UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

    For the fiscal year ended October 31, 20122013

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 number1-6196

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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

    Indicate by check mark if the registrant is not required to file reports pursuant to sectionSection 13 or 15 (d) of the Act. Yes¨ Nox

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. Yesx No¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website,Web site, if any, every Interactive Data fileFile 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). Yesx 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.¨x

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes¨ Nox

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2012.2013.

Common Stock, no par value - $2,166,959,354$2,575,772,202

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 6, 20132014 are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

20122013 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

PART I

Item 1. Business

Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina. 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 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service from resource centers in Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.

We have two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.businesses. The percentage of assets as of October 31, 20122013 and earnings before taxes by segment for the year ended October 31, 20122013 are presented below.

Operations of both segments are conducted within the United States of America. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements.statements in this Form 10-K.

Operating revenues shown in the Consolidated Statements of Comprehensive Income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in prudently incurred purchased gas costs from suppliers are passed through to customers through purchased gas adjustment (PGA) procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For the year ended October 31, 2012, 48% of our operating revenues were from residential customers, 27% from commercial customers, 12% from large volume customers, including industrial, power generation and resale customers, 12% from secondary market activities and 1% from other sources. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our utilityregulatory gas supply management program with regulator-approved sharing mechanisms between our utility customers and our shareholders. Operations of the non-utility activities segment are included in the Consolidated Statements of Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

Operating revenues by major customer class for the years ended October 31, 2013 and 2012 are presented below.

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 and equity securities.

We are also subject to various federal regulations that affect our 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, and 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. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December 20122013 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. From time to time, some of our franchise agreements expire; however, we continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Depending on the jurisdiction, we believe that these franchises will be

renewed or that service will be continued in the ordinary course of business while we negotiate renewals or continue to operate under our state-granted franchise rights without thea specific franchise agreementsagreement with each city or municipality. The likelihood of cessation of service under an expired franchise is remote, and we do not believe there will be a material adverse impact on us.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to recover the cost of natural gas we purchased for our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through integrity management riders (IMRs) or similar mechanisms and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. Alternative rate structures and cost recovery mechanisms are rate designs and mechanisms that allow utilities to recover certain costs through tracking mechanisms or riders without the need to file general base rate cases. They can also recognize the impact of energy efficiency and conservation on a utility’s revenue stream and thus separate or decouple the link between energy consumption and margin revenues, thereby aligning the interests of shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of 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. The approval of our settlement with the Public Staff of the 2013 NCUC rate proceeding includes implementation of an IMR in North Carolina that will separately track and recover the costs associated with capital expenditures to comply with federal pipeline safety and integrity requirements. Under this mechanism, we will make annual filings every November to capture costs closed to plant through October with revised rates effective the following February. A similar mechanism in Tennessee was approved by the TRA in December 2013. In South Carolina, we operate under a rate stabilization adjustment (RSA) tariff mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset our rates in South Carolina based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism for residential and commercial customers in South Carolina for bills rendered during the months of November through March and in Tennessee for bills rendered during the months of October through April that partially offsets the impact of colder- or warmer-than-normal winter weather. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increase revenues when weather is warmer than normal and decrease revenues when weather is colder than normal. 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 and when weather is significantly warmer than normal or colder than normal. Weather in 2013 on average over our three-state market area was 2% colder than normal and 25% colder than 2012. For the year ended October 31, 2013, the margin decoupling mechanism in North Carolina increased margin by $6 million, and the WNA mechanisms in South Carolina and Tennessee together increased margin by $3 million.

In all three 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. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve increasing levels of margin stabilization. The following table presents the breakdown of our gas utility margin for the years ended October 31, 2013, 2012 and 2011. For further information, see Note 2 to the consolidated financial statements in this Form 10-K.

The natural gas distribution business is seasonal in nature as variations in weather conditions and our regulated utility rate designs generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. As

Our Strategies

We monitor our progress and measure our performance related to our strategic directives and business objectives over the course of our fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, employee satisfaction, operations and maintenance (O&M) expense discipline, employee health and safety, pipeline safety, and sustainable business practices.

