oct. 31, 2016
Pipeline And Storage Capacity Contracts
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	19 years
Gas Supply Reservation Fees
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	2 years
Gas Supply Purchase Commitments
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	15 years
Telecommunications And Technology Outsourcing Contracts
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	5 years

XML

Employee Benefit Plans (Details) - USD ($)	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Deferred Compensation Noncurrent Liability	$ 4,700,000	$ 5,300,000
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Premiums Paid By Employer	100,000	100,000	$ 100,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Noncurrent liabilities	(23,400,000)	(15,100,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Regulatory asset	$ (487,000,000)	(215,800,000)
Defined Benefit Plan Actuarial Gains And Losses Amortization Corridor	5 years
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.80%
Defined Benefit Plans Impact Change Of Discount Rate Methodology	$ (2,400,000)
Gains And Losses Amortized In Excess Of Percentage	10.00%
Money Purchase Pension Plan
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plans Estimated Future Employer Contributions In Next Fiscal Year	$ 2,100,000
Money Purchase Pension Plan | Pension Plan
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%
Employer Contribution Percentage Above IRS Limit	4.00%
Pension Contributions	$ 1,800,000	1,400,000	900,000
Plan Vesting Period Defined Contribution Plan	3 years
Voluntary Deferral Plan | Other Postretirement Benefit Plan
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution to Plan - deferred compensation	$ 0
Defined Contribution Restoration Plan | Other Postretirement Benefit Plan
Defined Contribution Plan Disclosure [Line Items]
Employer Contribution Percentage Above IRS Limit	13.00%
Employer Contribution to Plan - deferred compensation	$ 500,000	500,000
Plan 401 K | Other Postretirement Benefit Plan
Defined Contribution Plan Disclosure [Line Items]
Service Required For Eligibility In Defined Contribution Plan	30 days
Standard Eligibility Age For Defined Contribution Plan	18 years
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	5.00%
Plan Vesting Period Defined Contribution Plan	6 months
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	50.00%
Employee Contribution Rate At Enrollment	2.00%
Contribution Annual Automatic Deferral Increase	1.00%
Employee Contribution Automatic Increase Rate Cap	5.00%
Investment In Company Stock Cap	20.00%
Employer Contribution to Plan	$ 6,900,000	$ 6,600,000	6,100,000
Qualified Pension
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age For Defined Benefit Plan	30 years
Service Required For Eligibility In Defined Benefit Plan	125 days
Years Of Highest Compensation For Benefit Calculation	5 years
Horizon For DBPP Long Term Rates Of Return	20 years
Period Of Compensation For Benefit Calculation	10 years
Plan Vesting Period Defined Benefit Plan	5 years
Maximum Credited Service Period	35 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$ 10,000,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	296,300,000	$ 263,100,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	311,500,000	302,700,000
Service cost	10,600,000	11,400,000	10,900,000
Interest cost	9,500,000	12,000,000	11,700,000
Plan amendments	0	0
Plan settlements	0	0
Actuarial (gain) loss	34,100,000	3,500,000
Participant contributions	0	0
Administrative expenses	(500,000)	(600,000)
Benefit payments	(13,500,000)	(17,500,000)
Obligation at end of year	351,700,000	311,500,000	302,700,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	329,300,000	336,400,000
Actual return on plan assets	17,600,000	1,000,000
Employer contributions	10,000,000	10,000,000
Participant contributions	0	0
Administrative expenses	(500,000)	(600,000)
Plan settlements	0	0
Benefit payments	(13,500,000)	(17,500,000)
Fair value at end of year	342,900,000	329,300,000	336,400,000
Funded status at year end - (under) over	(8,800,000)	17,800,000
Noncurrent assets	0	17,800,000
Current liabilities	0	0
Noncurrent liabilities	(8,800,000)	0
Net amount recognized	(8,800,000)	17,800,000
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	10,700,000	12,800,000
Unrecognized actuarial loss	(153,100,000)	(120,500,000)
Regulatory asset	(142,400,000)	(107,700,000)
Cumulative employer contributions in excess of cost	$ 133,600,000	$ 125,500,000
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.80%	4.34%
Rate Of Compensation Increase	4.05%	4.07%
Net Periodic Benefit Cost [Abstract]
Service cost	$ 10,600,000	$ 11,400,000	10,900,000
Interest cost	9,500,000	12,000,000	11,700,000
Expected return on plan assets	(24,000,000)	(23,600,000)	(22,500,000)
Amortization of prior service cost (credit)	(2,200,000)	(2,200,000)	(2,200,000)
Amortization of net loss	8,000,000	8,700,000	7,700,000
Settlement loss recognized	0	0	0
Net periodic benefit cost	1,900,000	6,300,000	5,600,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	(2,200,000)
Amortization of unrecognized actuarial loss	11,300,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	0	0	0
Net loss (gain)	40,500,000	26,200,000	14,400,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Amortization of net loss	8,000,000	8,700,000	7,700,000
Settlement loss recognized	0	0	0
Amortization of prior service (cost) credit	2,200,000	2,200,000	2,200,000
Total recognized in regulatory asset (liability)	34,700,000	19,700,000	8,900,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 36,600,000	$ 26,000,000	$ 14,500,000
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.34%	4.13%	4.55%
Expected Long Term Rate Of Return On Plan Assets	7.25%	7.50%	7.75%
Rate Of Compensation Increase	4.07%	3.68%	3.72%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 39,600,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	25,200,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	25,000,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	24,800,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	24,900,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	126,800,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	329,300,000	$ 336,400,000
