Form 10-K

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

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 x

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 such shorter period that the registrant was required to submit and post such files). Yes x 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. ¨

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 ¨ No x

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2011.

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

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 8, 2012 are incorporated by reference into Part III.

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.

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 51,800 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 storage and intrastate natural gas transportation.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service to Anderson, Gaffney, 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. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated segment include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. For the year ended October 31, 2011, 87% of our earnings before taxes came from our regulated utility segment. 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. For the year ended October 31, 2011, 13% of our earnings before taxes came from our non-utility segment, which consists of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. 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.

Operating revenues shown in the consolidated statements of 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 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, 2011, 46% of our operating revenues were from residential customers, 27% from commercial customers, 10% from large volume customers, including industrial, power generation and resale customers, and 17% from secondary market activities. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our utility 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 income in “Income from equity method investments” and “Non-operating income.”

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 or affected by various federal regulations. 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 purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation 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 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 2011 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. Twenty-one franchise agreements have expired as of October 31, 2011. We continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Two franchise agreements will expire during the 2012 fiscal year. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed or that service will be continued in the ordinary course of business under our state-granted franchise rights without the specific franchise agreements with each city or municipality, with no material adverse impact on us.

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 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, 2011, the amount of natural gas in storage varied from 14.6 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 26.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $75.9 million to $133.2 million.

During the year ended October 31, 2011, 181.2 million dekatherms of gas were sold to or transported for large volume customers compared with 154.3 million dekatherms in 2010. Of these volumes sold to or transported for large volume customers, we transported 83.5 million dekatherms this year to power generation facilities as compared with 63 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed demand contracts. Deliveries to temperature-sensitive residential

and commercial customers, whose consumption varies with the weather, totaled 98.5 million dekatherms in 2011, compared with 98.3 million dekatherms in 2010. Weather, as measured by degree days, was 10% colder than normal in 2011 and 6% colder than normal in 2010.

The following is a five-year comparison of operating statistics for the years ended October 31, 2007 through 2011.

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 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, 2011, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.

As of October 31, 2011, 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, 2011, we own or have under contract 36.1 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement or replace regular pipeline supplies.

The source of the gas we distribute is primarily from the Gulf Coast production region and is purchased primarily from major and independent producers and marketers. Natural gas demand is continuing to grow in our service area, particularly from power generation customers. To diversify our reliance away from the Gulf Coast region, we receive 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 have firm, long-term transportation service from Midwestern Gas Transmission Company that provides access to gas supplies from Canadian and Rocky Mountain supply basins via the Chicago hub that can supply city gate demand or be used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.

We completed two pipeline expansion projects in fiscal year 2011 and one in December 2011 to provide long-term gas transportation service to power generation customers in our market area. We have two pipeline expansion projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the environmental benefits of replacing a coal-fired power plant with a new natural gas-fired power plant, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance 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.

We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes and slower new home construction. However, we took advantage of the growth opportunities that existed in those markets and continue to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal year 2011, we added 10,522 new customers, including 6,843 residential new home construction customers, 1,406 commercial and industrial customers and 2,273 conversion customers, as well as two new power generation customers mentioned above. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.

During the year ended October 31, 2011, approximately 5% 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. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers, availability and the price of alternate fuels. 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, 2011, no bypass occurred. The future level of bypass activity cannot be predicted.

As noted above, many of our industrial customers are capable of burning a fuel other than natural gas, with fuel oil being the most prevalent energy alternative. Our ability to maintain industrial market share is largely dependent on price. 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 US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

The regulated utility also competes with other energy products, such as electricity and propane, in the residential and small commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. There are four major electric companies within our service areas. We believe that the consumer’s preference for natural gas is influenced by such factors as 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 lowers the carbon footprint of those premises in our market area.

During the year ended October 31, 2011, our largest revenue generating customer contributed $49.5 million, or 3%, of total operating revenues. Our largest margin generating customer contributed $15.6 million, or 3% of total margin.

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 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As of October 31, 2011, our fiscal year end, we had 1,782 employees compared with 1,788 as of October 31, 2010.

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

An overall economic downturn or slow recovery could negatively impact our earnings.

Weakening or slow recovery 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. Inflationary pressure could increase the costs of goods, services and labor, and an increase in interest rates could increase our interest expense and make it more difficult or expensive for us to access the capital markets. Earnings and liquidity would be negatively affected, reducing our ability to grow the business.

Increases in the wholesale price of natural gas could reduce our earnings and working capital.

The supply and demand balance 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, and restrictions or regulations on shale gas production could cause natural gas prices to increase. 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, and customers may have trouble paying higher bills leading to bad debt expenses, which may reduce our earnings.

A decrease in the availability of adequate interstate pipeline transportation capacity and natural gas supply could reduce our earnings.

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 that supply or interstate pipeline capacity due to unforeseen events, including but not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of natural gas wells, terrorist attacks or other acts of war, 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 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 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.

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.

Changes in federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacity and/or gas supply and thereby reduce our earnings.

The FERC has regulatory authority over some of our operations, including sales of natural gas in the wholesale market and the purchase and sale of interstate pipeline and storage capacity. Additionally, the Commodities Futures Trading Commission 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. Any federal legislation or agency regulation that has the effect of significantly raising costs that could not be recovered in rates from our customers or reducing the availability of supply or capacity, the liquidity of the natural gas supply market or our competitiveness could negatively impact our earnings.

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 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 operational requirements, impose additional charges to fund energy efficiency activities, provide a cost advantage to alternative energy sources other than natural gas, impose costs or restrictions on end users of natural gas, or result in other costs or requirements. As a result, there is a possibility that, if enacted or adopted, such legislation or regulation could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.

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. 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 by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers (including margin decoupling and cost of gas) or other tariff provisions, then our earnings could be negatively impacted. 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.” 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 appropriate entities. Regulatory authorities also review whether our gas costs are prudent and can adjust the amount of our gas costs that we pass through to our customers. Additionally, our state regulators foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use

alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there were changes in regulatory philosophies that altered our ability to compete for these customers, then we could lose customers or incur significant unrecoverable expenses to retain them. Both scenarios would impact our results of operations, financial condition and cash flows. 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 earnings can vary from year to year, depending in part on weather conditions. Currently, we have in place regulatory mechanisms that normalize our margin for weather during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. Mild winter temperatures can cause a decrease in the amount of gas we sell and deliver in any year and the margin we collect from these customers. If our rates and tariffs were modified to eliminate weather protection, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather, and our earnings could vary as a result.

Our gas supply risk management programs are subject to state regulatory approval or annual review in gas cost proceedings.

We manage our gas supply costs through short-term and long-term procurement and storage contracts. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments of various durations for the forward purchase or sale of our natural gas requirements, subject to regulatory approval or review. As a component of our gas costs, these expenses are subject to regulatory approval, and we may be exposed to additional liability if the recovery of these costs of gas supply procurement or risk management activities is excluded by our regulators in gas cost recovery proceedings.

Operational interruptions to our gas distribution and transmission activities caused by accidents, work stoppage, severe weather conditions, including destructive weather patterns such as hurricanes, tornadoes and floods, pandemic or acts of terrorism could adversely impact earnings.

Inherent in our gas distribution and transmission activities 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, could also damage our pipelines and other infrastructure and disrupt our ability to conduct our natural gas distribution and transportation business. 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 foregoing 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. With part of our workforce represented by unions, we are exposed to the risk of a work stoppage. 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 integrity or infrastructure development projects, which may delay or prevent us from serving our customers or expanding our business.

In order to serve new customers or 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, 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, which would negatively impact our earnings. In addition, the counterparties to our power generation construction and service agreements may elect to terminate the agreements, which would negatively affect future earnings and cash 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 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 cost 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 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.

The inability to access capital or significant increases in the cost of capital could adversely affect our business.

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 could adversely affect our ability to access short-term and long-term capital. Our access to funds under short-term credit facilities 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. Disruptions and volatility in the European credit market could cause the interest rate we pay on our short-term credit facility, which is based on the London Interbank Offered Rate, to increase, could result in higher interest rates on future financings, and could impact the liquidity of the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. Longer 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. The inability to access adequate 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 cost of borrowing.

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

Changes in federal and state fiscal 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 of 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 flow. 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.

Historically, we have made large capital expenditures in order to finance the expansion and upgrading 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.

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 is subject to changes in pension fund values and other factors and could unfavorably impact our liquidity and results of operations.

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 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 are subject to numerous environmental laws and regulations that may require significant expenditures or increase operating costs.

We are subject to numerous federal and state environmental laws and regulations affecting many aspects of our present and future operations. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and approvals. Compliance with these laws and regulations can require significant expenditures for clean-up costs and damages arising out of contaminated properties. Failure to comply may result in fines, penalties and injunctive measures affecting operating assets. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations or financial condition.

We are subject to new and existing pipeline safety and system integrity laws and regulations that may require significant expenditures or significantly increase operating costs.

We are subject to existing and may be subject to new pipeline safety and system integrity laws and regulations affecting various aspects of our present and future operations. These laws and regulations generally require us to enhance pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations may result in increased capital, operating and other costs which may not be recoverable in rates from our customers. Furthermore, because the language in some of these 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. All of the above could result in a material adverse effect on our business, results of operations or financial condition.

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 the 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. All the foregoing could adversely affect our earnings from or return of our investment in these businesses. We could make future investments in similarly 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.

Our inability to attract and retain professional and technical employees 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 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 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 (GAAP) in the United States. 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.

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, production plant, storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with 94% of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,700 linear miles of transmission pipelines 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 our consolidated balance sheets. The amount classified as plant held for future use relates to expenditures associated with a potential LNG peak storage facility in the eastern part of North Carolina that has been delayed given the slowing of our growth due to current economic conditions. Another project under construction will help serve the near term system pressure requirements in a cost effective manner in that part of North Carolina. The timing and design scope of the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.

We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our resource centers in the locations shown below. Lease payments for these various offices totaled $4 million for the year ended October 31, 2011.

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

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, 2011 and 2010.

As of December 16, 2011, our common stock was owned by 13,916 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in the street name or in the name of an investment company.

The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 2011 and 2010. 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, 2011, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

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, 2011.

The following performance graph compares our cumulative total shareholder return from October 31, 2006 through October 31, 2011 (a five-year period) with our utility peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500). Large natural gas distribution companies that are representative of our peers in the natural gas distribution industry are included in our LDC Peer Group index.

The Laclede Group, Inc. and South Jersey Industries, Inc. were added to our peer group because they are publicly traded companies with a focus on natural gas distribution in multi-state territories and have similar annual revenues and market capitalization as compared with us. 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 cumulative shareholder return as we use for market benchmarking for our executive compensation plans. It was recommended by a benefits consultant that we expand our peer group.

Our total return of $100 invested as of October 31, 2011 was $147. With the addition of The Laclede Group, Inc. and South Jersey Industries, Inc., our peer group return was $148. Without them, the peer group return would have been $142.

The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2006 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

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

The following table provides selected financial data for the years ended October 31, 2007 through 2011.

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

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 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 rely on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “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.

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 51,800 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 storage and intrastate natural gas transportation.

In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service to Anderson, Gaffney, 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 the cities of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the year ended October 31, 2011, 87% of our earnings before taxes came from our regulated utility segment. 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. For the year ended October 31, 2011, 13% of our earnings before taxes came from our non-utility segment, which consisted of 5% from regulated non-utility activities and 8% from unregulated non-utility activities. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements.

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina 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 or affected by various federal regulations. 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 purchase and sale of and the prices paid 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 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.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs 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 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.

In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on a year around basis independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the margin decoupling mechanism or the WNA. For further information, see Note 2 to the consolidated financial statements.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. We have been pursuing alternatives to the traditional utility rate design that provide for the collection of margin revenue based on volumetric throughput with new rate designs and incentives that allow utilities to encourage energy efficiency and conservation. By decoupling the link between energy consumption and margin revenues, our interests are aligned with our customers’ interests on conservation and energy efficiency. In North Carolina, we have decoupled residential and commercial rates. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. For the twelve months ended October 31, 2011, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 70% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and

Tennessee; and volumetric or periodic renegotiation of 12% of our utility margins. For the twelve months ended October 31, 2011, the margin decoupling mechanism in North Carolina reduced margin by $7 million, and the WNA in South Carolina and Tennessee reduced margin by $4.9 million.

On September 2, 2011, we filed a general rate application with the TRA for an increase in rates and charges to all customers that would be effective March 1, 2012. We also requested a modification of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. For further information, see Note 2 to the consolidated financial statements.