Safety is prevalenta critical component to our ongoing success as a company. We have always placed a high priority on the safety of our system, public safety and employee safety. We must comply with laws that regulate system integrity as well as new rulemaking proceedings under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital and O&M expenditure programs. Items currently being discussed by federal regulators include possible mandates addressing the integrity verification process of maximum allowable operating pressure of transmission pipelines. Potential regulatory changes resulting from the rulemaking could increase our future capital and O&M expenditures for pipeline integrity, safety and compliance. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

We believe natural gas is a safe and reliable energy source that is clean, affordable, reliable and environmentally responsible. It is also domestically abundant. We incorporate this message into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them.

Our business model supports new clean energy technologies and energy efficiencies in the industry, we injectend use of natural gas into

storage duringgas. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2012, the amountdirect use of natural gas in storage varied from 17 million dekatherms (one dekatherm equals 1,000,000 BTUs)more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security. We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We continued to 26.2 million dekatherms,execute our plan in 2013 to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party fleets and other customers.

With the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we have participated in the development of gas-fired power generation facilities in our market area. We completed pipeline expansion projects over the last three fiscal years to provide long-term natural gas delivery service to new power generation facilities in our market area. In addition to delivering the natural gas supply to the new natural gas-fired power plants, the construction of natural gas pipelines for two of these projects increased our natural gas infrastructure in the eastern part of North Carolina and has enhanced future opportunities for economic growth and development.

Our capital program primarily supports our system infrastructure and the aggregate commodity costgrowth in our customer base. We are increasing our spending for pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. For further information on our forecasted capital investments for fiscal 2014 – 2016, see “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength which includes a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and innovative rate designs for the benefit of our customers and shareholders.

We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects based on projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, specifically annual approved budgets, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.

To further our strategy of expanding our complementary energy-related businesses, in November 2012, we became a 24% equity member of Constitution Pipeline Company, LLC, a Delaware limited liability company. The purpose of the joint venture is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in storage varied from $70.6 millionSusquehanna County, Pennsylvania, to $125the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest of 24% for the development and construction of the new pipeline, which is expected to cost approximately $680 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.

Operating Statistics

The following is a five-year comparison of operating statistics for the years ended October 31, 20082009 through 2012.2013.

During the year ended October 31, 2012,2013, we delivered 324.3387.6 million dekatherms to our utility retail customers compared to 279.8324.3 million dekatherms the year before. Of this amount, 246.7292.7 million dekatherms of gas were sold to or transported for large volume customers compared with 181.2246.7 million dekatherms in 2011.2012. Of these volumes sold to or transported for large volume

customers, we transported 151.7190.9 million dekatherms this yearin 2013 to power generation facilities compared with 83.5151.7 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 94.9 million dekatherms in 2013, compared with 77.6 million dekatherms in 2012, compared with 98.5 million dekatherms in 2011.2012. Weather, as measured by degree days, was 2% colder than normal in 2013 and 19% warmer than normal in 2012.

With continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas in our service areas, we have made gains in utility customer growth. For the year ended October 31, 2013 and 2012, and 10% colder than normalwe added the following new customers.

* Includes a large, multi-unit conversion project.

We forecast continuing gross customer growth in 2011.fiscal 2014 of approximately 1.5%.

Natural Gas Utility Operations

We purchase natural gas under firm contracts to meet our design-day requirements for firm sales customers. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the peak day, seasonal and annual needs of our firm customers by using a variety of firm transportation and storage capacity contracts. The pipeline capacity contracts require the payment of fixed monthly demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement these firm contracts with other supply arrangements to serve our interruptible market.

As of October 31, 2012,2013, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.

Williams-Transco			632,200
Kinder Morgan -TennesseeEl Paso-Tennessee Pipeline			74,100
Spectra-Texas Eastern (through(partially through East Tennessee and Transco)			36,700
Oneok-Midwestern (through either Tennessee, Columbia Gulf, East Tennessee or Transco)			120,000
NiSource-Columbia Gas (through Transco and Columbia Gulf)			42,800
NiSource-Columbia Gulf			10,000
ONEOK-Midwestern (through Tennessee, Columbia Gulf, East Tennessee and Transco)			120,00015,000
Total			915,800    920,800

As of October 31, 2012,2013, we had the following assets or contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets with deliverability from 5 days to one year.

As of October 31, 2012,2013, we own or have under contract 36.135.5 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capabilitycapacity is used to supplement or replace regular pipeline supplies.

WeAs is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2013, the amount of natural gas in storage varied from 10.9 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 25.1 million dekatherms, and the weighted average commodity cost of this gas in storage varied from $43.6 million to $95.5 million.