Actual return on plan assets:
Fair value at end of year	$ 342,900,000	$ 329,300,000	$ 336,400,000
Qualified Pension | Minimum
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age For Defined Benefit Plan	21 years
Qualified Pension | Derivative | Maximum
Defined Benefit Plan, Information about Plan Assets [Abstract]
Investment Limitation Percentage	10.00%
Qualified Pension | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	46.00%	46.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 84,100,000
Fair value at end of year	78,900,000	$ 84,100,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	84,100,000
Actual return on plan assets:
Fair value at end of year	$ 78,900,000	$ 84,100,000
Qualified Pension | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	35.00%
Defined Benefit Plan, Actual Plan Asset Allocations	33.00%	34.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 44,700,000
Fair value at end of year	44,400,000	$ 44,700,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	44,700,000
Actual return on plan assets:
Fair value at end of year	$ 44,400,000	$ 44,700,000
Qualified Pension | Real estate
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Qualified Pension | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	0.00%
Defined Benefit Plan, Actual Plan Asset Allocations	2.00%	1.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 2,900,000
Fair value at end of year	5,900,000	$ 2,900,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	2,900,000
Actual return on plan assets:
Fair value at end of year	$ 5,900,000	$ 2,900,000
Qualified Pension | Other investments
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Defined Benefit Plan, Actual Plan Asset Allocations	14.00%	14.00%
Qualified Pension | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 121,800,000
Fair value at end of year	133,200,000	$ 121,800,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	121,800,000
Actual return on plan assets:
Fair value at end of year	133,200,000	121,800,000
Qualified Pension | Common trust fund
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	23,600,000
Fair value at end of year	$ 25,000,000	23,600,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 23,600,000
Actual return on plan assets:
Fair value at end of year	$ 25,000,000	23,600,000
Qualified Pension | Private equity fund of funds
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.50%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 8,300,000
Fair value at end of year	8,900,000	8,300,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Initial Unfunded Subscription Balance	$ 12,000,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Limited
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 2,600,000
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 8,300,000
Actual return on plan assets:
Fair value at end of year	$ 8,900,000	8,300,000
Qualified Pension | Private equity fund of funds | Minimum
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	8 years
Qualified Pension | Private equity fund of funds | Maximum
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	10 years
Qualified Pension | Hedge fund of funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 19,800,000
Fair value at end of year	$ 20,000,000	19,800,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Quarterly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	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, 2016.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 19,800,000
Actual return on plan assets:
Fair value at end of year	20,000,000	19,800,000
Qualified Pension | Commodities fund of funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	7,700,000
Fair value at end of year	$ 9,200,000	7,700,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	35 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Monthly
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	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.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 7,700,000
Actual return on plan assets:
Fair value at end of year	9,200,000	7,700,000
Qualified Pension | High yield debt (bank loans)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	16,400,000
Fair value at end of year	$ 17,400,000	16,400,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Frequency	Daily
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Redemption Restriction, Description	None
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	$ 16,400,000
Actual return on plan assets:
Fair value at end of year	17,400,000	16,400,000
Qualified Pension | Fair Value, Inputs, Level 1
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	126,400,000
Fair value at end of year	127,700,000	126,400,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	126,400,000
Actual return on plan assets:
Fair value at end of year	127,700,000	126,400,000
Qualified Pension | Fair Value, Inputs, Level 1 | Fixed income securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 1 | Equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	44,700,000
Fair value at end of year	44,400,000	44,700,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	44,700,000
Actual return on plan assets:
Fair value at end of year	44,400,000	44,700,000
Qualified Pension | Fair Value, Inputs, Level 1 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	2,800,000
Fair value at end of year	5,100,000	2,800,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	2,800,000
Actual return on plan assets:
Fair value at end of year	5,100,000	2,800,000
Qualified Pension | Fair Value, Inputs, Level 1 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	78,900,000
Fair value at end of year	78,200,000	78,900,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	78,900,000
Actual return on plan assets:
Fair value at end of year	78,200,000	78,900,000
Qualified Pension | Fair Value, Inputs, Level 1 | Common trust fund
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 1 | Private equity fund of funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	150,700,000