We have refined our strategic objectives to a customer-centered approach and what we believe is the inherent benefit of natural gas compared to other types of energy. Our overall corporate focus is to expand our core natural gas and complementary energy-related businesses to enhance shareholder value. This focus includes traditional growth in the core residential, commercial and industrial markets, growth in the power generation market, supply diversity and complementary energy-related investments and natural gas end use technology. We want our customers to choose us because of the value of natural gas and the quality of our service to them. We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. We pursue business practices to promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and fostering increased awareness and use of natural gas. We support our employees with improved processes and technology to better serve our customers and to add value for our shareholders while continuing to build on our healthy, high performance culture in order to recruit, retain and motivate our workforce.

To support these objectives, we are reorganizing our field customer services, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service and increase customer loyalty and satisfaction while improving operational efficiencies. We have also implemented new centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

The safety of our system, the public and our employees is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing programs to inspect our system for corrosion and leaks. Given an increased interest in pipeline safety and integrity in the wake of several serious pipeline incidents in the United States, we anticipate federal legislative and regulatory enactments that will add further requirements to our pipeline safety and integrity programs. We met an August 2011 deadline to evaluate any risks to our distribution pipeline system (such as corrosion and leak detection) and created an action plan to address those risks. We have transmission pipeline integrity programs where we execute standard procedures and programs for pipeline safety that include leak detection surveys, periodic valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection, in-line inspection devices, hydrostatic and compressed air pressure testings of new facilities and other evaluation methods. It is likely that these programs will increase in scope as a result of anticipated legislation and regulation. 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 any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

The safeguarding of our information technology infrastructure is important to our business. There is risk associated with the unauthorized access of digital data with the intent to misappropriate information, corrupt data or cause operational disruptions. To protect confidential customer, vendor, financial and employee information, we believe we have appropriate levels of security measures in place to secure our information systems from cybersecurity attacks or breaches. We also have a comprehensive identity theft protection program to protect customer information, as well as a cybersecurity insurance policy.

We continue our efforts to promote the benefits of natural gas. Promotion efforts are led by educating consumers on the benefits of natural gas compared to other energy sources as well as advocating the benefits of natural gas to prospective customers in our communities. We continue our efforts to promote the direct use of natural gas in 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 also promote and market the cost and environmental benefits of natural gas to power generation customers in our market area. Price moderation and stability of natural gas continues, which has made natural gas more economical than many other fuels.

We continue to see challenging economic conditions in our market area with continued high rates of unemployment, weakened housing markets with high inventories of unsold homes, and slower new home construction. We took advantage of the growth opportunities that existed in those markets and continue to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. In fiscal 2011, our gross customers additions were 4% lower than 2010; however, our month-end customers billed as well as the twelve-month average customers billed during fiscal year 2011 increased 1% over the respective prior year. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2012 of approximately 1%.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are executing a plan to build more compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as third party use and the general public. Currently, approximately 11% of our vehicle fleet uses CNG. We have five CNG fueling stations in use, and we plan to construct four more. Within two years, we anticipate that up to 33% of our fleet will be capable of using CNG.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength, which translates to continued access to capital markets. We continue to evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. In June 2011, we replaced $196.8 million of notes with a 6.25% stated interest rate with $200 million of notes with a weighted interest rate of 4%. In July 2011, we filed a shelf registration statement that will allow for future issuances of debt or equity. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

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 with a major factor being 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, 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

Several new laws were enacted in 2010 for health care reform and the regulation of U.S. financial markets. We continue to follow the progress of new regulations that are being issued and will be issued by various regulatory agencies. While we are not able to assess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material impact on our financial position, results of operations or cash flows.

Also, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010, extended the 50% “bonus depreciation” that expired December 31, 2009 and temporarily increased “bonus depreciation” for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. The Internal Revenue Service has issued regulations that are intended to provide guidance in interpreting the law. Based on current capital projections and timelines, we are anticipating a benefit through 2014 of $130 - 170 million. We anticipate that the bonus depreciation allowance will have a material favorable impact on our cash flows in the near term by reducing cash needed to pay federal income taxes.

The following tables present our financial highlights for the years ended October 31, 2011, 2010 and 2009.

Net income decreased $28.4 million in 2011 compared with 2010 primarily due to the following changes which decreased net income:

These changes were partially offset by the following changes, which increased net income:

Net income increased $19.1 million in 2010 compared with 2009 primarily due to the following changes which increased net income:

These changes were partially offset by the following changes, which decreased net income:

Operating revenues in 2011 decreased $118.4 million compared with 2010 primarily due to the following decreases:

Operating revenues in 2010 decreased $85.8 million compared with 2009 primarily due to the following decreases:

Cost of gas in 2011 decreased $139.4 million compared with 2010 primarily due to the following decreases:

Cost of gas in 2010 decreased $76.8 million compared with 2009 primarily due to $131.1 million from lower priced gas costs passed through to sales customers, partially offset by the following increases:

In all three states, we are authorized to recover from customers all prudently incurred gas costs. Changes to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the passthrough of changes in wholesale commodity gas costs, which accounted for 47% of revenues for the twelve months ended October 31, 2011, and transportation and storage costs, which accounted for 9%.

In general rate proceedings, state regulatory commissions authorize us to recover a margin, which is the applicable billing rate less cost of gas, on each unit of gas delivered. The commissions also authorize us to recover margin losses resulting from negotiating lower rates to industrial customers when necessary to remain competitive. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include the WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the Tennessee Incentive Plan in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the recovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Margin increased $21 million in 2011 compared with 2010 primarily due to the following increases:

Margin decreased $9 million in 2010 compared with 2009 primarily due to the following decreases:

Operations and maintenance expenses increased $5.5 million in 2011 compared with 2010 primarily due to the following increases:

Operations and maintenance expenses increased $11.7 million in 2010 compared with 2009 primarily due to the following increases:

Depreciation expense increased from $97.4 million to $102.8 million over the three-year period 2009 to 2011 primarily due to increases in plant in service.

General taxes increased $4.5 million in 2011 compared with 2010 primarily due to the following increases:

Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, charitable contributions, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of other miscellaneous expenses.

The primary changes to Other Income (Expense) in 2011 compared with 2010 were in income from equity method investments, the gain on the sale of half of our ownership interest in SouthStar Energy Services LLC (SouthStar) in 2010 and non-operating income discussed below. All other changes were insignificant.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.3 million, or $.42 per diluted earnings per share, for 2010.

Income from equity method investments decreased $4.8 million in 2011 compared with 2010 primarily due to a decrease of $4.5 million in earnings from SouthStar due to a full year of recording earnings at the lower 15% ownership interest and unfavorable changes in SouthStar’s average customer usage due to warmer weather and retail pricing plan mix which were partially offset by decreases in operating expenses.

Non-operating income increased $1.1 million in 2011 compared with 2010 primarily due to increased revenues under our non-regulated home service warranty program, interest earned on installment loans made to our natural gas customers under our third party financing program and a state tax refund on behalf of a joint venture.

Income from equity method investments decreased $4.6 million in 2010 compared with 2009 due to a $4.5 million decrease in earnings from SouthStar primarily due to the recording of earnings at the new 15% ownership interest as of January 1, 2010 and a change in the retail pricing mix chosen by SouthStar customers with a decrease in the average number of customers, losses on weather derivatives and a decreased contribution from storage and transportation asset management due to higher transportation and commodity prices, partially offset by increased average customer usage due to colder weather, favorable changes in the lower of cost or market storage inventory adjustments and higher retail price spreads.

Utility interest charges increased $.3 million in 2011 compared with 2010 primarily due to the following changes:

Utility interest charges decreased $3 million in 2010 compared with 2009 primarily due to the following changes:

To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities.

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchases and other cash needs.

Short-Term Borrowings. On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility. The new facility expires in January 2014 and has an option to expand up to $850 million. The three-year revolving syndicated credit facility has the same financial covenant as our previous syndicated credit facility and has additional provisions regarding defaulting lenders and replacement of lenders. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. During the three months ended October 31, 2011, short-term borrowing ranged from $165.5 million to $342.5 million, and interest rates ranged from 1.10% to 1.15%. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17%.

Our short-term borrowings, which consist only of the revolving syndicated credit facility as included in “Bank debt” in the consolidated balance sheets, are vital in order to meet working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity, capital expenditures and approved investments. We rely on short-term borrowings along with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support our system infrastructure and the growth in our customer base. We believe that our revolving syndicated credit facility, along with our access to capital markets, will allow us to meet the increased capital requirements anticipated to be spent over the next two years.

Highlights for our bank borrowings as of October 31, 2011 and for the quarter and year ended October 31, 2011 are presented below.

The level of short-term bank borrowings can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

As of October 31, 2011, we had $10 million available for letters of credit under our three-year revolving syndicated credit facility, of which $3.5 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2011, unused lines of credit available under our three-year revolving syndicated credit facility, including the issuance of the letters of credit, totaled $315.5 million.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, seasonal construction activity and decreases in receipts from customers.

During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their heating bills. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Because of the weak economy, including continued high unemployment, we may incur additional bad debt expense as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, are expected to mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $311.2 million in 2011, $360.5 million in 2010 and $344.3 million in 2009. Net cash provided by operating activities reflects a $28.4 million decrease in net income for 2011 compared with 2010, which included the gain on the sale of half our interest in SouthStar as discussed in “Results of Operations” above in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. The effect of changes in working capital on net cash provided by operating activities is described below:

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated credits to customers of $4.9 million in 2011, $8.8 million in 2010 and $1.2 million in 2009. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism reduced margin by $7 million in 2011 and $5.9 million in 2010 and increased margin by $6 million in 2009. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. 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 US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and operations and maintenance cost management programs to capture operational efficiencies while improving customer service and maintaining a safe and reliable system.

Cash Flows from Investing Activities. Net cash used in investing activities was $252.6 million in 2011, $128.6 million in 2010 and $129.6 million in 2009. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $243.6 million in 2011, a 22% increase from the $199.1 million in 2010, primarily due to $103.6 million and $52.3 million, respectively, of investments in plant to serve power generation customers. Gross utility construction expenditures were $129 million in 2009 with $2.6 million of investments in plant to serve power generation customers.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Significant utility construction expenditures are expected to meet long-term growth, including the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

We anticipate making capital expenditures, including AFUDC, of $240 - 280 million and $80 - 90 million in our fiscal years 2012 and 2013, respectively, to provide natural gas service in the power generation market. These expenditures are significantly higher than we have traditionally expended. We intend to fund expenditures related to these projects in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. Additional detail for the anticipated capital expenditures follows.

In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct approximately 38 miles of 20-inch transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2012. We began construction in February 2010. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. To provide the additional delivery service, we have executed an agreement with Cardinal Pipeline Company, LLC (Cardinal) to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend an estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions to date related to this system expansion were $6.2 million. For further information regarding this agreement, see Note 12 to the consolidated financial statements.

In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement, also approved by the NCUC in May 2010, calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013. We began construction in May 2010. Our service to Progress Energy Carolinas is supported by a long-term service agreement. We anticipate that a portion of the cost of this project will be included in our North Carolina utility rate base.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our previously announced Robeson liquefied natural gas storage project. The timing and design scope of the expansion of our facilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.

During the first quarter of fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a Progress Energy Carolinas power generation facility located in Richmond County, North Carolina.

During the first quarter of fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a Duke Energy Carolinas power generation facility located in Rowan County, North Carolina. In a second agreement with Duke Energy Carolinas, we placed into service in December 2011 natural gas pipeline facilities we constructed to provide natural gas delivery service to their Rockingham County, North Carolina power generation facility.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to Georgia Natural Gas Company (GNGC) and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC. For further information regarding the sale, see Note 12 to the consolidated financial statements.

In 2009, we contributed $.9 million to our Hardy Storage Company, LLC (Hardy Storage) joint venture as part of our equity contribution for construction of the FERC regulated interstate storage facility. We made no contributions in 2010 and 2011 as Hardy Storage converted its construction interim notes in March 2010 into long-term project-financed debt. For further information on Hardy Storage, see Note 12 to the consolidated financial statements.

Cash Flows from Financing Activities. Net cash used in financing activities was $57.5 million in 2011, $233.9 million in 2010 and $214.1 million in 2009. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to retire long-term debt, pay down outstanding short-term bank borrowings, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock. As of October 31, 2011, our current assets were $286 million and our current liabilities were $534.1 million, primarily due to seasonal requirements as discussed above.