Natural gas development and production in North America continues to provide abundant supply and price stability and moderation for natural gas as an energy commodity. With lower gas prices over the past six years, we have historically sourcedbeen able to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas component of customer rates in the three jurisdictions that we distribute primarily fromserve. Currently, natural gas has a price advantage over many other fuels, and it is anticipated that the Gulf Coast production region. cost of natural gas will remain competitive due to abundant sources of shale gas reserves.

We purchase theseour natural gas supplies by contracting primarily with major and independent producers and marketers. We also purchase a diverse portfolio of transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed due to market demand fluctuations, we may release these services in the secondary market under FERC-approved capacity release provisions, with proceeds received being used to reduce the cost of natural gas we charge to customers through the sharing mechanism that is available in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans. Peak-use requirements are met through the use of company owned storage facilities, pipeline transportation capacity, purchased storage services and other supply sources. We have been able to obtain sufficient supplies of natural gas to meet customer requirements, and with the prospect of abundant domestic shale natural gas supplies and our contracted pipeline capacity, we believe that we will be able to meet our market demands in the future.

To diversify our reliance away from the Gulf Coast region, we receiveWhen firm long-term market area storage service from Hardy Storage Company, LLC (Hardy Storage) located in West Virginia, Columbia Gas Storage located in West Virginia, Ohio and Pennsylvania, and Dominion Storage located in West Virginia, Pennsylvania and New York that may be filled with Appalachian sourced supply. We also contract for firm, long-term transportation service from Midwestern Gas Transmission Company that provides access topipeline services or contracted gas supplies are temporarily not needed due to market demand fluctuations, we may release these services and supplies in the secondary market under FERC-approved capacity release provisions or make wholesale secondary market sales. The proceeds from Canadian and Rocky Mountain supply basins and the Chicago hub that can supply city gate demand or bethose transactions are used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.reduce the cost of natural gas we charge to customers through sharing mechanisms that are in place in all three jurisdictions whereby customers are allocated 75% of the savings through the incentive plans.

In November 2012, we executedcontinued to diversify our supply diversification strategyportfolio by contracting to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm capacity contract with Williams-Transco forWilliams – Transco under its Leidy Southeast expansion project to transport thosethe Marcellus based Cabot gas supplies to our markets. In December 2012, we also signed a long-term firm capacity contract with Williams – Transco under its Virginia Southside expansion project that will also allow us to further diversify our supply portfolio with Marcellus based natural gas. These new supply arrangements are scheduled to begin in Decemberlate 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

We completed pipeline expansion projectsCompetition

The regulated utility competes with other energy products, such as electricity and propane, in December 2011the residential and June 2012 to provide long-termcommercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas delivery service to two power generation customersincluding price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under construction in North Carolina with a targeted in service date of June 2013. In addition to delivering the natural gas supply to achieve the environmental benefits of replacing coal-fired power plants with new natural gas-fired power plants, the constructionprice of natural gas pipelines for two of these projects increasescan negatively impact our natural gas infrastructure incompetitive position by decreasing the eastern part of North Carolina and enhances future opportunities for economic growth and development. See the following discussion of our forecasted capital investment related to the construction of the natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

With some improvement in economic conditions and targeted marketing programs on theprice benefits of natural gas in our service areas, we have made gains in utility customer growth. The composition of our new customers forto the year ended October 31, 2012 is presented below.

We forecast continuing grossconsumer. This can lead to slower customer growth for fiscal 2013 of approximately 1%.

Our business model supports new clean energy technologiesor customer conservation, or both, resulting in reduced gas purchases and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovationcustomer billings. In turn, this can impact our capital expenditures and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting theoverall cash needs, including working capital needs. The direct use of natural gas in more homes and businesses industriesis the most efficient and vehicles as we strongly believe that the expandedcost effective use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce bothand results in overall energy consumption and greenhouse gas emissions and enhance our national energy security. We see an opportunity inlower carbon emissions. However, the clean energy technologyuse of compressed natural gas (CNG) vehicles. We are executingfor power generation also adds significant value as a plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently ownresult of natural gas’ environmental attributes, competitive cost advantage and operate eight company CNG fueling stations at Company resource centers with 14%efficiency of our vehicle fleet capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 38,000 dekatherms of CNG to commercial customers for the year ended October 31, 2012, which is equivalent to approximately 579 homes, and used 4,880 dekatherms of CNG in our own fleets. Through sales of CNG to commercial customers and use by our own fleet, this CNG usage displaced more than 344,000 gallons of gasoline and diesel fuel.