Fair value at end of year	159,700,000	150,700,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	150,700,000
Actual return on plan assets:
Fair value at end of year	159,700,000	150,700,000
Qualified Pension | Fair Value, Inputs, Level 2 | Fixed income securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	84,100,000
Fair value at end of year	78,900,000	84,100,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	84,100,000
Actual return on plan assets:
Fair value at end of year	78,900,000	84,100,000
Qualified Pension | Fair Value, Inputs, Level 2 | Equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 2 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	100,000
Fair value at end of year	800,000	100,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	100,000
Actual return on plan assets:
Fair value at end of year	800,000	100,000
Qualified Pension | Fair Value, Inputs, Level 2 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	42,900,000
Fair value at end of year	55,000,000	42,900,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	42,900,000
Actual return on plan assets:
Fair value at end of year	55,000,000	42,900,000
Qualified Pension | Fair Value, Inputs, Level 2 | Common trust fund
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	23,600,000
Fair value at end of year	25,000,000	23,600,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	23,600,000
Actual return on plan assets:
Fair value at end of year	25,000,000	23,600,000
Qualified Pension | Fair Value, Inputs, Level 2 | Private equity fund of funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	8,300,000
Fair value at end of year	8,900,000	8,300,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	8,300,000
Actual return on plan assets:
Fair value at end of year	8,900,000	8,300,000
Qualified Pension | Fair Value, Inputs, Level 3 | Fixed income securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Common trust fund
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Qualified Pension | Fair Value, Inputs, Level 3 | Private equity fund of funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	8,300,000	7,200,000
Fair value at end of year	8,900,000	8,300,000	7,200,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	8,300,000	7,200,000
Actual return on plan assets:
Relating to assets still held at the reporting date	100,000	400,000
Relating to assets sold during the period	500,000	600,000
Purchases, sales and settlements (net)	0	100,000
Transfer in/out of Level 3	0	0
Fair value at end of year	8,900,000	8,300,000	7,200,000
Non Qualified Pension
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	500,000
Reconciliation Of Changes In Plan Benefit Obligations And Fair Value Of Assets [Abstract]
Accumulated Benefit Obligation At Year End	4,600,000	5,500,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	5,500,000	5,900,000
Service cost	0	0	0
Interest cost	200,000	200,000	200,000
Plan amendments	0	0
Plan settlements	(900,000)	0
Actuarial (gain) loss	300,000	(100,000)
Participant contributions	0	0
Administrative expenses	0	0
Benefit payments	(500,000)	(500,000)
Obligation at end of year	4,600,000	5,500,000	5,900,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	1,400,000	500,000
Participant contributions	0	0
Administrative expenses	0	0
Plan settlements	(900,000)	0
Benefit payments	(500,000)	(500,000)
Fair value at end of year	0	0	0
Funded status at year end - (under) over	(4,600,000)	(5,500,000)
Noncurrent assets	0	0
Current liabilities	(500,000)	(500,000)
Noncurrent liabilities	(4,100,000)	(5,000,000)
Net amount recognized	(4,600,000)	(5,500,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	0	(200,000)
Unrecognized actuarial loss	(1,500,000)	(1,600,000)
Regulatory asset	(1,500,000)	(1,800,000)
Cumulative employer contributions in excess of cost	$ (3,100,000)	$ (3,700,000)
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.80%	3.85%
Net Periodic Benefit Cost [Abstract]
Service cost	$ 0	$ 0	0
Interest cost	200,000	200,000	200,000
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	200,000	200,000	200,000
Amortization of net loss	0	100,000	100,000
Settlement loss recognized	300,000	0	0
Net periodic benefit cost	700,000	500,000	500,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	0
Amortization of unrecognized actuarial loss	100,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	0	0	500,000
Net loss (gain)	300,000	(100,000)	1,000,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Amortization of net loss	0	100,000	100,000
Settlement loss recognized	300,000	0	0
Amortization of prior service (cost) credit	(200,000)	(200,000)	(200,000)
Total recognized in regulatory asset (liability)	(200,000)	(400,000)	1,200,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 500,000	$ 100,000	$ 1,700,000
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	3.85%	3.69%	3.98%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 500,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	500,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	500,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	400,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	400,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	1,700,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0	$ 0
Actual return on plan assets:
Fair value at end of year	$ 0	$ 0	$ 0
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	55 years
Standard Eligibility Age for Defined Benefit Plan Post Amendment	50 years
Age Of Exclusion For Defined Benefit Plan	65 years
Years After Qualifying Age	10 years
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Benefits Provided After Employee Is Eligible for Medicare Benefits	$ 0
Term Life Insurance Per Individual Benefit Provided By Employer	15,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	2,200,000
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Obligation at beginning of year	37,600,000	$ 37,800,000
Service cost	1,200,000	1,200,000	1,100,000
Interest cost	1,300,000	1,500,000	1,500,000
Plan amendments	0	(1,900,000)
Plan settlements	0	0
Actuarial (gain) loss	1,600,000	1,700,000
Participant contributions	100,000	600,000
Administrative expenses	0	0
Benefit payments	(2,500,000)	(3,300,000)