Outstanding short-term bank borrowings increased from $242 million as of October 31, 2010 to $331 million as of October 31, 2011 primarily due to higher capital expenditures and long-term debt maturities. Over the three-year period from 2009 to 2011, our short-term borrowings have included the replacement of our five-year revolving syndicated credit facility with our current three-year revolving syndicated credit facility and a syndicated seasonal credit facility in existence from December 3, 2008 through March 31, 2009. For further information on bank borrowings, see the previous discussion of “Short-Term Borrowings” in “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.

We retired our $60 million 6.55% medium-term notes, $60 million 7.8% medium-term notes and $30 million 7.35% medium-term notes in September 2011, September 2010 and September 2009, respectively, as they became due. On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal balance of $196.8 million with short-term bank borrowings under the revolving syndicated credit facility. On June 6, 2011, we issued $40 million of unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million of unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term borrowings as well as for other general corporate purposes and working capital needs. The replacement of this higher rate debt with lower rate debt will provide annual interest savings of $4.3 million.

On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in our subsidiaries, and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.

We plan to issue approximately $300 million of long-term debt in our fiscal 2012 third quarter for general corporate purposes, including the funding of capital expenditures to serve new power generation projects. We continually monitor customer growth trends and opportunities in our markets along with the economic recovery of our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our ASR program as described in Note 6 to the consolidated financial statements. During 2011, we repurchased and retired .8 million shares for $23 million under our Common Stock Open Market Purchase Program, leaving a balance of 3,710,074 shares available for repurchase under the program. During 2010 and 2009, we repurchased 1.8 million shares and .7 million shares for $47.3 million and $17.9 million, respectively. We anticipate repurchasing .8 million shares of common stock through an ASR agreement in the first quarter of our fiscal year 2012 with no permanent reduction in shares outstanding for fiscal year 2012.

During 2011, we issued $20.2 million of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. During 2010 and 2009, we issued $19.1 million and $14.4 million, respectively, through these plans.

We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share in 2011, 2010 and 2009. Dividends of $82.9 million, $80.3 million and $78.4 million for 2011, 2010 and 2009, respectively, were paid on common stock. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2011, our retained earnings were not restricted. On December 16, 2011, the Board of Directors declared a quarterly dividend on common stock of $.29 per share, payable January 13, 2012 to shareholders of record at the close of business on December 27, 2011. For further information, see Note 4 to the consolidated financial statements.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. As of October 31, 2011, our capitalization, including current maturities of long-term debt, if any, consisted of 40% in long-term debt and 60% in common equity.

The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2011 and 2010 are summarized in the table below.

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:

As of October 31, 2011, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. Credit ratings and outlooks are opinions of the rating agency and are subject to their ongoing review. A significant decline in our operating performance, capital structure, or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2011, there has been no event of default giving rise to acceleration of our debt.

We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2011, our estimated recorded and unrecorded contractual obligations are as follows.

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit and operating leases are discussed in Note 5 and Note 8, respectively, to the consolidated financial statements and are reflected in the table above.

We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates. Management has discussed these critical accounting estimates presented below with the Audit Committee of the Board of Directors.

Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to the accounting regulations required by rate regulated operations and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.

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 deregulation legislation. 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 recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.

Regulatory assets as of October 31, 2011 and 2010 totaled $200.1 million and $197.8 million, respectively. Regulatory liabilities as of October 31, 2011 and 2010 totaled $467 million and $439.1 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements.

Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. In South Carolina and Tennessee, we have WNA mechanisms that are designed to protect a portion of our revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin earned monthly under the margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism. Without the WNA and margin decoupling mechanisms, our operating revenues in 2011 and 2010 would have been higher by $11.9 million and $14.7 million, respectively, and lower by $4.8 million in 2009.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanism, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.

Pension and Postretirement Benefits. We have a traditional defined benefit pension plan (qualified pension plan) covering eligible employees. We also provide certain other postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 9 to the consolidated financial statements. The costs of providing these benefits are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.

Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, we also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or

lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods, and we cannot predict with certainty what these factors will be in the future.

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s Investors Service’s AA or better-rated non-callable bonds. Based on this approach, the weighted average discount rate used in the measurement of the benefit obligation for the qualified pension plan changed from 5.47% in 2010 to 4.67% in 2011. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 4.37% in 2010 to 4.10% in 2011. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 4.85% in 2010 to 4.36% in 2011. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, the initial health care cost trend rate was assumed to be 7.80% in 2011 declining gradually to 5% by 2027.

In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 50% equity securities and 50% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8% in 2009, 2010 and 2011. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.92% in 2009, decreasing to 3.87% in 2010 and further decreasing to 3.78% in 2011 due to changes in the demographics of the participants.

Our market-related value of plan assets represents the fair market value of the plan’s assets as adjusted by the portion of the prior five years’ asset gains and losses that has not yet been recognized. The use of this calculation delays the impact of current market fluctuations on benefit costs for the fiscal year.

During 2011, we recorded cost of $2.3 million related to our qualified pension plan and postretirement benefits plan. We estimate 2012 expenses for these two plans to be in the range of $5 to $6 million representing an increase of $3 to $4 million over 2011. These estimates reflect the discount rates and assumed rate of return on the plan assets discussed above for each plan.

The following reflects the sensitivity of pension cost to changes in certain actuarial assumptions for our qualified pension plan, assuming that the other components of the calculation are constant.

The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.

We utilize accounting methods consistently applied that are allowed under GAAP which reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

The source of our gas supply that we distribute to our customers comes primarily from the Gulf Coast production region where it is purchased primarily from major and independent producers and marketers. As part of our long-term plan to diversify our reliance away from the Gulf Coast region, we have contracted for firm, long-term market area storage service in West Virginia from Hardy Storage, a venture in which we have a 50% equity interest, which is more fully discussed in Note 12 to the consolidated financial statements. We have also contracted for firm, long-term transportation contract service that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets.

Natural gas demand is continuing to grow in our service area, particularly to provide natural gas delivery service to existing and future power generation facilities as discussed in the preceding section of “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. For further information on our equity venture with Cardinal to expand our firm capacity requirement in order to serve a power generation facility in Wayne County, North Carolina, see Note 12 to the consolidated financial statements.

Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. For further information on secondary market transactions, see Note 2 to the consolidated financial statements.

We continue to work with our regulatory commissions to earn a fair rate of return for our shareholders and provide safe, reliable natural gas distribution service to our customers. For further information about regulatory proceedings and other regulatory information, see Note 2 to the consolidated financial statements.

For information about our equity method investments, see Note 12 to the consolidated financial statements.

We have developed an environmental self-assessment plan to assess our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 8 to the consolidated financial statements.

For further information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements.

In early 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. In October 2010, the SEC staff issued its first public progress report on the work plan. Additionally, in December 2010, the SEC chairman publicly stated that companies would be allowed a minimum of four years to implement IFRS if it is mandated. In May 2011, an SEC Staff Paper was issued outlining a possible endorsement approach for incorporation of IFRS into the U.S. financial reporting system if the SEC were to decide that incorporation of IFRS is in the best interest of U.S. investors. Under this possible framework, IFRS would be incorporated into U.S. GAAP during a transition period of five to seven years with the Financial Accounting Standards Board remaining as the U.S. accounting standard setter.

In November 2011, the SEC released two more Staff Papers as part of their work plan. The first paper was the SEC Staff’s observations regarding the application of IFRS in practice based on an analysis of 183 companies across 36 industries. The Staff found that company financial statements generally appeared to comply with IFRS requirements. Two observations made were: (1) Companies did not always provide relevant accounting policy disclosures or there was not

sufficient detail or clarity in the accounting policy disclosures; and (2) Diversity in the application of IFRS made comparability challenging with the diversity attributed to be standard driven where options were permitted by IFRS or there was an absence of IFRS guidance or just noncompliance with IFRS. The second paper provided an assessment of a comparison of U.S. GAAP and IFRS with an inventorying of areas in which IFRS provides less or no guidance than U.S. GAAP. The fundamental differences noted were that IFRS contains broad principles to account for transactions across industries with limited specific guidance and stated exceptions and that fundamental differences exist between conceptual frameworks, including the level of authority and the definition and recognition of assets and liabilities. The Staff Paper provided a broad comparison of the requirements of both accounting standards, highlighting notable differences, but did not provide an analysis of the impact of those differences on the quality of IFRS.

Although the SEC was expected to vote by the end of 2011 on whether to require the use of IFRS and by what method, they have further delayed their decision to 2012 in order to complete a comprehensive work plan.

In late 2010 and early 2011, we completed a preliminary assessment of IFRS to understand the key accounting and reporting differences compared to U.S. GAAP and to assess potential organizational, process and system impacts that would be required. The accounting differences between U.S. GAAP and IFRS are complex and significant in many areas, and conversion to IFRS would have broad impacts to us. In addition to financial statement and disclosure changes, converting to IFRS would involve changes to processes and controls, regulatory and management reporting, financial reporting systems and other areas of the company. As a part of the IFRS assessment project, a preliminary conversion roadmap was created for reporting IFRS. This IFRS conversion roadmap and our strategy for addressing a potential mandate of IFRS will be re-assessed when the SEC makes its final determination on the use of IFRS.

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 and weather risk. We seek to identify, assess, monitor and manage all of these risks in accordance with defined policies and procedures under an Enterprise Risk Management program and with the direction of the Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures.

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

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. In situations where counterparties do not have investment grade 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.

We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year that exceed the gas cost portion included in base rates is recovered through 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 can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2011, 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, 2011, we had $331 million of short-term debt outstanding under our syndicated revolving credit facility at an interest rate of 1.15%. 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 $2 million during 2011.

As of October 31, 2011, information about our long-term debt is presented below.

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. As such, 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” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets 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 and have used over-the-counter instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval.

We purchase firm gas from a diverse portfolio of suppliers at liquid exchange points. For term suppliers whose performance is greater than one month, we evaluate and monitor their creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. Since most of our commodity supply contracts are at market index prices tied to liquid exchange points and with our significant storage flexibility, we believe that it is unlikely that a supplier default would have a material effect on our financial position, results of operations or cash flows.

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.

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. In these states, this risk is mitigated by WNA mechanisms that are designed to offset the impact of colder-than-normal or warmer-than-normal weather during the months of November through March in our residential and commercial markets. In North Carolina, we manage our weather risk through a year around margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.

Additional information concerning market risk is set forth in “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.

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

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of October 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 2011 and 2010 are as follows.

Piedmont 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 unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

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. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in 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 “Income from equity method investments” in the consolidated statements of income. For further information on equity method investments, see Note 12 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in the consolidated statements of income. 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.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware have been evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.

The consolidated financial statements of Piedmont have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Our segments are based on the components of the company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision making activities. We evaluate the performance of the regulated utility based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the gas distribution business, including the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. See Note 14 for further discussion of segments.

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.

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 commission 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. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.

Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 2011 and 2010 are presented below.

As of October 31, 2011, we had regulatory assets totaling $.5 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and, accordingly, $.5 million will be fully amortized by 2018. We have $4.5 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $81.1 million of regulatory postretirement assets, $19.3 million of asset retirement obligations (AROs) and $9.6 million of estimated environmental costs on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

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, and 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 cost 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 through 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 Income (Expense) in the consolidated statements of income.

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the consolidated statements of income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the consolidated statements of income.

In accordance with utility accounting practice, we have classified expenditures associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina that has been delayed due to current economic conditions as “Plant held for future use” in the consolidated balance sheets. Another project under construction will create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. The timing and design scope of the expansion of our facilities in this area will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate and such costs, approximately half being land purchase and preparation, will be moved to any such future project.

We compute depreciation expense using the straight-line method over periods ranging from 4 to 88 years. The composite weighted-average depreciation rates were 3.19% for 2011, 3.20% for 2010 and 3.25% for 2009.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina. We have proposed the implementation of the new depreciation rates in Tennessee beginning March 1, 2012. We anticipate new rates to become effective in North Carolina in connection with our next general rate case filing.

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 accrue estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the statements of cash flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 2011 and 2010.

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. 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 North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC), we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. In Tennessee, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the Actual Cost Adjustment (ACA) filings; if the difference is greater, there would be a charge to customers through the ACA filing. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the consolidated balance sheets.

We are exposed to credit risk when we enter into contracts with third parties to sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our internal credit policies require counterparties to have an investment-grade credit rating at the time of the contract. Where the counterparty does not have an investment-grade credit rating, 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. We continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2011 and 2010, our trade accounts receivable consisted of the following.

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2011, 2010 and 2009 is presented below.