To further our strategy of expanding our complementary energy-related businesses, in November 2012, we entered into an agreement to become a 24% equity member of Constitution Pipeline Company, LLC with two other members. The purpose of the joint venture is to construct and operate an interstate natural gas pipeline and related facilities connecting gathering systems in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost between $700 – $800 million. For further information on this equity method investment, see Note 12 to the consolidated financial statements in this Form 10-K.delivery.

During the year ended October 31, 2012,2013, approximately 5%4% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price and alternative fuels.prices. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the USU.S. dollar versus other currencies. Our margin could be impacted, either positively or negatively, as a result of changes in oil and natural gas prices and the alternate fuel decisions made by industrial customers.

Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2012,2013, no bypass occurred. The future level of bypass activity cannot be predicted.

The regulated utility alsoNatural gas for power generation competes with other energy products, suchfuel sources for the generation of electricity, including coal, nuclear and renewable resources. Additionally, as electricity and propane, inwith industrial customers, we compete with other pipeline providers to serve the residential and small commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. The direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and results in overall lower carbon emissions.generation plants.

Other

During the year ended October 31, 2012,2013, our largest revenue generating customer contributed $59.2$75.4 million, or 5%6%, of total operating revenues. Our largest margin generating customer contributed $27.5$53.1 million, or 5%9% of total margin. Our largest revenue and margin generating customer is the same customer.

Our costs for research and development are not material and are primarily limited to natural gas industry-sponsored research projects.

Compliance with federal, state and local environmental protection laws have had no material effect on our construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 ofin this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Costs incurred for natural gas, labor, employee benefits, consulting and construction are the business charges that we incur that are most significantly impacted by inflation. Changes to the cost of gas are generally recovered through regulatory mechanisms and do not significantly impact

net income. Labor and employee benefits are components of the cost of service, and construction costs less utility deferred income taxes are the primary componentcomponents of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities in North Carolina and Tennessee, when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. See discussion above for information on IMRs to track and recover costs in North Carolina and Tennessee outside of a general rate case. In South Carolina, we operate under a rate stabilization mechanism that reduces theregulatory lag to one year. This regulatoryyear, but we reserve the right to file general rate cases when necessary. Regulatory lag can impact earnings.

As of October 31, 2012,2013, our fiscal year end, we had 1,7521,795 employees compared with 1,7821,752 as of October 31, 2011.2012.

Our reports on Form 10-K, Form 10-Q and Form 8-K, and any amendments to these reports, are available at no cost on our website atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission (SEC).Commission.

Item 1A. Risk Factors

An overall economic downturn could negatively impact our earnings.

WeakeningAny 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.

TheA supply and demand balanceimbalance 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 CommoditiesCommodity 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 customers’customer bills. Customers may have trouble paying those higher bills which may lead to bad debt expenses, ultimately reducing our earnings.

The availability of adequate interstate pipeline transportation capacity and natural gas supply may decrease.

We purchase all of our gas supply from interstate sources that must then be transported to our service territory. Interstate pipeline companies transport the gas to our system under firm service agreements that are designed to meet the requirements of our core markets. A significant disruption to or reduction in that supply or interstate pipeline capacity due to events including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist or cyber-attacks or other acts of war, or legislative or regulatory actions or requirements, including remediation related to integrity inspections, could reduce our normal interstate supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling rigs and platforms, processing and gathering systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that meets demand, then our growth opportunities would be limited and our earnings negatively impacted.

Regulatory actions at the state level could impact our ability to earn a reasonable rate of return on our invested capital and to fully recover our operating costs as well as reduce our earnings.

Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. IfOur 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, byor significantly loweringlowers our allowed return or negatively alteringalters our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, or prohibits recovery of regulatory assets, including deferred gas costs, or other tariff provisions, then our earnings could be negatively impacted.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. The foregoingAll 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. Regulatory authorities also review whetherState regulators have approved various mechanisms to stabilize our gas costs are prudentutility margin, including margin decoupling in North Carolina, rate stabilization in South Carolina, and can adjust the amount of ouruncollectible gas costs that we pass through to our customers. Additionally, our statecost recovery in all states. State regulators foster a competitive regulatory modelhave approved other margin stabilizing mechanisms that, for example, allowsallow 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 there are changes in the regulatory compact that alter our abilityregulators decided to compete fordiscontinue allowing us to use these customers, then we could lose customers or incur significant unrecoverable expenses or margin losses to retain them. The occurrence of any of the foregoing couldtariff 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 and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.