Obligation at end of year	39,300,000	37,600,000	37,800,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,500,000	27,700,000
Actual return on plan assets	1,100,000	300,000
Employer contributions	2,600,000	2,200,000
Participant contributions	100,000	600,000
Administrative expenses	0	0
Plan settlements	0	0
Benefit payments	(2,500,000)	(3,300,000)
Fair value at end of year	28,800,000	27,500,000	27,700,000
Funded status at year end - (under) over	(10,500,000)	(10,100,000)
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(10,500,000)	(10,100,000)
Net amount recognized	(10,500,000)	(10,100,000)
Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred Regulatory Account
Unrecognized prior service (cost) credit	1,500,000	1,900,000
Unrecognized actuarial loss	(9,100,000)	(7,200,000)
Regulatory asset	(7,600,000)	(5,300,000)
Cumulative employer contributions in excess of cost	$ (2,900,000)	$ (4,800,000)
Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate	3.80%	4.38%
Net Periodic Benefit Cost [Abstract]
Service cost	$ 1,200,000	$ 1,200,000	1,100,000
Interest cost	1,300,000	1,500,000	1,500,000
Expected return on plan assets	(1,800,000)	(1,800,000)	(1,800,000)
Amortization of prior service cost (credit)	(300,000)	0	0
Amortization of net loss	400,000	0	0
Settlement loss recognized	0	0	0
Net periodic benefit cost	800,000	900,000	800,000
Estimated Amortization And Expected Refunds [Abstract]
Amortization of unrecognized prior service cost (credit)	(300,000)
Amortization of unrecognized actuarial loss	700,000
Other Changes In Plan Assets And Benefit Obligatin Recognized Through Regulatory Asset Or Liability [Abstract]
Prior service cost (credit)	0	(1,900,000)	0
Net loss (gain)	2,400,000	3,200,000	3,600,000
Amounts Recognized As Component Of Net Periodic Benefit Cost [Abstract]
Amortization of net loss	400,000	0	0
Settlement loss recognized	0	0	0
Amortization of prior service (cost) credit	300,000	0	0
Total recognized in regulatory asset (liability)	2,300,000	1,300,000	3,600,000
Total Recognized In Net Periodic Benefit Cost And Regulatory Asset (Liability)	$ 3,100,000	$ 2,200,000	$ 4,400,000
Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate	4.38%	4.03%	4.44%
Expected Long Term Rate Of Return On Plan Assets	7.25%	7.50%	7.75%
Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 1,900,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Two	2,100,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Three	2,200,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	2,400,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Five	2,400,000
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter	13,100,000
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect Of One Percentage Point Increase on Postretirement Benefit Obligation	0	$ 0
Effect of One Percentage Point Decrease on Postretirement Benefit Obligation	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,500,000	27,700,000
Actual return on plan assets:
Fair value at end of year	$ 28,800,000	$ 27,500,000	$ 27,700,000
Other Postretirement Benefit Plan | Minimum
Defined Benefit Plan Disclosure [Line Items]
Standard Eligibility Age for Defined Benefit Plan Pre Amendment	45 years
Other Postretirement Benefit Plan | Fixed income securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Defined Benefit Plan, Actual Plan Asset Allocations	47.00%	47.00%
Other Postretirement Benefit Plan | Equity securities
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	47.00%
Defined Benefit Plan, Actual Plan Asset Allocations	44.00%	44.00%
Other Postretirement Benefit Plan | Real estate
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Defined Benefit Plan, Actual Plan Asset Allocations	5.00%	5.00%
Other Postretirement Benefit Plan | Cash and cash equivalents
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Defined Benefit Plan, Actual Plan Asset Allocations	4.00%	4.00%
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 1,100,000
Fair value at end of year	1,200,000	$ 1,100,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	1,100,000
Actual return on plan assets:
Fair value at end of year	$ 1,200,000	1,100,000
Other Postretirement Benefit Plan | High yield fixed income
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations	5.00%
Other Postretirement Benefit Plan | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	$ 26,400,000
Fair value at end of year	27,600,000	26,400,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	26,400,000
Actual return on plan assets:
Fair value at end of year	27,600,000	26,400,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	27,500,000
Fair value at end of year	28,800,000	27,500,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	27,500,000
Actual return on plan assets:
Fair value at end of year	28,800,000	27,500,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	1,100,000
Fair value at end of year	1,200,000	1,100,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	1,100,000
Actual return on plan assets:
Fair value at end of year	1,200,000	1,100,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 1 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	26,400,000
Fair value at end of year	27,600,000	26,400,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	26,400,000
Actual return on plan assets:
Fair value at end of year	27,600,000	26,400,000
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 2 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Cash and cash equivalents
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	0
Other Postretirement Benefit Plan | Fair Value, Inputs, Level 3 | Mutual funds
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value at beginning of year	0
Fair value at end of year	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value at beginning of year	0
Actual return on plan assets:
Fair value at end of year	0	$ 0
Supplemental Executive Retirement Plans
Defined Benefit Plan, Information about Plan Assets [Abstract]
Assets for Participant Benefits	0
Officers and Director-Level Employees Life Insurance
Defined Benefit Plan, Information about Plan Assets [Abstract]
Term Life Insurance Per Individual Benefit Provided By Employer	$ 200,000