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

We utilize asset management agreements with counterparties for certain natural gas storage and transportation assets. At October 31, 2011 and 2010, such counterparties held natural gas storage assets, included in “Prepayments” in the consolidated balance sheets, with a value of $35.8 million and $36.6 million, respectively, through capacity release and agency relationships. Under the terms of the asset management agreements, we receive capacity and storage asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The asset management agreements expire at various times through March 31, 2014. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

Effective November 1, 2009, we adopted the additional authoritative guidance related to nonrecurring fair value guidance for certain nonfinancial assets and liabilities and the use of fair value in the impairment testing of goodwill, intangible assets and long-lived assets. In February 2010, we adopted the amended fair value guidance, which clarified disclosure requirements for fair value measurements and requires disclosure of transfers between Levels 1, 2 or 3. The adoption of the additional fair value guidance had no material impact on our financial position, results of operations or cash flows.

The carrying values of cash and cash equivalents, receivables, bank debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the consolidated balance sheets in accordance with derivative accounting standards and marketable securities, classified as trading securities, that are held in a rabbi trust established for our deferred compensation plans. Our pension and postretirement plan assets and liabilities are recorded at fair value in the consolidated balance sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level into the following fair value hierarchy levels as set forth in the fair value guidance.

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities hedge fund of funds, 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 valuation policies and procedures.

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 hedge fund of funds, diversified private equity fund of funds and commodities hedge fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.

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 a 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 end of the reporting period.

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

We early adopted the accounting guidance issued September 2011 that simplifies how an entity tests goodwill for impairment. As part of our qualitative assessment, we considered macroeconomic conditions such as a 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 change in the market for our products or services, and regulatory and political development. We assessed our overall financial performance and considered cost factors such as increases in utility construction expenditures, labor, or other costs that would have a negative effect on earnings. We determined the relevance of any entity-specific events or events affecting our regulated utility segment which would have a negative effect on the carrying value of the reporting unit.

Based on a qualitative assessment, we have determined that it is not necessary to perform a quantitative goodwill impairment test as of October 31, 2011. 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 has been recognized during the years ended October 31, 2011, 2010 and 2009.

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. There were no events or circumstances during the years ended October 31, 2011, 2010 and 2009 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

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 a rabbi trust established for our deferred compensation plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in a rabbi trust. Trading securities are recorded at fair value on the consolidated balance sheets 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 investments at any time. Any participant’s account that exceeds $25,000 will be paid over five years upon retirement. A lesser amount will be paid upon retirement in a lump sum. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in the consolidated balance sheets.

The money market investments in the trust 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, 2011 and 2010 is as follows.

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 which has lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is three 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 and amortize 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.

As discussed in Note 6 to the consolidated financial statements, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares. Currently, it is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans.

The accounting guidance for 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 AROs exist for our underground mains and services.

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. We collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal costs are non-legal obligations as defined by the accounting guidance. Because these estimated removal costs meet the requirements of rate regulated accounting guidance, we have accounted for these non-legal AROs as a regulatory liability. We record the estimated non-legal AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in our consolidated balance sheets. 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 the regulated utility has the opportunity to earn its allowed rate of return.

In 2006, we applied 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. At the same time, the NCUC, the PSCSC and the TRA approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs. AROs will be capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the 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 4.5% to 5.87% with a weighted average of 5.86% for the twelve months ended October 31, 2011. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. Any accretion will not be reflected in the income statement as we have received regulatory treatment for deferral as a regulatory asset with netting against a regulatory liability. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in our consolidated balance sheets as of October 31, 2011 and 2010 are presented below.

A reconciliation of the changes in conditional AROs for the year ended October 31, 2011 and 2010 is presented below.

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 formal 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 South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March. The WNA is designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. In North Carolina, a year around margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA or the margin decoupling mechanism.

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 mechanism, as applicable.

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 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

Utility sales, transportation and secondary market revenues are reported on a net of tax basis. For further information regarding taxes, see “Taxes” in this Note 1 to the consolidated financial statements.

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 and allocated gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. We review gas costs and deferral activity periodically and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

We charge our secondary market customers for natural gas based on specified contract terms. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives.

We have two categories of income taxes in our consolidated statements of income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in our 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 in operating expenses in the consolidated statements of 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 as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use, public utility fees and other miscellaneous taxes.

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

In June 2009, the Financial Accounting Standards Board (FASB) amended accounting guidance to eliminate the quantitative approach that entities use to determine whether an entity has a controlling financial interest in a variable interest entity (VIE) and to require that the entity with a variable interest in a VIE qualitatively assess whether it has a controlling financial interest, and if so, determine whether it is the primary beneficiary. The guidance requires companies to continually evaluate the VIE for consolidation, rather than performing the assessment only when specific events occur. It also requires enhanced disclosures to provide more information about the entity’s involvement with the VIE. The guidance is effective for fiscal periods beginning after November 15, 2009. Our adoption of this guidance on consolidation of VIEs, effective November 1, 2010, had no impact on our financial position, results of operations or cash flows. For information regarding disclosures related to variable interests in unconsolidated VIEs, see Note 13 to the consolidated financial statements.

In January 2010, the FASB issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements. The guidance will be effective for interim periods for fiscal years beginning after December 15, 2010. We will adopt the guidance for Level 3 disclosure for recurring and non-recurring items covered under the fair value guidance for the first quarter of our fiscal year ending October 31, 2012. Since the guidance addresses only disclosures related to fair value measurements under Level 3, the adoption of this guidance will not have a material impact on our financial position, results of operations or cash flows.

In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity’s financing receivables and the reserves held against them. End of reporting period disclosures are required for the reporting period ending on or after December 15, 2010. The disclosures about activity that occurred during a reporting period were effective for interim and annual periods beginning on or after December 15, 2010. We adopted the guidance for the end of period disclosures as of January 31, 2011, and the guidance for the disclosures related to activity in the reporting period during our fiscal second quarter beginning February 1, 2011. Since the guidance addresses only disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of OCI in financial statements. The guidance gives businesses two options for presenting OCI. An OCI statement can be included with the statement of operations, and together the two will comprise the statement of comprehensive income. Alternatively, businesses can present a separate OCI statement, but that statement must appear consecutively with the statement of operations within the financial report. The guidance will be effective for interim and annual periods beginning after December 15, 2011. In October 2011, the FASB tentatively decided to indefinitely defer the provisions to require entities to present the adjustment of items reclassified from OCI to net income in both net income and OCI. We will adopt the unaffected provisions of OCI presentation guidance for the second quarter of our fiscal year ending October 31, 2012. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. We intend to present net income and other comprehensive income in one continuous statement.

In September 2011, the FASB issued accounting guidance to simplify how an entity tests goodwill for impairment. An entity is allowed an option to first assess qualitative factors to determine whether it is more likely than not (greater than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step quantitative impairment test. An entity is not required to calculate the fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. This guidance, which we early adopted for our goodwill assessment performed for October 31, 2011, is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

Our utility operations are regulated by the NCUC, PSCSC and TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of long-term debt and equity securities.

The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and audit our gas cost accounting practices. The TRA regulates our gas purchasing practices under a gas supply incentive program which compares our actual costs to market pricing benchmarks. As part of this jurisdictional oversight, all three states address our gas supply hedging activities. Additionally, North Carolina and South Carolina allow for recovery of uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is recovered through the deferred account and only the non-gas costs, or margin, portion of uncollectibles is included in base rates and uncollectibles expense. In Tennessee, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings; if the difference is greater, there would be a charge to customers through the ACA filing.

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting economic infeasibility of providing service and granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. With the 2003 acquisition and subsequent merger of EasternNC into our regulated utility segment, we are required to provide an accounting of the operational feasibility of this area to the NCUC every two years. Should this operational area become economically feasible and generate a profit, which we believe is unlikely, we would begin to repay the state bond funding.

The NCUC had allowed EasternNC to defer its operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurred first, with a maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% per annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005, and the balance in the deferred account as of June 30, 2005, $7.9 million, including accrued interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the 2008 general rate proceeding, the unamortized balance of the EasternNC deferred operations and maintenance expenses was $9 million at October 31, 2008. This balance is accruing interest at a rate of 7.84% per annum and is being amortized over a twelve year period. As of October 31, 2011 and 2010, we had unamortized balances of $7.7 million and $8.3 million, respectively.

With the inception of our North Carolina energy conservation program on November 1, 2005, we incurred charges of $6.4 million for the benefit of residential and commercial customers. The charges consisted of $3.75 million for the funding of conservation programs in North Carolina, $2.25 million for the reduction of residential and commercial customer rates in North Carolina and $.4 million for interest accruals on the conservation funding and reduction of customer rates. At October 31, 2010, we had a liability for the conservation programs of $.4 million and no liability as of October 31, 2011.

We incur certain pipeline integrity management costs in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of the operations and maintenance costs applicable to all incremental expenditures beginning November 1, 2004. Under the settlement of the 2008 general rate proceeding, the pipeline integrity management costs incurred between July 1, 2005 and June 30, 2008 of $4.6 million were fully amortized over a three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing pipeline integrity management costs continues until another recovery mechanism is established in a future rate proceeding. The unamortized balance as of October 31, 2011 that is subject to a future rate proceeding is $8 million.

In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

In February 2010, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2009, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2009 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In January 2011, the NCUC approved our accounting of gas costs for the twelve months ended May 31, 2010, with adjustments agreed to by us as a result of the North Carolina Public Staff’s audit of the 2010 gas cost review period. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In August 2011, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2011. A hearing on this matter was held on October 4, 2011. We are unable to predict the outcome of this proceeding at this time.

Our gas cost hedging plan for North Carolina is designed to provide some level of protection against significant price increases, targets a percentage range of 22.5% to 45% of annual normalized sales volumes for North Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas costs subject to the annual gas cost prudence review. Any gain or loss recognition under the hedging program is a reduction in or an addition to gas costs, respectively, which, along with any hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review orders issued February 2010 and January

2011 found our hedging activities during the review periods to be reasonable and prudent. As part of the February 2010 order, the NCUC approved an adjustment of $1.1 million related to hedging activity that decreased “Amounts due from customers” as agreed to by us and the North Carolina Public Staff.

We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South Carolina. If a utility elects to operate under the RSA, the annual filing will provide that the utility’s rate of return on equity will remain within a 50-basis point band above or below the last approved allowed rate of return on equity.

In June 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2009 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2008 order. In October 2009, the PSCSC issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.1 million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2009.

In June 2010, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2009 order. In October 2010, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $.75 million annual increase in margin on a return on equity of 11.3%, effective November 1, 2010.

In June 2011, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2011 and a cost and revenue study as permitted by the RSA requesting a change in rates from those approved by the PSCSC in the October 2010 order. In October 2011, the PSCSC issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $3.1 million annual decrease in margin based on a return on equity of 11.3% and a decrease of $1.9 million in depreciation rates for South Carolina utility plant in service, effective November 1, 2011.

In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to determine the prudence of our gas purchases. Costs have never been disallowed on the basis of prudence.

In August 2009, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2009.

In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2010.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan targets a percentage range of 22.5% to 45% of annual normalized sales volumes for South Carolina and operates using historical pricing indices tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and recovered in rates as gas costs. Any gain or loss recognized under the hedging program is a reduction in or an addition to gas costs, respectively, and flows through to South Carolina customers in rates.

In February 2011, the ORS requested that the PSCSC temporarily suspend the PSCSC-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing policies. In March 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of price stability for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC in April 2011. In June 2011, the ORS withdrew its petition for suspension of gas hedging programs. In July 2011, the PSCSC granted the ORS’ motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings.

In August 2011, the PSCSC approved our PGAs and found our gas purchasing policies to be prudent for the twelve months ended March 31, 2011. The settlement agreement also stipulated that our hedging program should no longer have a required minimum volume of hedging. At the PSCSC’s request, the ORS held a public briefing in November 2011 on the issue of how to measure the prudence of hedging programs in future annual review proceedings with no action taken on the matter.

In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers at a total annual cost of $.35 million. The proposed programs in South Carolina were designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs through annual RSA filings and were similar to approved energy efficiency programs in North Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.

In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the ACA mechanism in 1996 by benchmarking gas costs against amounts determined by published market indices and by sharing secondary market (capacity release and off-system sales) activity performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of allocating gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio. The TRA also maintained the $1.6 million annual incentive cap for us on gains and losses, improved the transparency of plan operations by an agreed to request for proposal procedures for asset management transactions and provided for a triennial review of TIP operations by an independent consultant.

In December 2008, we filed an annual report for the twelve months ended December 31, 2007 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In April 2009, the TRA staff filed its final audit report, with which we concurred. In

May 2009, the TRA issued an order adopting all findings from the staff audit. The order included cost of gas adjustments for the calendar year 2007 review period. There was no material impact from these gas cost adjustments on our financial position, results of operations or cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.