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

The natural gas business is competitive, and we face competition 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.

Our business activities are concentrated in three states.

Approximately 97% of our assets and 88% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers, including customers served by three North Carolina municipalities who are our wholesale customers, and most of our utility transmission and distribution pipelines 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 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. Furthermore, becauseBecause 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 million per day for each violation. In addition, asAs the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of the abovethese 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. 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 the foregoingthese events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.

Weather conditions may cause our earnings to vary from year to year.

Our earnings can vary from year to year, depending in part on weather conditions. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms and rate design that normalize the margin we collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. If our rates and tariffs are modified to eliminate weather protection provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather. Additionally, our weather normalization mechanisms provide reduceddo not ensure full protection, especially for significantly warmer-than-normal winter weather. As a result of the foregoing,these events, our results of operations and earnings could vary and be negatively impacted.

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.

Inherent in our gas distribution and transmission activities, including natural gas and LNG storage, 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 or cyber-attacks, 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 the foregoingthese 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 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.

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 recover these costs either through general rate cases or alternative rate mechanisms approved by state regulatory commissions, such as RSAs and 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, the counterparty to one of our power generation construction agreements may elect to terminate the agreement priorafter these capital costs are reflected in rates, to the in-service date for the project,extent that rates rise considerably, customers may choose alternative forms of energy to meet their needs. This would reduce our customer growth, which would negatively affect futureweaken our financial position by reducing earnings and cash flows.flow.

A downgrade in our 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. Such a downgrade 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 commercial paper (CP) program, as well as on any future public or private debt issuances, would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.

We may be unable to access capital or the cost of capital may significantly increase.

Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets or waning investor sentiment could adversely affect our ability to access short-term and long-term capital. Our access to funds under short-term credit facilitiesour CP program is dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding

commitments if they experience shortages of capital and liquidity.investor demand for our commercial paper. Disruptions and volatility in the global credit markets could causelimit the demand for our commercial paper or result in the need to offer higher interest rate we pay on our short-term credit facility,rates to investors, which is based on the London Interbank Offered Rate, to increase, couldwould result in higher interest rates on future financings,expense and could adversely impact the liquidity of the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. Disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to capital needed for our business.liquidity. Tax rates on dividends may increase, which could increase the cost of equity. The inability to access adequate capital or the increase in cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.

Changes in federal andand/or state fiscal, tax and monetary policy could significantly increase our costs or decrease our cash flows.

Changes in federal andand/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. This series ofThese events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flows. 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 or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.

We do not generate sufficient cash flows to meet all our cash needs.

Historically, weWe have made, and expect to continue to make, large capital expenditures in order to finance the expansion, upgrading and maintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our 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, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under the indenture or other loan agreements. Accordingly, should an event of default occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obliged in such instance to satisfy all of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to implement our business plan, make capital expenditures and finance our operations.

We are exposed to credit risk of counterparties with whom we do business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom we do business could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations. We depend on these counterparties to remit payments to fulfill their contractual obligations on a timely basis. Any delay or default in payment or failure of the counterparties to meet their contractual obligations could adversely affect our financial position, results of operations or cash flows.

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.

We may invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by our regulated utility segment. 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. All the foregoingabove could adversely affect our

earnings from or return of our investment in these businesses. We could make future equity method investments or acquisitions of regulated or unregulated businesses that have the similar potential to adversely affect our earnings from or return of our investment in those businesses. All these adverse impacts could negatively affect our results of operations or financial condition.

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 skilled workforce, our ability to provide safe quality service to our customers and meet our regulatory requirements will be challenged, and this could negatively impact our earnings.

Changes in accounting standards may adversely impact our financial condition and results of operations.

The SEC is considering whether issuers in the United States should be required to prepare financial statements in accordance with International Financial Reporting Standards (IFRS) instead of the current generally accepted accounting principles in the United States (GAAP). IFRS is a comprehensive set of accounting standards promulgated by the International Accounting Standards Board (IASB), which are currently in effect for most other countries in the world. Unlike U.S. GAAP, IFRS does not currently provide an industry accounting standard for rate-regulated activities. As such, if IFRS were adopted in its current state, we may be precluded from applying certain regulatory accounting principles, including the recognition of certain regulatory assets and regulatory liabilities. The potential issues associated with rate-regulated accounting, along with other potential changes associated with the adoption of IFRS, may adversely impact our reported financial condition and results of operations should adoption of IFRS be required. Also, the U.S. Financial Accounting Standards Board is considering various changes to U.S. GAAP, some of which may be significant, as part of a joint effort with the IASB to converge accounting standards over the next several years. If approved, adoption of these changes may adversely impact our reported financial condition and results of operations.