XML

Employee Share Based Plans (Details) $ / shares in Units, $ in Millions				1 Months Ended	11 Months Ended	12 Months Ended
	Oct. 03, 2016 USD ($) $ / shares	Dec. 15, 2015 shares	Dec. 15, 2014 shares	Dec. 31, 2011 shares	Oct. 02, 2016	Oct. 31, 2016 USD ($) Integer	Oct. 31, 2015 USD ($)	Oct. 31, 2014 USD ($)	Dec. 14, 2015 $ / shares	Dec. 12, 2014 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Performance Periods Under ICP Plans						3 years
Business Acquisition, Share Price | $ / shares	$ 60
Share Price | $ / shares									$ 56.85	$ 37.89
Stock Issued During Period, Value, Share-based Compensation, Gross						$ 18.3	$ 5.0	$ 3.3
Maximum Statutory Withholdings Allowed						50.00%
Compensation expense						$ 16.1	14.2	8.5
Tax Benefit						6.1	4.0	$ 2.5
Liability						0.0	$ 22.0
Purchase Price of Common Stock, Percent					95.00%
Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense related to acceleration of incentive plans						$ 5.3
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Incentive Compensation Plan Awards | Integer						3
Long Term Incentive Plan | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Acceleration And Payout Election Rate		96.00%
Stock Issued During Period, Shares, Restricted Stock Award | shares		162,390
Stock Issued During Period, Value, Share-based Compensation, Gross	$ 0.3
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested Shares Granted in Period | shares				64,700
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Restricted Stock Award | shares			7,231
Vesting % of restricted stock unit						20.00%
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Restricted Stock Award | shares		11,732
Vesting % of restricted stock unit						30.00%
Retention Stock Unit Award President And Chief Executive Officer | Restricted Stock Unit Award | Share-based Compensation Award, Tranche Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Restricted Stock Award | shares		19,554
Vesting % of restricted stock unit						50.00%
Duke Energy Restricted Stock Unit Award [Member] | Restricted Stock Unit Award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Percentage						100.00%
Accounts Payable, Related Parties, Current						$ 6.1