In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. There was no material impact from these gas cost adjustments to our financial position, results of operations or cash flows. In October 2010, the TRA issued its order adopting the findings of the revised TRA Audit Staff report on this matter, which were in agreement with our revised report.

In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. This one-time eighteen month audit period was designed to synchronize the ACA audit year with the TIP year in order to facilitate the audit process for future periods. In August 2011, the TRA issued an order approving the deferred gas cost account.

In September 2010, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2010 under the TIP. In May 2011, the TRA issued an order approving our TIP account balances.

In August 2011, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the TIP. We are unable to predict the outcome of this proceeding at this time.

In September 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are unable to predict the outcome of this proceeding at this time.

In September 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 1, 2012. A hearing on this matter has been scheduled for the week of January 23, 2012. We are unable to predict the outcome of this proceeding at this time.

In February 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005,

which would deny recovery of $1.5 million for us. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

In September 2010, we filed a petition with the TRA requesting deferred accounting treatment for the direct, incremental expenses incurred as a result of our response to the severe flooding in Nashville in May 2010. The TRA approved our petition in October 2010. The balance in the deferred account is $1 million as of October 31, 2011 and 2010. We are seeking recovery of these deferred expenses in the general rate application filed with the TRA in September 2011.

Due to the seasonal nature of our business, we contract with customers in the secondary market to sell supply and capacity assets when available. In North Carolina and South Carolina, we operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions where 75% of the net margins are flowed through to jurisdictional customers in rates and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase benchmarking gains and losses are combined with secondary market transaction gains and losses and shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended October 31, 2011, we generated $56.1 million of margin from secondary market activity, $42.1 million of which is allocated to customers as gas cost reductions and $14 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2010, we generated $42.8 million of margin from secondary market activity, $32.1 million of which is allocated to customers as gas cost reductions and $10.7 million as margin allocated to us. In all three jurisdictions for the twelve months ended October 31, 2009, we generated $46 million of margin from secondary market activity, $34.5 million which is allocated to customers as gas cost reductions and $11.5 million as margin allocated to us.

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

We compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

A reconciliation of basic and diluted EPS for the years ended October 31, 2011, 2010 and 2009 is presented below.

All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of October 31, 2011 and 2010 is as follows.

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

Payments of $.1 million and $.6 million in 2011 and 2010, respectively, were paid to noteholders of the 6.25% insured quarterly notes based on a redemption right upon the death of the owner of the notes, within specified limitations. We redeemed all of the 6.25% insured quarterly notes on June 1, 2011, which had an aggregate principal balance of $196.8 million. We retired the balance of $60 million of our 6.55% medium-term notes and $60 million of our 7.8% medium-term notes in September 2011 and September 2010, respectively, as they became due.

On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term borrowings used to finance the redemption of the 6.25% insured quarterly notes, as well as for other general corporate purposes and working capital needs.

On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries, and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.

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, 2011, our retained earnings were not restricted as the amount available for restricted payments was greater than our actual retained earnings as presented below.

We are subject to default provisions related to our long-term debt and short-term debt. Since there are cross default provisions in all of our debt agreements, failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. As of October 31, 2011, we are in compliance with all default provisions.

On January 25, 2011, we replaced our existing $450 million five-year revolving syndicated credit facility with a new $650 million three-year revolving syndicated credit facility that expires in January 2014. The new facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $3.5 million was issued and outstanding at October 31, 2011. The prior five-year revolving syndicated credit facility provided a line of credit for letters of credit of $5 million, of which $2.7 million was issued and outstanding at October 31, 2010. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from 65 to 150 basis points, based on our credit ratings. Amounts borrowed remain outstanding until repaid and do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

Our outstanding short-term bank borrowings, as included in “Bank debt” in the consolidated balance sheets, were $331 million, as of October 31, 2011, under our three-year revolving syndicated credit facility and $242 million, as of October 31, 2010, under our five-year revolving syndicated credit facility, in LIBOR cost-plus loans at a weighted average interest rate of .94% in 2011 and .50% in 2010. During the twelve months ended October 31, 2011, short-term borrowings ranged from $73.5 million to $426 million, and interest rates ranged from .51% to 1.17% when borrowing. Our three-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 51% at October 31, 2011.

Changes in common stock for the years ended October 31, 2011, 2010 and 2009 are as follows.

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorized the repurchase of up to three million shares of currently outstanding shares of common stock. We implemented the program in September 2004. We utilize a broker to repurchase the shares on the open market, and such shares are cancelled and become authorized but unissued shares available for issuance under the ESPP, DRIP and ICP.

On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares were referred to as our ASR program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

On January 10, 2011, we entered into an ASR agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $27.79 per share. The settlement and retirement of those shares occurred on January 11, 2011. Total consideration paid to purchase the shares of $22.2 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets.

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in 48 trading days, or March 18, 2011. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.10 per

share discount, was higher than the initial purchase closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.10 per share discount, for the shares purchased was lower than the initial purchase closing price. At settlement on March 21, 2011, we paid cash of $.8 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction of “Common Stock” in the consolidated balance sheets. The $.8 million was the difference between the investment bank’s weighted average purchase price of $28.8551 per share less a discount of $.10 per share for a settlement price of $28.7551 per share and the initial purchase closing price of $27.79 per share multiplied by 800,000 shares.

As of October 31, 2011, our shares of common stock were reserved for issuance as follows.

In late 2009, we discovered that we had inadvertently sold more shares under our DRIP than were registered with the SEC and authorized by our Board of Directors for issuance under the DRIP as well as having an expired registration statement. To correct these issuances, our Board of Directors ratified the authorization and issuance of the excess number of shares, we filed a registration statement in November 2009 covering the sale and issuance of an additional 2.75 million shares of our common stock under our DRIP, and we filed a registration statement in February 2010, which offered to rescind the purchase of the shares sold under the DRIP between December 1, 2008 and November 16, 2009 and registered all previously unregistered shares issued under the DRIP during that period. All related unauthorized shares and related proceeds received by us and the repurchase of rescinded shares and consideration paid were immaterial. We reported these events to the relevant regulatory authorities, including the SEC and the NCUC. We have not been subjected to enforcement actions, penalties or fines by these regulatory authorities.

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments and the fair value of the right to reclaim cash collateral. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of October 31, 2011 and 2010, we had long gas purchase options providing total coverage of 38.1 million dekatherms and 33.5 million dekatherms, respectively. The long gas purchase options held at October 31, 2011 are for the period from December 2011 through October 2012.

We use financial instruments to mitigate commodity price risk for our customers. We also have marketable securities that are held in a rabbi trust established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of October 31, 2011 and 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the years ended October 31, 2011 and 2010.

Our utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net costs and the gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” or “Amounts due from customers” in the consolidated balance sheets. These derivative instruments reflect exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in a rabbi trust established for our deferred compensation plans and are included in “Marketable securities, at fair value” in the consolidated balance sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, are shown below.

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and do not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of October 31, 2011 and 2010.

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives generally has no earnings impact.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of income for the twelve months ended October 31, 2011 and 2010, absent the regulatory treatment under our approved PGA procedures.

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under an Enterprise Risk Management program. In addition, we have an Energy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Operating lease payments for the years ended October 31, 2011, 2010 and 2009 are as follows.

Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to twenty-one years. The time periods for gas supply contracts range from one to under two years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the consolidated statements of income as part of gas purchases and included in cost of gas.

As of October 31, 2011, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect on our financial position, results of operations or cash flows.

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $3.5 million in letters of credit that were issued and outstanding at October 31, 2011. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements.

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

There are four other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. Remediation work on our Reidsville site under our North Carolina Department of Environment and Natural Resources (NCDENR) approved plan is scheduled to be completed in fiscal 2012.

As part of a voluntary agreement with the NCDENR, we conducted and completed the soil and groundwater remediation for the Hickory, North Carolina MGP site. The soil and groundwater remediation report was approved by the NCDENR. We continue to conduct periodic groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.4 million of remediation costs on this site through October 31, 2011.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The public comment period has ended, and we continue to conduct semi-annual groundwater monitoring at the site per the final consent order. We have incurred $1.5 million of remediation costs through October 31, 2011.

In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required for the Huntersville LNG molecular sieve issue. In September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site and imposing a fine in an amount that will be less than $100,000. We are currently negotiating the ACO. Plans to investigate the extent of the groundwater contamination related to the sieve burial are being developed and are tentatively scheduled to be implemented in the first quarter of our fiscal year 2012. The Huntersville LNG facility also was originally coated with lead-based paint. As a precautionary measure to ensure that no lead contamination occurs, removal of lead-based paint from the site was initiated in spring 2010. We have incurred $3.2 million to remediate the Huntersville LNG site through October 31, 2011. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work tentatively scheduled for our fiscal year 2012.

During the twelve months ended October 31, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility. As of October 31, 2011, our estimate of the total cost to remediate the property is $.5 million, and we have incurred $.4 million through October 31, 2011. This work is scheduled to be completed in our fiscal year 2012.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina district continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina districts had their USTs removed, and we do not anticipate significant environmental remediation with respect to the removal process. As of October 31, 2011, our estimated undiscounted environmental liability for USTs for which we retain remediation responsibility is $.3 million.

In July 2005, we were notified by the NCDENR that we were named as a potentially responsible party for alleged environmental issues associated with an UST site in Clemmons, North Carolina. We owned and operated this site from March 1986 until June 1988 in connection with a non-utility venture. There have been at least four owners of the site. We contractually transferred any clean-up costs to the new owner of the site when we sold this venture in June 1988. Our current estimate of the cost to remediate the site is approximately $144,540. It is unclear how many of the former owners may ultimately be held liable for this site; however, based on the uncertainty of the ultimate liability, we established a non-regulated environmental liability for $36,135, one-fourth of the estimated cost.

One of our operating districts has coatings containing asbestos on some of their pipelines. We have educated our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been trained on the hazards of lead exposure, and we have engaged independent environmental contractors to remove and dispose of the lead-based paint at these facilities.

As of October 31, 2011, our estimated undiscounted environmental liability totaled $2.8 million, and consisted of $1.5 million for the MGP sites for which we retain remediation responsibility, $1 million for the LNG facilities and $.3 million for USTs not yet remediated.

As of October 31, 2011, our regulatory assets for unamortized environmental costs totaled $9.6 million. We sought recovery of $2 million in the pending Tennessee rate case. We will seek recovery of the remaining balance in future rate proceedings.

Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our 401(k) plans. These amendments applied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments applied to all employees, including those covered by the Nashville, Tennessee bargaining unit contract.

Under GAAP, we are required to recognize all obligations related to defined benefit pension and OPEB plans and quantify the plans’ funding status as an asset or liability on our consolidated balance sheets. In accordance with accounting guidance, we measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. We are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost under the authoritative guidance; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OBEB costs. Our plans’ assets are required to be accounted for at fair value. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability.

We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan) for our eligible employees. A defined benefit plan specifies the amount of benefit that an eligible participant eventually will receive upon retirement using information about that participant. An employee became eligible on the January 1 or July 1 following either the date on which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement or termination during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. Effective January 1, 2008, the qualified pension plan was amended for all employees not covered by the bargaining unit contract in Nashville, Tennessee to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued in the future for existing employees. Employees hired prior to January 1, 2008 continue to participate in the amended traditional qualified pension plan. Employees are vested after five years of service and can be credited with up to a total of 35 years of service. When a vested employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under the old formula plus the accrued benefit under the new formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the new formula. These amendments were effective on January 1, 2009 for employees covered by the bargaining unit contract in Nashville, Tennessee.

The investment objectives of the qualified pension plan are oriented to meet both the current ongoing and future commitments to the participants and designed to grow at an acceptable rate of return for the risks permitted under the investment policy guidelines. Assets are structured to provide for both short-term and long-term needs and to meet the objectives of the qualified pension plan as specified by the Benefits Committee of the Board of Directors.

Our primary investment objective of the qualified pension plan is to generate sufficient assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize long-term returns in a manner that is consistent with the plan’s liabilities, cash flow requirements and risk tolerance. The plan’s liabilities are defined in terms of participant salaries. Given the nature of these liabilities and recognizing the long-term benefits of investing in return-generating assets, the qualified pension plan seeks to invest in a diversified portfolio to:

We consider the historical long-term return experience of our assets, the current and targeted allocation of our plan assets and the expected long-term rates of return. Investment advisors assist us in deriving expected long-term rates of return. These rates are generally based on a 20-year horizon for various asset classes, our expected investments of plan assets and active asset management instead of a passive investment strategy of an index fund.

