10-K 1 pny-20161031x10xk.htm 10-K Document


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
ý ANNUAL 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
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
 
 
 
Part II.
 
 
 
 
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder
  Matters and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results
  of Operations
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial
  Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
 
 
 
Part III.
 
 
 
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related
  Stockholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
 
 
 
Part IV.
 
 
 
 
 
Item 15.
Exhibits, Financial Statement Schedules
 
 
 
 
Signatures




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.

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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.


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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.


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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.


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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.


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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

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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,

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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.

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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.

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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.


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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