Cyber-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, 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. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.

Disruption or failure of business operations and information technology systems could shut down our facilities or otherwise adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems, serve our customers effectively or manage our assets. An attack on or failure of information technology systems could result in the unauthorized release of customer, employee or other confidential or sensitive data. The foregoingThese events could adversely affect our business reputation, diminish customer confidence, disrupt operations, subject us to financial liability or increased regulation, increase our costs and expose us to material legal claims and liability, and our operations and financial results could be adversely affected.

Our insurance coverage may not be sufficient.

We currently have general liability and property insurance in place in amounts that we consider appropriate based on our business risk and best practices in our industry and in general business. Such policies are subject to certain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage coveringfor 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

All property included in the Consolidated Balance Sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,8002,900 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 22,000 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. 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.

None of our property is encumbered, and all property is in use except for “Plant held for future use” as classified in the Consolidated Balance Sheets. The amount classified as plant held for future use relates to expenditures associated with a potential LNG peak storage facilityis comprised of land located in the eastern part ofRobeson County, North Carolina. There is no current need to proceed with theFor further information on this Robeson LNG peak

storage facility dueCounty property, see Note 1 and Note 2 to the expansion capacity, cost effectiveness, timing and design scope of another construction project that will enhance our ability to serve our North Carolina customersconsolidated financial statements in this area. The future use of this property is dependent upon annual updates to our ongoing five-year plan for forecasted growth requirements.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 $3.7$4.2 million for the year ended October 31, 2012.2013.

Property included in the Consolidated Balance Sheets in “Other Physical Property” is owned by the parent company and one of its subsidiaries. The property owned by the parent company primarily consists of natural gas water heaters leased to commercial customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.

Item 3. Legal Proceedings

We have only immaterial litigation or routine immaterial litigation in the normal course of business.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Market Information

Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 20122013 and 2011.2012.

Holders

As of December 14, 2012,13, 2013, our common stock was owned by 13,39213,749 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in street name or in the name of an investment company.

Dividends

The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 20122013 and 2011.2012. We expect that comparable cash dividends will continue to be paid in the future.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2012,2013, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Share Repurchases

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2012.2013.

Discussion of our compensation plans, under which shares of our common stock are authorized for issuance, is included in the portion of our proxy statement captioned “Executive Compensation” to be filed no later than January 31, 2013,2014, in connection with our Annual Meeting to be held on March 6, 2013,2014, and is incorporated herein by reference.

Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares our cumulative total shareholder return from October 31, 20072008 through October 31, 20122013 (a five-year period) with the average performance of our industry peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500 Index). Our LDC Peer Group index is comprised of peer group companies that are domiciled in the United States, publicly traded havein the U.S. energy industry with a primary focus on natural gas distribution and transmission businesses in multi-state territories and have similar annual revenues and market capitalization to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our cumulativerelative total shareholder return asreturns, which we use for market benchmarking for our executive compensation plans when the end of the three-year performance period of a share-based plan award aligns with the current year of our report.

NICOR, Inc. and AGL Resources Inc. were included in our peer group for our fiscal year 2011. In 2012, NICOR, Inc. was merged into AGL Resources Inc.plans.

The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 20072008 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

Comparisons of Five-Year Cumulative Total Returns

Comparisons of Five-Year Cumulative Total Returns Value of $100 Invested as of October 31, 2008 Value of $100 Invested as of October 31, 2007

LDC Peer Group—The following companies are included: AGL Resources Inc., Atmos Energy Corporation, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc.

LDC Peer Group—The following companies are included: AGL Resources Inc., Atmos Energy Corporation, New Jersey Resources Corporation, NiSource Inc., Northwest Natural Gas Company, South Jersey Industries, Inc., Southwest Gas Corporation, The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc.