The investment philosophy of the qualified pension plan is to maintain a balanced portfolio which is diversified across asset classes. The portfolio is primarily composed of equity and fixed income investments in order to provide diversification as to issuers, economic sectors, markets and investment instruments. Risk and quality are viewed in the context of the diversification requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

The qualified pension plan maintains a 45% target allocation to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds, asset-backed securities and derivatives. The derivatives must be fully collateralized so that they either hedge an existing position or there is a cash position for an equivalent value of the underlying principal. No leveraged position greater than 10% within the fixed income portfolio can be taken with derivatives, and the aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives. The qualified pension plan maintains a 35% target allocation to equities, including exposure to large cap growth, large cap value and small cap domestic equity securities, as well as exposure to international equity. There is a 5% target allocation to real estate in a diversified global real estate investment trust (REIT) fund. The remaining 15% target allocation is for investments in other types of funds, including commodities, hedge funds and private equity funds that follow several diversified strategies.

Employees hired or rehired after December 31, 2007 (or December 31, 2008 for employees covered by the bargaining unit contract in Nashville, Tennessee) cannot participate in the amended traditional pension plan but are participants in the Money Purchase Pension (MPP) plan, a defined contribution pension plan that allows the employee to direct the investments and assume the risk of investment returns. A defined contribution plan specifies the amount of the employer’s annual contribution to individual participant accounts established for the retirement benefit. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Under the MPP plan, we annually deposit a percentage of each participant’s pay into an account of the MPP plan. This contribution equals 4% of the participant’s compensation plus an additional 4% of compensation above the social security wage base up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after three years of service. During the year ended October 31, 2011, we contributed $.3 million to the MPP plan.

We provide certain postretirement health care and life insurance benefits to eligible retirees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage. Retirees not in the grandfathered group have 80% of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are responsible for the full cost of dependent coverage. Effective January 1, 2008 (January 1, 2009 for new employees covered under the bargaining unit contract in Nashville, Tennessee), new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits are provided to those employees after age 65 when they are automatically eligible for Medicare benefits to

cover health costs. Our OPEB plan includes a defined dollar benefit to pay the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is $15,000. The life insurance amount for employees who retired prior to this date was calculated as a percentage of their basic life insurance prior to retirement.

OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is the same as the qualified pension plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan maintains a 47% target allocation to equities, which includes exposure to large cap growth, large cap value and small cap domestic equity, as well as exposure to international equity. The OPEB plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3% target allocation to cash. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or the surviving spouse. There are no assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. These nonqualified plans are presented below.

On September 4, 2008, the Compensation Committee of our Board of Directors terminated a former SERP effective October 31, 2008. The supplemental retirement benefit was replaced with a non-qualified defined contribution restoration plan (DCR plan), effective January 1, 2009. Benefits payable under the new plan are informally funded through a rabbi trust with a bank as the trustee. We contribute 13% of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each executive. An additional one-time contribution was made for all eligible officers in January 2009 equal to the greater of:

In addition, an opening balance that totaled $.3 million was established for four Vice Presidents to compensate them for the loss of future benefits under the new plan. Participants may not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption, of annual company contributions, and prospective five-year cliff vesting for the opening balances of the four Vice Presidents. If the officer severs employment before the expiration of the relevant five-year period, he or she receives nothing from that portion of the DCR plan. Participants in the DCR plan may provide instructions to us for the deemed investment of their plan accounts. Distribution will occur upon separation of service or death of the participant. The insurance portion of the SERP benefit was maintained in the form of new term life insurance as discussed below.

Also on September 4, 2008, the Compensation Committee of our Board of Directors approved a voluntary deferred compensation plan, effective January 1, 2009, for the benefit of all officers and director-level employees. Benefits under this plan, known as the Voluntary Deferral Plan, are also informally funded through a rabbi trust with a bank as the trustee. There are no company contributions to the Voluntary Deferral Plan. Participants may defer up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the rabbi trust. Participants may provide instructions to us for the deemed investment of their plan accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

The funding to the DCR plan accounts for the years ended October 31, 2011 and 2010, and the amounts recorded as liabilities for these deferred compensation plans as of October 31, 2011 and 2010 are presented below.

We provide term life insurance policies for officers at the vice president level and above who were participants in the former SERP that terminated on October 31, 2008; the level of the insurance benefit is dependent upon the position of the officer. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed, as grossed up for taxes to the individual officer. Beginning on December 1, 2008, we provide a term life insurance benefit equal to $200,000 to all officers and director-level employees for which we bear the cost of the policies. The cost of these premiums is presented below.

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2011 and 2010, and a statement of the funded status and the amounts reflected in the consolidated balance sheets for the years ended October 31, 2011 and 2010 are presented below.

In 2006 with the implementation of accounting guidance for employers’ accounting for defined benefit pension and other postretirement plans, the NCUC, the PSCSC and the TRA approved our request to place certain defined benefit postretirement obligations in a deferred regulatory account instead of OCI as presented above. The regulators have allowed future recovery of our pension and OPEB costs to this date.

Net periodic benefit cost for the years ended October 31, 2011, 2010 and 2009 includes the following components.

The 2012 estimated amortization of the following items, which are recorded as a regulatory asset or liability instead of accumulated OCI discussed above, and expected refunds for our plans are as follows.

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s Investors Service’s AA or better-rated non-callable bonds that produces similar results to a hypothetical bond portfolio. The discount rate can vary from plan year to plan year. As of October 31, 2011, the benchmark by plan was as follows.

Equity market performance has a significant effect on our market-related value of plan assets. In determining the market-related value of plan assets, we use the following methodology: The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized, meaning that 20% of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the consolidated financial statements.

We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period for active employees. The method of amortization in all cases is straight-line.

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2011 and 2010 are presented below.

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2011, 2010 and 2009 are presented below.

We anticipate that we will contribute the following amounts to our plans in 2012.

The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. The PPA established a 100% funding target for plan years beginning after December 31, 2007, and we are in compliance.

Benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the next ten years ending October 31 as follows.

The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2011 and 2010 are presented below.

The health care cost trend rate assumptions could have a significant effect on the amounts reported. A change of 1% would have the following effects.

The qualified pension plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

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

The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31, 2011 and 2010 are presented below. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see “Fair Value Measurements” in Note 1 to the consolidated financial statements.

We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the Employee Retirement Income Security Act. Eligible employees who have completed 30 days of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary and cash incentive payments to the plan, and we match a portion of their contributions. Employee contributions vest immediately, and company contributions vest after six months of service.

Beginning January 1, 2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville, Tennessee), employees receive a company match of 100% up to the first 5% of eligible pay contributed. Prior to January 1, 2008, we matched 50% of employee contributions up to the first 10% of pay contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution limit. We automatically enroll all affected non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee chooses not to participate by notifying our record keeper. For employees who are automatically enrolled in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our record keeper. If the employee does not make an investment election, employee contributions and matches are automatically invested in a diversified portfolio

of stocks and bonds. Participants may direct up to 20% of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended October 31, 2011, 2010 and 2009, we made matching contributions to participant accounts as follows.

As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Former ESOP participants may remain invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and reinvest the proceeds in other available investment options. The tax benefit of any dividends paid on ESOP shares still in participants’ accounts is reflected in the consolidated statement of stockholders’ equity as an increase in retained earnings.

Under our shareholder approved incentive compensation plans, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the years ended October 31, 2011, 2010 and 2009, we recorded compensation expense, and as of October 31, 2011 and 2010, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

We have three awards under approved incentive compensation plans with three-year performance periods ending October 31, 2011, October 31, 2012 and October 31, 2013. 50% of the units awarded will be based on achievement of a target annual compounded increase in basic EPS. For this 50% portion, an EPS performance of 80% of target will result in an 80% payout, an EPS performance of 100% of target will result in a 100% payout and an EPS performance of 120% of target will result in a maximum 120% payout, and EPS performance levels between these levels will be subject to mathematical interpolation. EPS performance below 80% of target will result in no payout of this portion. The other 50% of the units awarded will be based on the achievement of total annual shareholder return (increase in our common stock price plus dividends reinvested over the specified period of time) in comparison to a peer group which consists of natural gas companies. The total shareholder return performance measure will be our percentile ranking in relationship to the peer group. For this 50% portion, a ranking below the 25th percentile will result in no payout, a ranking between the 25th and 39th percentile will result in an 80% payout, a ranking between the 40th and 49th percentile will result in a 90% payout, a ranking between the 50th and 74th percentile will result in a 100% payout, a ranking between the 75th and 89th percentile will result in a 110% payout, and a ranking at or above the 90th percentile will result in a maximum 120% payout.

In December 2010, a long-term retention award under the incentive compensation plan was approved for eligible officers and other participants. This retention award will be distributed to participants who have met the retention requirements at the end of a three-year period ending in

December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of a participant’s retention units. For the twelve months ended October 31, 2011, we recorded compensation expense, and as of October 31, 2011, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

Also under our approved incentive compensation plan, 65,000 unvested shares of our common stock were granted to our President and Chief Executive Officer in September 2006. During the five-year vesting period, any dividends paid on these shares were accrued and converted into additional shares at the closing price on the date of the dividend payment. In accordance with the vesting schedule 20%, 30% and 50% of the shares vested on September 1, 2009, 2010 and 2011, respectively.

The compensation expense related to the incentive compensation plans for the years ended October 31, 2011, 2010 and 2009, and the amounts recorded as liabilities as of October 31, 2011 and 2010 are presented below.

Based on current accrual assumptions as of October 31, 2011, the expected payout for the approved incentive compensation plans ending October 31, 2011, 2012 and 2013 will occur in the following fiscal years.

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

The components of income tax expense for the years ended October 31, 2011, 2010 and 2009 are presented below.

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2011, 2010 and 2009 is presented below.

As of October 31, 2011 and 2010, deferred income taxes consisted of the following temporary differences.

As of October 31, 2011 and 2010, total net deferred income tax assets were net of a valuation allowance to reduce amounts to the amounts that we believe will be more likely than not realized. We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. As of October 31, 2011 and 2010, we had federal net operating loss carryforwards of $6.2 million and $6.5 million, respectively, which expire from 2024 through 2026. As of October 31, 2011 and 2010, we had state net operating loss carryforwards of $7 million and $7.1 million, respectively, which expire from 2018 through 2025. We may use the loss carryforwards to offset taxable income. Of the loss carryforwards, $6.2 million are subject to an annual limitation of $.3 million.

Our return for the tax year ended October 31, 2008 is currently under examination by the IRS. We do not expect the audit to have a material effect on our financial position, results of operations or cash flows. We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2007, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2007.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2011, 2010 and 2009 is presented below.

A reconciliation of the unrecognized tax benefits for the years ended October 31, 2011 and 2010 is presented below.

We recorded no interest related to unrecognized tax benefits during the year ended October 31, 2011 and only immaterial amounts of interest during the year ended October 31, 2010.

The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the consolidated statements of income.

As of October 31, 2011, there were no amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 37%. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is nonrecourse to the members and is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.

In October 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend an estimated $48 million for a new compressor station and expanded meter stations in order to increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and another customer. As an equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of October 31, 2011, our contributions related to this expansion were $6.2 million.

The members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to be June 2012. Our service subscription to Cardinal’s capacity following the system expansion will increase from approximately 37% to approximately 53%. The NCUC issued a formal certificate order to Progress Energy Carolinas for their Wayne County generation project in October 2009.

We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For each of the years ended October 31, 2011, 2010 and 2009, these transportation costs and the amounts we owed Cardinal as of October 31, 2011 and 2010 are as follows.

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2011 and 2010, and for the twelve months ended September 30, 2011, 2010 and 2009 is presented below.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia and subsidiaries of The Williams Companies, Inc., SCANA Corporation and Hess Corporation. Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. Pine Needle has firm service agreements for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 64%.

Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in the consolidated balance sheets. Pine Needle’s long-term debt is nonrecourse to the members and is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle.

We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2011, 2010 and 2009, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2011 and 2010 are as follows.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2011 and 2010, and for the twelve months ended September 30, 2011, 2010 and 2009 is presented below.

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.3 million, or $.42 per diluted share for 2010. GNGC has no further rights to acquire our remaining 15% interest. We will continue to account for our 15% membership interest in SouthStar using the equity method, as we retain board representation with voting rights equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

SouthStar’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of earnings.

These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in the consolidated balance sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the years ended October 31, 2011, 2010 and 2009, our operating revenues from these sales and the amounts SouthStar owed us as of October 31, 2011 and 2010 are as follows.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2011 and 2010, and for the twelve months ended September 30, 2011, 2010 and 2009 is presented below.