XML

Income Taxes Income Tax Expense Components (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Income Tax Table Continuing Operations [Line Items]
Current Federal Tax Expense (Benefit)		$ 27.2	$ (0.7)	$ 2.5
Current State Tax Expense (Benefit)		11.8	1.1	1.8
Deferred Federal Income Tax Expense (Benefit)		79.6	77.9	76.5
Deferred State Income Tax Expense (Benefit)		5.8	12.1	14.2
Amortization of investment tax credits		(0.2)	(0.2)	(0.2)
Federal Total		106.6	77.0	78.8
State Total		17.6	13.2	16.0
Current Income Tax Expense (Benefit)	$ 40.4
Deferred Income Tax Expense (Benefit)	(8.7)
Taxes accrued	68.4	68.4	30.3
Income Tax Examination, Interest Income		0.5
Duke Energy
Income Tax Table Continuing Operations [Line Items]
Taxes accrued	$ 31.5	31.5
Domestic Tax Authority | NOL Carryforward 1
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)		$ 91.4	64.3
Domestic Tax Authority | Net Operating Loss Utilization
Income Tax Table Continuing Operations [Line Items]
Deferred Federal Income Tax Expense (Benefit)			$ 19.8	$ 28.6

XML

Income Taxes Operating Loss Carryforwards (Details) - USD ($)	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Operating Loss Carryforwards [Line Items]
Unrecognized Tax Benefits	$ 0
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	0	$ 300,000	$ 0
Operating Loss Carryforwards	$ 175,400,000
Operating Loss Carryforwards, Limitations on Use	Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of $159.6 million are subject to an effective annual limitation of $31.8 million.
Capital Loss Carryforward
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 300,000
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2017
Charitable Carryforward
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 3,200,000
Charitable Carryforward | Minimum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2016
Charitable Carryforward | Maximum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2019
Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Net Operating Loss, Retroactive Impact	$ 46,800,000	$ 61,100,000
Domestic Tax Authority | Carryforward Limitation 1
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Annual Amount Subject To Limitation	31,800,000
Domestic Tax Authority | Federal NOL
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	163,500,000
Domestic Tax Authority | Federal NOL | Carryforward Limitation 1
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 159,600,000
Domestic Tax Authority | Federal NOL | Minimum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2020
Domestic Tax Authority | Federal NOL | Maximum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2036
State and Local Jurisdiction | State NOL
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 8,400,000
State and Local Jurisdiction | State NOL | Minimum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2027
State and Local Jurisdiction | State NOL | Maximum
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2036

XML

Income Taxes (Details) - USD ($)	12 Months Ended
	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Federal taxes at 35%	$ 111,100,000	$ 79,500,000	$ 83,500,000
State income taxes, net of federal benefit	11,400,000	8,600,000	10,400,000
Amortization of investment tax credits	(200,000)	(200,000)	(200,000)
Other, net	1,900,000	2,300,000	1,100,000
Total	$ 124,200,000	$ 90,200,000	$ 94,800,000
Effective Income Tax Rate Reconciliation, Percent	39.10%	39.70%	39.70%
Deferred tax assets:
Benefit of tax carryforwards				$ 175,400,000	$ 84,000,000
Revenues and cost of natural gas				0	3,500,000
Employee benefits and compensation				28,600,000	22,100,000
Revenue requirement				30,100,000	26,100,000
Property, plant and equipment				5,300,000	7,500,000
Deferred Tax Assets, Derivative Instruments				70,600,000	0
Other				13,800,000	10,500,000
Total deferred tax assets				323,800,000	153,700,000
Valuation allowance	$ (800,000)	$ (500,000)	$ (500,000)	(800,000)	(800,000)	$ (500,000)
Total deferred tax assets, net				323,000,000	152,900,000
Deferred tax liabilities:
Utility Plant				1,010,800,000	849,800,000
Revenues and cost of natural gas				20,000,000	0
Equity Method Investments				34,800,000	44,800,000
Deferred costs				85,000,000	73,900,000
Deferred Tax Liabilities, Derivatives				70,600,000	0
Other				5,900,000	13,600,000
Total deferred tax liabilities				1,227,100,000	982,100,000
Net Deferred Income Tax Liabilities				904,100,000	829,200,000
Valuation Allowance [Abstract]
Balance at beginning of year	800,000	500,000	500,000
Charged to income tax expense	0	300,000	0
Balance at end of year	800,000	800,000	500,000
Unrecognized Tax Benefits				0
NC Tax Law [Line Items]
State and Local Income Tax Expense (Benefit)	17,600,000	13,200,000	$ 16,000,000
Regulatory liabilities, Noncurrent				617,000,000	590,300,000
Regulatory liabilities, Total				617,000,000	611,800,000
Deferred income taxes
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent				$ 78,900,000	68,700,000
North Carolina | State and Local Jurisdiction
NC Tax Law [Line Items]
Increase (Decrease) in Deferred Income Taxes	15,700,000	17,500,000
State and Local Income Tax Expense (Benefit)	$ 600,000	$ 500,000
North Carolina | State and Local Jurisdiction | Earliest Tax Year
NC Tax Law [Line Items]
Statutory Tax Rate				6.90%
North Carolina | State and Local Jurisdiction | Tax Year 2014
NC Tax Law [Line Items]
Statutory Tax Rate				6.00%
North Carolina | State and Local Jurisdiction | Tax Year 2015
NC Tax Law [Line Items]
Statutory Tax Rate				5.00%
North Carolina | State and Local Jurisdiction | Short Tax Year 2016
NC Tax Law [Line Items]
Statutory Tax Rate				4.00%
North Carolina | State and Local Jurisdiction | Latest Tax Year
NC Tax Law [Line Items]
Statutory Tax Rate				3.00%
North Carolina | Deferred income taxes | State and Local Jurisdiction
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent				$ 15,100,000	$ 17,000,000
North Carolina | Corporate Tax Legislation | State and Local Jurisdiction
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent						$ 3,000,000
North Carolina | Corporate Tax Legislation | Deferred income taxes | State and Local Jurisdiction
NC Tax Law [Line Items]
Regulatory liabilities, Noncurrent				$ 58,600,000