This graph represents the relative value of an investment in Common Stock made on a particular day, October 31, 2008. On that particular day, Piedmont’s common stock closed at $32.92, within 99% of a new all-time high price of $33.24 reached on September 19, 2008, having surged in price during the U.S. and world financial crisis that occurred in the late summer and fall of 2008. During that time, the S&P 500 dropped dramatically, and most of our LDC Peer Group stock prices declined as well, with lower closing stock values on October 31, 2008 compared to Piedmont. By early February 2009, the price of Piedmont’s stock declined to pre-August 2008 levels and did not close above $27 until late December 2009. Piedmont’s ten- and twenty-year cumulative total returns (from October 31, 2003 and October 31, 1993) are 153% and 527%, respectively, versus 105% and 454% for the S&P 500 and 160% and 436% for the LDC Peer Group.

Item 6. Selected Financial Data

The following table provides selected financial data for the years ended October 31, 20082009 through 2012.

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

Forward-Looking Statements

This report, as well as other documents 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, as well as those discussed in Item 1A. Risk Factors:

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 atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, 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 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and regulated intrastate natural gas transportation. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.transportation businesses.

We haveoperate with two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority 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 and equity securities. Factors critical to the success of the regulated utility include operating a safe and reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.

Executive Summary

A summary of our annual results is as follows:

Comprehensive Income Statement Components

Gas Deliveries, Customers, Weather Statistics and Number of Employees

RegulationFinancial Performance – Fiscal 2013 Compared with Fiscal 2012

We closed the fiscal year with a 12% increase in net income. Margin increased 8% primarily due to increased transportation services from new contracts for power generation customers and higher volumes delivered to residential, commercial and industrial customers due to colder weather and customer growth. Operations and maintenance (O&M) expenses and depreciation expense increased 4% and 9%, respectively. The increase in O&M expenses was related to higher costs for contract labor related to process improvement and pipeline integrity programs, payroll from short-term incentive plans, bad debt expense and regulatory amortizations, partially offset by a decrease in employee benefits costs. Depreciation was higher due to increases in plant in service from our capital expansion programs for customer growth, power generation, pipeline delivery projects and system integrity and infrastructure investments. Other Income (Expense) increased 7% with an increase in income from equity method investments, including additional markets served by one of our investments and a new pipeline venture investment on November 1, 2012, partially offset by the cumulative amortization of non-real estate costs related to the allowed deferral of a regulatory asset for certain non-real estate costs included in the 2013 settlement agreement as approved by the NCUC in December 2013. Utility interest charges increased 24% due to increases in long-term debt, partially offset by an increase in capitalized interest income and lower balances of short-term debt used from our commercial paper (CP) program at lower interest rates.

Business Summary – Fiscal 2013 Compared with Fiscal 2012

Our utility operations are regulated byfiscal 2013 performance reflects our continued execution of our long-term business strategy. As discussed above, financial performance was solid for the North Carolina Utilities Commission (NCUC), the Public Service Commissionyear with increased earnings and an increase in our dividend rate per share to our investors.

Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we executed our financing programs to optimize and reduce our cost of South Carolinacapital, preserve our liquidity and the Tennessee Regulatory Authority (TRA) asstrong balance sheet and protect our high quality credit ratings with a goal of maintaining a long-term debt to rates, service area, adequacy of service, safety standards, extensionscapital ratio between 45% and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as50%. To meet our short-term liquidity needs, we continue to the issuance ofrely on our CP program.

We issued long-term debt and equity securities.during fiscal 2013 for total proceeds of $389.8 million. In February 2013, we issued 3 million shares of our common stock and entered into forward sale agreements (FSAs) related to the future issuance of up to an additional 1.6 million shares. Early in fiscal 2014, we issued 1.6 million shares on December 16, 2013 under the FSAs, receiving proceeds of $47.3 million. In August 2013, we issued $300 million of 30-year, unsecured senior notes. In November 2013, we entered into an agreement with our revolving credit facility lenders to increase our borrowing capacity to $850 million. For further information on these transactions, see Note 4, Note 5 and Note 6 to the consolidated financial statements in this Form 10-K and the following discussion of “Cash Flows from Financing Activities.”

We are also subjectManaging Gas Supplies and Prices – Our gas supply acquisition strategy is regularly reviewed and adjusted to various federal regulationsensure that affectwe have adequate and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. In November 2012, in order to provide additional diversification, reliability and non-utility operations.gas cost benefits to our customers, we signed long-term contracts to source more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These federal regulations include regulations thatnew capacity and supply arrangements are particularscheduled to thebegin in late 2015.