Piedmont Hardy Storage Company, a wholly owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Hardy Storage has firm service contracts for 100% of the storage capacity of the facility, of which Piedmont subscribes to approximately 40%.

In June 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for construction financing. The revolving equity bridge facility was subsequently paid off in 2007. The members of Hardy Storage each agreed to guarantee 50% of the construction financing as well as a separate guaranty of 50% of construction expenditures should contingency wells be required based on the performance of the facility over the first three years after the in-service date. The Guaranty of Principal and Residual Guaranty were executed by a wholly owned subsidiary of Piedmont, Piedmont Energy Partners, Inc. Securing our guaranty was a pledge of intercompany notes issued by Piedmont to its non-utility subsidiaries held under its wholly owned subsidiary. Also pledged was our membership interest in Hardy Storage.

In March 2010, Hardy Storage paid $3.6 million on the interim notes to enable completion of their conversion to long-term project financing of $119.8 million due in 2023 at an interest rate of 5.88%. As a result of the conversion, our Guaranty of Principal and Residual Guaranty, as executed in connection with the interim financing, terminated with no payments having been made. The long-term project financing is nonrecourse to the members of Hardy Storage and their parent entities.

Prior to the long-term financing, we had recorded a liability of $1.2 million for the fair value of this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter with the risk of the project evaluated at each quarter end, with a corresponding increase to our investment account in the venture. Upon completion of the permanent financing in March 2010, the liability was reversed, and our investment account was adjusted accordingly to reflect the elimination of the guaranty.

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For the years ended October 31, 2011, 2010 and 2009, these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2011 and 2010 are as follows.

Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2011 and 2010, and for the twelve months ended October 31, 2011, 2010 and 2009 is presented below.

Effective November 1, 2010, we adopted the FASB guidance that requires us to evaluate our variable interest in a VIE to qualitatively assess whether we have a controlling financial interest, and if so, determine whether we are the primary beneficiary. Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As of October 31, 2011, we have determined that we are not the primary beneficiary, as defined by the authoritative guidance related to consolidations, in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments as discussed in Note 12 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of October 31, 2011 and 2010, our investment balances are as follows.

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Operations of the regulated utility segment are reflected in “Operating Income” in the consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.” All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Operations by segment for the years ended October 31, 2011, 2010 and 2009, and as of October 31, 2011, 2010 and 2009 are presented below.

Reconciliations to the consolidated financial statements for the years ended October 31, 2011, 2010 and 2009, and as of October 31, 2011 and 2010 are as follows.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, see Note 2 to the consolidated financial statements.

16. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)

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

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

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-K. Such disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-K, our disclosure controls and procedures were effective at the reasonable assurance level.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting as that term is defined in Rules 13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s Board of Directors and applicable to all Company Directors, officers and employees.

Because of the inherent limitations, any system of internal control over financial reporting, no matter how well designed, may not prevent or detect misstatements due to the possibility that a control can be circumvented or overridden or that misstatements due to error or fraud may occur that are not detected. Also, projections of the effectiveness to future periods are subject to the risk that the internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures included in such controls may deteriorate.

We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our management concluded that as of October 31, 2011, our internal control over financial reporting was effective.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued its report on the effectiveness of the Company’s internal control over financial reporting as of October 31, 2011.

Piedmont Natural Gas Company, Inc.

/s/ THOMAS E. SKAINS

Thomas E. Skains

Chairman, President and Chief Executive Officer

/s/ KARL W. NEWLIN

Karl W. Newlin

Senior Vice President and Chief Financial Officer

/s/ JOSE M. SIMON

Jose M. Simon

Vice President and Controller

We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of October 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended October 31, 2011 of the Company and our report dated December 23, 2011 expressed an unqualified opinion on those financial statements.

Information concerning our executive officers and directors is set forth in the sections entitled “Information Regarding the Board of Directors” and “Executive Officers” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning our Audit Committee and our Audit Committee financial experts is set forth in the section entitled “Committees of the Board” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. We have also adopted Special Provisions Relating to the Company’s Principal Executive Officer and Senior Financial Officers (Special Provisions) that are part of our Corporate Governance Guidelines and that apply to our principal executive officer, principal financial officer and principal accounting officer. The Code of Ethics and Business Conduct and Special Provisions are available on the “For Investors-Corporate Governance” section of our website at www.piedmontng.com. If we amend or grant a waiver, including an implicit waiver, from the Code of Ethics and Business Conduct or Special Provisions that apply to the principal executive officer, principal financial officer and controller or persons performing similar functions and that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website within four business days of such amendment or waiver.

Information for this item is set forth in the sections entitled “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and “Compensation Committee Report” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference.

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

Information for this item is set forth in the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Equity Compensation Plan Information” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

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

Information for this item is set forth in the section entitled “Independence of Board Members and Related Person Transactions” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Information for this item is set forth in the table entitled “Fees For Services” in “Proposal 2 – Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public Accounting Firm For Fiscal Year 2012” in our Proxy Statement for the 2012 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

The following consolidated financial statements for the year ended October 31, 2011, are included in Item 8 of this report as follows:

Schedules and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at October 31, 2011 and 2010; (3) Consolidated Statements of Income for the years ended October 31, 2011, 2010 and 2009; (4) Consolidated Statements of Cash Flows for the years ended October 31, 2011, 2010 and 2009; (5) Consolidated Statements of Stockholders’ Equity for the years ended October 31, 2011, 2010 and 2009; and Notes to Consolidated Financial Statements.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Piedmont Natural Gas Company, Inc.
(Registrant)

By:		/s/ THOMAS E. SKAINS
		Thomas E. Skains
		Chairman of the Board, President and Chief Executive Officer

Date: December 23, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


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


Title of each class		Name of each exchange on which registered
Common Stock, no par value		New York Stock Exchange


Class		Outstanding at December 16, 2011
Common Stock, no par value		72,338,303


		Page
Part I.

Item 1.	Business		1
Item 1A.	Risk Factors		7
Item 1B.	Unresolved Staff Comments		15
Item 2.	Properties		15
Item 3.	Legal Proceedings		16
Item 4.	(Removed and Reserved)		16

Part II.

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		17
Item 6.	Selected Financial Data		19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		49
Item 8.	Financial Statements and Supplementary Data		52
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		119
Item 9A.	Controls and Procedures		119
Item 9B.	Other Information		122

Part III.

Item 10.	Directors, Executive Officers and Corporate Governance		122
Item 11.	Executive Compensation		122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		123
Item 13.	Certain Relationships and Related Transactions, and Director Independence		123
Item 14.	Principal Accounting Fees and Services		123

Part IV.

Item 15.	Exhibits, Financial Statement Schedules		124

	Signatures		131


	2011		2010		2009		2008		2007
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	658,892	$	743,346	$	787,994	$	813,032	$	743,637
Commercial		379,846		428,085		462,160		503,317		418,426
Industrial		104,774		116,122		126,855		209,341		190,204
For Power Generation		28,969		21,708		19,609		25,266		29,135
For Resale		9,692		11,061		11,746		12,326		13,907

Total		1,182,173		1,320,322		1,408,364		1,563,282		1,395,309
Secondary Market Sales		244,824		224,973		221,300		515,968		308,904
Miscellaneous		6,908		7,000		8,452		9,858		7,079

Total	$	1,433,905	$	1,552,295	$	1,638,116	$	2,089,108	$	1,711,292

Gas Volumes - Dekatherms (in thousands):
System Throughput:
Residential		57,778		58,327		55,298		51,909		50,072
Commercial		40,749		39,994		38,526		36,766		33,647
Industrial		90,842		82,805		74,363		81,780		79,266
For Power Generation		83,522		63,024		39,639		30,875		34,096
For Resale		6,870		8,465		9,048		8,921		8,923

Total		279,761		252,615		216,874		210,251		206,004

Secondary Market Sales		48,835		46,823		46,057		53,442		42,049

Number of Customers Billed (12-month average):
Residential		871,401		864,205		855,670		852,586		835,636
Commercial		94,485		94,287		94,404		94,045		93,472
Industrial		2,265		2,273		2,358		2,937		2,959
For Power Generation		22		20		20		20		15
For Resale		15		16		17		17		15

Total		968,188		960,801		952,469		949,605		932,097


Williams-Transco			632,200
El Paso-Tennessee Pipeline			74,100
Spectra-Texas Eastern (through East Tennessee and Transco)			36,700
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)			120,000

Total			915,800


Piedmont Liquefied Natural Gas (LNG)			268,000
Pine Needle LNG (through Transco)			263,400
Williams-Transco Storage			86,100
NiSource-Columbia Gas Storage			96,400
Hardy Storage (through Columbia Gas and Transco)			68,800
Dominion Storage (through Transco)			13,200
El Paso-Tennessee Pipeline Storage			55,900

Total			851,800


North Carolina	South Carolina	Tennessee
Burlington	Anderson	Nashville
Cary	Gaffney
Charlotte	Greenville
Elizabeth City	Spartanburg
Fayetteville
Goldsboro
Greensboro
Hickory
High Point
Indian Trail
New Bern
Reidsville
Rockingham
Salisbury
Spruce Pine
Tarboro
Wilmington
Winston-Salem


2011	High		Low		2010	High		Low
Quarter ended:					Quarter ended:
January 31	$	30.10	$	27.57	January 31	$	27.84	$	22.51
April 30		32.00		27.88	April 30		28.52		23.87
July 31		31.98		28.80	July 31		27.97		24.50
October 31		33.60		25.86	October 31		29.85		26.15


2011	Dividends Paid Per Share			2010	Dividends Paid Per Share
Quarter ended:				Quarter ended:
January 31		28	¢	January 31		27	¢
April 30		29	¢	April 30		28	¢
July 31		29	¢	July 31		28	¢
October 31		29	¢	October 31		28	¢


Period	Total Number of Shares Purchased			Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period									3,710,074
8/1/11 - 8/31/11		—		$	—		—		3,710,074
9/1/11 - 9/30/11		19,345	(2)	$	31.28		—		3,710,074
10/1/11 - 10/31/11		1,753	(2)	$	33.29		—		3,710,074
Total		21,098		$	31.45		—


In thousands except per share amounts	2011		2010		2009		2008		2007
Operating Revenues	$	1,433,905	$	1,552,295	$	1,638,116	$	2,089,108	$	1,711,292
Margin (operating revenues less cost of gas)	$	573,639	$	552,592	$	561,574	$	552,973	$	524,165
Net Income	$	113,568	$	141,954	$	122,824	$	110,007	$	104,387
Earnings per Share of Common Stock:
Basic	$	1.58	$	1.96	$	1.68	$	1.50	$	1.41
Diluted	$	1.57	$	1.96	$	1.67	$	1.49	$	1.40
Cash Dividends per Share of Common Stock	$	1.15	$	1.11	$	1.07	$	1.03	$	0.99
Total Assets *	$	3,242,541	$	3,053,275	$	3,118,819	$	3,138,401	$	2,823,106
Long-Term Debt (less current maturities)	$	675,000	$	671,922	$	732,512	$	794,261	$	824,887


							Percent Change
In thousands except per share amounts	2011		2010		2009		2011 vs. 2010			2010 vs. 2009
Operating Revenues	$	1,433,905	$	1,552,295	$	1,638,116		(7.6	)%		(5.2	)%
Cost of Gas		860,266		999,703		1,076,542		(13.9	)%		(7.1	)%

Margin		573,639		552,592		561,574		3.8	%		(1.6	)%

Operations and Maintenance		225,351		219,829		208,105		2.5	%		5.6	%
Depreciation		102,829		98,494		97,425		4.4	%		1.1	%
General Taxes		38,380		33,909		34,590		13.2	%		(2.0	)%
Utility Income Taxes		64,068		62,082		70,079		3.2	%		(11.4	)%

Total Operating Expenses		430,628		414,314		410,199		3.9	%		1.0	%

Operating Income		143,011		138,278		151,375		3.4	%		(8.7	)%
Other Income (Expense), net of tax		14,549		47,387		18,124		(69.3	)%		161.5	%
Utility Interest Charges		43,992		43,711		46,675		0.6	%		(6.4	)%

Net Income	$	113,568	$	141,954	$	122,824		(20.0	)%		15.6	%

Average Shares of Common Stock:
Basic		72,056		72,275		73,171		(0.3	)%		(1.2	)%
Diluted		72,266		72,525		73,461		(0.4	)%		(1.3	)%
Earnings per Share of Common Stock:
Basic	$	1.58	$	1.96	$	1.68		(19.4	)%		16.7	%
Diluted	$	1.57	$	1.96	$	1.67		(19.9	)%		17.4	%