XML

Investments in Unconsolidated Affiliates (Details) - USD ($)			12 Months Ended
		Oct. 03, 2016	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 02, 2016
Schedule of Equity Method Investments [Line Items]
Retained Earnings, Undistributed Earnings from Equity Method Investees			$ 0
Investments in equity method unconsolidated affiliates			199,200,000	$ 207,000,000
Equity in earnings of unconsolidated affiliates			28,600,000	34,500,000	$ 32,800,000
Accounts payable to affiliated companies	[1],[2]		8,700,000	2,500,000
Receivables from affiliated companies	[1],[2]		7,000,000	200,000
Net proceeds from the sales of interests in unconsolidated affiliates and other assets			174,500,000	700,000	1,900,000
Gain on Sale of Investments			80,900,000	0	0
Equity Method Investee [Member]
Schedule of Equity Method Investments [Line Items]
Related party expenses			28,700,000	29,500,000	29,700,000
Accounts payable to affiliated companies			$ 2,400,000	2,500,000
Cardinal Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			21.49%
Investments in equity method unconsolidated affiliates			$ 14,200,000	15,100,000
Equity in earnings of unconsolidated affiliates			$ 1,500,000	$ 1,700,000	$ 1,700,000
Pipeline Subscription Capacity Percentage			100.00%
Pipeline Transportation Capacity Subscribed			53.00%
Summarized Financial Information Percentage			100.00%	100.00%	100.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			$ 10,300,000	$ 9,500,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			101,500,000	106,400,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			46,000,000	1,200,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			300,000	45,400,000
Equity Method Investment, Summarized Financial Information, Revenue			16,600,000	16,600,000	$ 16,700,000
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			16,600,000	16,600,000	16,700,000
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			7,700,000	7,700,000	8,000,000
Cardinal Pipeline Company | Equity Method Investee [Member]
Schedule of Equity Method Investments [Line Items]
Related party expenses			8,700,000	8,800,000	8,800,000
Accounts payable to affiliated companies			$ 700,000	700,000
Pine Needle Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			45.00%
Investments in equity method unconsolidated affiliates			$ 16,600,000	18,400,000
Equity in earnings of unconsolidated affiliates			$ 2,800,000	$ 2,700,000	$ 2,700,000
Pipeline Subscription Capacity Percentage			100.00%
Summarized Financial Information Percentage			100.00%	100.00%	100.00%
Storage Capacity Subscribed			64.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			$ 7,700,000	$ 9,900,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			68,100,000	71,600,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			3,000,000	5,400,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			35,200,000	35,100,000
Equity Method Investment, Summarized Financial Information, Revenue			17,100,000	16,900,000	$ 18,000,000
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			15,400,000	15,300,000	15,300,000
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			6,800,000	6,000,000	6,000,000
Pine Needle Company | Equity Method Investee [Member]
Schedule of Equity Method Investments [Line Items]
Related party expenses			10,700,000	11,400,000	11,400,000
Accounts payable to affiliated companies			$ 900,000	1,000,000
South Star Energy Services
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			0.00%			15.00%
Equity Method Investment, Ownership Percentage Sold		15.00%
Investments in equity method unconsolidated affiliates			$ 0	41,300,000
Equity in earnings of unconsolidated affiliates			$ 18,800,000	$ 19,400,000	$ 20,400,000
Summarized Financial Information Percentage			100.00%	100.00%	100.00%
Net proceeds from the sales of interests in unconsolidated affiliates and other assets		$ 160,000,000
Gain on Sale of Investments		$ 80,900,000
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			$ 212,200,000	$ 204,200,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			126,800,000	132,300,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			47,100,000	46,000,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			0	0
Equity Method Investment, Summarized Financial Information, Revenue			638,300,000	769,300,000	$ 845,700,000
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			216,400,000	244,600,000	234,600,000
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			125,500,000	129,300,000	136,600,000
South Star Energy Services | Equity Method Investee [Member]
Schedule of Equity Method Investments [Line Items]
Operating revenues			300,000	1,600,000	3,500,000
Receivables from affiliated companies			$ 0	200,000
Hardy Storage
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Investments in equity method unconsolidated affiliates			$ 42,100,000	39,700,000
Equity in earnings of unconsolidated affiliates			$ 5,100,000	$ 5,200,000	$ 5,300,000
Summarized Financial Information Percentage			100.00%	100.00%	100.00%
Storage Capacity Subscription Percentage			100.00%
Storage Capacity Subscribed			40.00%
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			$ 6,600,000	$ 11,700,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			151,800,000	156,800,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			14,400,000	19,100,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			59,100,000	70,000,000
Equity Method Investment, Summarized Financial Information, Revenue			23,500,000	23,400,000	$ 23,800,000
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			23,500,000	23,400,000	23,800,000
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			11,000,000	10,400,000	10,500,000
Hardy Storage | Equity Method Investee [Member]
Schedule of Equity Method Investments [Line Items]
Related party expenses			9,300,000	9,300,000	9,500,000
Accounts payable to affiliated companies			$ 800,000	800,000
Constitution Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			24.00%
Investments in equity method unconsolidated affiliates			$ 93,100,000	82,400,000
Equity in earnings of unconsolidated affiliates			$ (1,300,000)	$ 6,100,000	$ 2,700,000
Pipeline Subscription Capacity Percentage			100.00%
Summarized Financial Information Percentage			100.00%	100.00%	100.00%
Estimated Pipeline Development And Construction Costs			$ 955,000,000
Estimated Contributions For Pipeline And Construction Costs			229,300,000
Capital contributions to or payments to acquire equity method investments			12,100,000
Total Contributions To Equity Method Investments For Project			$ 84,800,000
Target Pipeline In Service Date			2018
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			$ 6,600,000	$ 6,200,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			380,900,000	330,200,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			1,200,000	4,400,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			0	0
Equity Method Investment, Summarized Financial Information, Revenue			0	0	$ 0
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			0	0	0
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			(3,400,000)	24,600,000	10,100,000
Equity Method Investment, Other than Temporary Impairment			$ 0
Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			7.00%			10.00%
Equity Method Investment, Ownership Percentage Sold		3.00%
Investments in equity method unconsolidated affiliates			$ 33,200,000	10,100,000
Equity in earnings of unconsolidated affiliates			$ 1,700,000	$ (600,000)	$ 0
Summarized Financial Information Percentage			100.00%	100.00%
Net proceeds from the sales of interests in unconsolidated affiliates and other assets		$ 13,900,000
Capital contributions to or payments to acquire equity method investments			$ 35,300,000
Total Contributions To Equity Method Investments For Project			$ 46,000,000
Target Pipeline In Service Date			2019
Long-term Purchase Commitment, Period			20 years
Estimated Percentage Project Financing			60.00%
Estimated Percentage Debt Financing			50.00%
Estimated Percentage Equity Financing			50.00%
Maximum Funding Obligation Under Equity Contribution Agreements			$ 10,600,000
Equity Method Investment, Summarized Financial Information [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets			134,300,000	$ 23,400,000
Equity Method Investment, Summarized Financial Information, Noncurrent Assets			376,300,000	86,100,000
Equity Method Investment, Summarized Financial Information, Current Liabilities			47,900,000	9,100,000
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities			0	0
Equity Method Investment, Summarized Financial Information, Revenue			0	0
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)			0	0
Equity Method Investment, Summarized Financial Information, Net Income (Loss)			17,300,000	$ (5,200,000)
Atlantic Coast Pipeline | Minimum
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs			4,500,000,000
Atlantic Coast Pipeline | Maximum
Schedule of Equity Method Investments [Line Items]
Estimated Pipeline Development And Construction Costs			$ 5,000,000,000

[1] See Note 11 for amounts attributable to investments in unconsolidated affiliates.

[2] See Note 14 for details on related party transactions with Duke Energy.