In thousands
End of period (October 31, 2011):
Amount outstanding	$	331,000
Weighted average interest rate		1.15	%
During the period (August 1, 2011 - October 31, 2011):
Average amount outstanding	$	236,000
Weighted average interest rate		1.14	%
Maximum amount outstanding during the month:
August	$	269,500
September		288,500
October		342,500
During the year ended October 31, 2011:
Average amount outstanding	$	203,500
Weighted average interest rate		.94	%
Maximum amount outstanding	$	426,000


	2011			2010			2009			2008			2007
Average Per Residential Customer:
Gas Used - Dekatherms		66.30			67.49			64.63			60.88			59.92
Revenue	$	756.13		$	860.15		$	920.91		$	953.61		$	889.90
Revenue Per Dekatherm	$	11.40		$	12.74		$	14.25		$	15.66		$	14.85
Cost of Gas (in thousands):
Natural Gas Commodity Costs	$	666,930		$	753,529		$	727,744		$	1,454,073		$	1,055,600
Capacity Demand Charges		136,139			127,137			128,081			127,640			116,977
Natural Gas Withdrawn From (Injected Into) Storage, net		11,362			5,293			126,480			(78,283	)		(12,815	)
Regulatory Charges (Credits), net		45,835			113,744			94,237			32,705			27,365

Total	$	860,266		$	999,703		$	1,076,542		$	1,536,135		$	1,187,127

Supply Available for Distribution (dekatherms in thousands):
Natural Gas Purchased		155,550			157,021			149,696			159,857			143,598
Transportation Gas		175,005			147,038			115,519			108,332			108,355
Natural Gas Withdrawn From (Injected Into) Storage, net		196			(1,309	)		1,010			(2,980	)		(1,640	)
Company Use		(309	)		(282	)		(283	)		(135	)		(141	)

Total		330,442			302,468			265,942			265,074			250,172


										Percent Change
	2011			2010			2009			2011 vs. 2010			2010 vs. 2009
Deliveries in Dekatherms (in thousands):
Sales Volumes		104,740			105,583			110,379			(0.8	)%		(4.3	)%
Transportation Volumes		175,021			147,032			106,495			19.0	%		38.1	%

Throughput		279,761			252,615			216,874			10.8	%		16.5	%

Secondary Market Volumes		48,835			46,823			46,057			4.3	%		1.7	%
Customers Billed (at period end)		958,307			946,785			937,962			1.2	%		0.9	%
Gross Customer Additions		10,522			10,975			12,608			(4.1	)%		(13.0	)%
Degree Days
Actual		3,662			3,535			3,413			3.6	%		3.6	%
Normal		3,318			3,321			3,324			(0.1	)%		(0.1	)%
Percent colder than normal		10.4	%		6.4	%		2.7	%		n/a			n/a
Number of Employees (at period end)		1,782			1,788			1,821			(0.3	)%		(1.8	)%


In millions	2012		2013		2014
Utility capital expenditures	$	300 - 320	$	270 - 300	$	200 - 250
Power generation related capital expenditures		240 - 280		80 - 90		—

Total forecasted capital expenditures	$	540 - 600	$	350 - 390	$	200 - 250


	Payments Due by Period
In thousands	Less than 1 year		1-3 Years		4-5 Years		After 5 Years		Total
Recorded contractual obligations:
Long-term debt (1)	$	—	$	100,000	$	75,000	$	500,000	$	675,000
Short-term debt (2)		331,000		—		—		—		331,000

Total	$	331,000	$	100,000	$	75,000	$	500,000	$	1,006,000


Actuarial Assumption	Change in Assumption			Impact on 2011 Benefit Cost		Impact on Projected Benefit Obligation
				Increase (Decrease) In thousands
Discount rate		(.25	)%	$	515	$	5,973
Rate of return on plan assets		(.25	)%		644		N/A
Rate of increase in compensation		.25	%		560		3,162


Actuarial Assumption	Change in Assumption			Impact on 2011 Postretirement Benefit Cost		Impact on Accumulated Postretirement Benefit Obligation
				Increase (Decrease) In thousands
Discount rate		(.25	)%	$	13	$	796
Rate of return on plan assets		(.25	)%		52		N/A
Health care cost trend rate		.25	%		9		177


																						Fair Value as of October 31, 2011
	Expected Maturity Date
In millions	2012			2013			2014			2015			2016			Thereafter			Total
Fixed Rate Long-term Debt	$	—		$	—		$	100		$	—		$	40		$	535.0		$	675.0		$	831.3
Average Interest Rate		—	%		—	%		5	%		—	%		2.92	%		6.38	%		5.97	%


In thousands except per share amounts	Common Stock			Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, October 31, 2008	$	471,565		$	763		$	414,246		$	670		$	887,244

Comprehensive Income:
Net income								122,824						122,824
Other comprehensive income:
Unrealized gain from hedging activities of equity method investments, net of tax of ($3,886)											(6,032	)		(6,032	)
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,879											2,915			2,915

Total comprehensive income														119,707
Common Stock Issued		17,861												17,861
Common Stock Repurchased		(17,857	)											(17,857	)
Share-Based Compensation Expense					(730	)								(730	)
Dividends - Incentive Compensation Plan					(33	)		33						—
Tax Benefit from Dividends Paid on ESOP Shares								93						93
Dividends Declared ($1.07 per share)								(78,370	)					(78,370	)

Balance, October 31, 2009		471,569			—			458,826			(2,447	)		927,948

Comprehensive Income:
Net income								141,954						141,954
Other comprehensive income:
Unrealized gain from hedging activities of equity method investments, net of tax of ($52)											(88	)		(88	)
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $1,291											2,005			2,005

Total comprehensive income														143,871
Common Stock Issued		21,366												21,366
Common Stock Repurchased		(47,276	)											(47,276	)
Rescission Offer		(19	)											(19	)
Costs of Rescission Offer								(792	)					(792	)
Tax Benefit from Dividends Paid on ESOP Shares								98						98
Dividends Declared ($1.11 per share)								(80,255	)					(80,255	)

Balance, October 31, 2010		445,640			—			519,831			(530	)		964,941


In thousands
Amount available for restricted payments	$	605,481
Retained earnings		550,584


In thousands	Shares			Amount
Balance, October 31, 2008		73,246		$	471,565
Issued to participants in the Employee Stock Purchase Plan (ESPP)		37			875
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		565			13,560
Issued to participants in the Executive Long-Term Incentive Plan (LTIP)		89			2,755
Issued to participants in the Incentive Compensation Plan (ICP)		29			671
Shares repurchased under Accelerated Share Repurchase (ASR) agreement		(700	)		(17,857	)

Balance, October 31, 2009		73,266			471,569
Issued to ESPP		35			899
Issued to DRIP		676			17,663
Issued to ICP		106			2,804
Shares repurchased under ASR agreement		(1,800	)		(47,276	)
Shares repurchased under rescission offer		(1	)		(19	)

Balance, October 31, 2010		72,282			445,640
Issued to ESPP		30			870
Issued to DRIP		657			18,834
Issued to ICP		149			4,451
Shares repurchased under ASR agreement		(800	)		(23,004	)

Balance, October 31, 2011		72,318		$	446,791


Recurring Fair Value Measurements as of October 31, 2011
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Assets:
Derivatives held for distribution operations	$	2,772	$	—	$	—	$	2,772
Debt and equity securities held as trading securities:
Money markets		217		—		—		217
Mutual funds		1,274		—		—		1,274

Total fair value assets	$	4,263	$	—	$	—	$	4,263


In thousands	Carrying Amount		Fair Value
As of October 31, 2011	$	675,000	$	831,323
As of October 31, 2010		731,922		890,277


Fair Value of Derivative Instruments
In thousands	Fair Value October 31, 2011		Fair Value October 31, 2010
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments
Current Assets - Gas purchase derivative assets (December 2011 - October 2012)	$	2,772

Current Assets - Gas purchase derivative assets (December 2010 - November 2011)			$	2,819


In thousands	Amount of Loss Recognized on Derivative Instruments				Amount of Loss Deferred Under PGA Procedures				Location of Loss Recognized through PGA Procedures
	Twelve Months Ended October 31				Twelve Months Ended October 31
	2011		2010		2011		2010
Gas purchase options	$	10	$	62,516	$	10	$	62,516	Cost of Gas


In thousands
2012	$	3,560
2013		4,068
2014		3,941
2015		3,766
2016		3,720
Thereafter		35,424

Total	$	54,479


In thousands	Pipeline and Storage Capacity		Gas Supply		Telecommunications and Information Technology		Other		Total
2012	$	151,456	$	6,974	$	11,055	$	5,912	$	175,397
2013		100,637		11		6,855		—		107,503
2014		80,603		—		6,108		—		86,711
2015		73,059		—		1,958		—		75,017
2016		57,154		—		—		—		57,154
Thereafter		336,767		—		—		—		336,767

Total	$	799,676	$	6,985	$	25,976	$	5,912	$	838,549


	Qualified Pension						Nonqualified Pension						Other Benefits
In thousands	2011			2010			2011			2010			2011			2010
Accumulated benefit obligation at year end	$	205,159		$	182,822		$	5,219		$	5,039			N/A			N/A

Change in projected benefit obligation:
Obligation at beginning of year	$	211,003		$	195,329		$	5,039		$	4,828		$	31,919		$	35,523
Service cost		8,508			8,069			45			38			1,398			1,337
Interest cost		11,024			10,898			209			243			1,495			1,906
Plan amendments		—			—			290			—			—			—
Actuarial (gain) loss		16,896			7,549			130			420			(327	)		(3,769	)
Participant contributions		—			—			—			—			898			883
Administrative expenses		(391	)		(306	)		—			—			—			—
Benefit payments		(10,408	)		(10,536	)		(494	)		(490	)		(3,483	)		(3,961	)

Obligation at end of year	$	236,632		$	211,003		$	5,219		$	5,039		$	31,900		$	31,919

Change in fair value of plan assets:
Fair value at beginning of year	$	228,345		$	184,277		$	—		$	—		$	21,636		$	19,278
Actual return on plan assets		19,965			32,910			—			—			792			2,841
Employer contributions		22,000			22,000			494			490			2,202			2,595
Participant contributions		—			—			—			—			898			883
Administrative expenses		(391	)		(306	)		—			—			—			—
Benefit payments		(10,408	)		(10,536	)		(494	)		(490	)		(3,483	)		(3,961	)

Fair value at end of year	$	259,511		$	228,345		$	—		$	—		$	22,045		$	21,636

Noncurrent assets	$	22,879		$	17,342		$	—		$	—		$	—		$	—
Current liabilities		—			—			(517	)		(517	)		—			—
Noncurrent liabilities		—			—			(4,702	)		(4,522	)		(9,855	)		(10,283	)

Net amount recognized	$	22,879		$	17,342		$	(5,219	)	$	(5,039	)	$	(9,855	)	$	(10,283	)

Amounts Not Yet Recognized as a Component of Cost and Recognized in a Deferred
Regulatory Account:
Unrecognized transition obligation	$	—		$	—		$	—		$	—		$	(1,334	)	$	(2,001	)
Unrecognized prior service (cost) credit		21,638			23,836			(358	)		(88	)		—			—
Unrecognized actuarial loss		(99,653	)		(85,661	)		(941	)		(852	)		(424	)		(9	)

Regulatory asset		(78,015	)		(61,825	)		(1,299	)		(940	)		(1,758	)		(2,010	)
Cumulative employer contribution in excess of cost		100,894			79,167			(3,920	)		(4,099	)		(8,097	)		(8,273	)

Net amount recognized	$	22,879		$	17,342		$	(5,219	)	$	(5,039	)	$	(9,855	)	$	(10,283	)


Pension plan	4.67	%
NCNG SERP	4.01	%
Directors’ SERP	4.26	%
Piedmont SERP	3.50	%
OPEB	4.36	%


In thousands
Qualified pension plan	$	—
Nonqualified pension plans		517
MPP plan		535
OPEB plan		1,600


In thousands	Qualified Pension		Nonqualified Pension		Other Benefits
2012	$	21,486	$	517	$	1,992
2013		16,161		484		2,031
2014		13,946		450		2,233
2015		14,827		461		2,330
2016		15,452		436		2,381
2017 - 2021		94,812		1,977		13,151


	2011			2010
Health care cost trend rate assumed for next year		7.70	%		7.80	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2027			2027


In thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2011	$	37	$	(38	)
Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2011		693		(706	)