XML

Business Segments (Details) $ in Millions	3 Months Ended								12 Months Ended
	Oct. 31, 2016 USD ($)	Jul. 31, 2016 USD ($)	Apr. 30, 2016 USD ($)	Jan. 31, 2016 USD ($)	Oct. 31, 2015 USD ($)	Jul. 31, 2015 USD ($)	Apr. 30, 2015 USD ($)	Jan. 31, 2015 USD ($)	Oct. 31, 2016 USD ($) segment		Oct. 31, 2015 USD ($)	Oct. 31, 2014 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment									1
Segment Reporting, Disclosure of Major Customers									0
Segment Reporting Information [Abstract]
Total Assets	$ 5,691.0				$ 5,086.3				$ 5,691.0		$ 5,086.3	$ 4,719.8
Noncurrent Asset Additions									569.2		473.4	498.1
Segment Reporting Information, Profit (Loss) [Abstract]
Unaffiliated revenues									1,141.7
Revenue from Duke Energy									7.0	[1]
Total operating revenues	171.9	$ 160.4	$ 352.9	$ 463.5	184.1	$ 162.2	$ 427.3	$ 609.5	1,148.7		1,383.1	1,479.5
Interest Expense									68.6		68.6	54.7
Depreciation and amortization									137.3		128.7	119.0
Equity in earnings of unconsolidated affiliates									28.6		34.5	32.8
Gain on sale of unconsolidated affiliates									132.8		0.0	0.0
Income tax expense									124.2		90.2	94.8
Net income	38.7	$ (6.7)	$ 63.4	$ 97.8	(14.1)	$ (8.3)	$ 66.4	$ 93.0	193.2		137.0	143.8
Retail Natural Gas
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues									1,066.3		1,237.4	1,300.5
Wholesale Natural Gas
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues									72.3		134.3	169.5
Other Revenues
Segment Reporting Information, Profit (Loss) [Abstract]
Total operating revenues									10.1		11.4	9.5
Gas Utilities and Infrastructure
Segment Reporting Information [Abstract]
Total Assets	5,691.0				5,045.0				5,691.0		5,045.0	4,678.8
Noncurrent Asset Additions									569.2		473.4	498.1
Segment Reporting Information, Profit (Loss) [Abstract]
Unaffiliated revenues									1,141.7
Revenue from Duke Energy									7.0
Total operating revenues									1,148.7		1,383.1	1,479.5
Interest Expense									68.6		68.6	54.7
Depreciation and amortization									137.3		128.7	119.0
Equity in earnings of unconsolidated affiliates									9.8		15.1	12.3
Gain on sale of unconsolidated affiliates									0.0
Income tax expense									85.2		85.9	87.0
Net income									143.3		131.1	131.2
Other Segments
Segment Reporting Information [Abstract]
Total Assets	$ 0.0				$ 41.3				0.0		41.3	41.0
Noncurrent Asset Additions									0.0		0.0	0.0
Segment Reporting Information, Profit (Loss) [Abstract]
Unaffiliated revenues									0.0
Revenue from Duke Energy									0.0
Total operating revenues									0.0		0.0	0.0
Interest Expense									0.0		0.0	0.0
Depreciation and amortization									0.0		0.0	0.0
Equity in earnings of unconsolidated affiliates									18.8		19.4	20.5
Gain on sale of unconsolidated affiliates									132.8
Income tax expense									39.0		4.3	7.8
Net income									$ 49.9		$ 5.9	$ 12.6

[1] See Note 14 for details on related party transactions with Duke Energy.

XML

Related Party Transactions with Duke Energy (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Oct. 31, 2016	Jul. 31, 2016	Apr. 30, 2016	Jan. 31, 2016	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014
Related Party Transaction [Line Items]
Revenue, Net		$ 171.9	$ 160.4	$ 352.9	$ 463.5	$ 184.1	$ 162.2	$ 427.3	$ 609.5	$ 1,148.7	$ 1,383.1	$ 1,479.5
Accounts payable to affiliated companies	[1],[2]	8.7				$ 2.5				8.7	2.5
Duke Energy
Related Party Transaction [Line Items]
Revenue, Net										80.8	$ 83.2	$ 86.2
Related party expenses										0.2
Duke Energy | Duke Energy RSU Award
Related Party Transaction [Line Items]
Accounts payable to affiliated companies		$ 6.1								$ 6.1

[1] See Note 11 for amounts attributable to investments in unconsolidated affiliates.

[2] See Note 14 for details on related party transactions with Duke Energy.

XML

Severance (Details) - Severance $ in Millions	12 Months Ended
	Oct. 31, 2016 USD ($)
Restructuring Cost and Reserve [Line Items]
Severance Charges	$ 18.7
Severance Liability	$ 18.7

XML

Reclassification of Financial Statements - Adoption of New Accounting Guidance (Details) $ in Millions	Oct. 31, 2015 USD ($)
Accounting Standards Update 2015-17 [Member] | Scenario, Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Tax Assets, Net, Current	$ 32.4

XML

Reclassifications of Consolidated Financial Statements - Duke Acquisition (Details) - Scenario, Previously Reported - USD ($) $ in Millions	12 Months Ended
	Oct. 31, 2015	Oct. 31, 2014
Operating Income Tax Expense Benefit	$ 76.9	$ 83.2
Non Operating Income Tax Expense Benefit	$ 13.3	$ 11.6

XML

Quarterly Financial Data (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Oct. 31, 2016	Jul. 31, 2016	Apr. 30, 2016	Jan. 31, 2016	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Jan. 31, 2015	Oct. 31, 2016	Oct. 31, 2015	Oct. 31, 2014	Oct. 03, 2016
Quarterly Financial Data [Abstract]
Operating Revenues	$ 171.9	$ 160.4	$ 352.9	$ 463.5	$ 184.1	$ 162.2	$ 427.3	$ 609.5	$ 1,148.7	$ 1,383.1	$ 1,479.5
Operating Income (Loss)	(50.3)	0.5	103.9	171.3	(8.8)	(1.7)	111.1	162.2	225.4	262.8	263.1
Net income (loss)	$ 38.7	$ (6.7)	$ 63.4	$ 97.8	$ (14.1)	$ (8.3)	$ 66.4	$ 93.0	$ 193.2	$ 137.0	$ 143.8
South Star Energy Services
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage Sold												15.00%