UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended October 31, 2009

or

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

For the transition period from                      to                     

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

     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 þ No o

     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 o No o

     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. o

     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. (Check one):

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

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

     State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2009.

Common Stock, no par value — $ 1,762,419,954

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

Class		Outstanding at December 11, 2009
Common Stock, no par value		73,295,803

Portions of the Proxy Statement for the Annual Meeting of Shareholders on February 26, 2010, are incorporated by reference into Part III.

 

 

Piedmont Natural Gas Company, Inc.

2009 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
Part I.
Item 1. Business			1
Item 1A. Risk Factors			6
Item 1B. Unresolved Staff Comments			13
Item 2. Properties			13
Item 3. Legal Proceedings			14
Item 4. Submission of Matters to a Vote of Security Holders			14
Part II.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			15
Item 6. Selected Financial Data			18
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			47
Item 8. Financial Statements and Supplementary Data			50
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			112
Item 9A. Controls and Procedures			113
Item 9B. Other Information			116
Part III.
Item 10. Directors, Executive Officers and Corporate Governance			116
Item 11. Executive Compensation			116
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			117
Item 13. Certain Relationships and Related Transactions, and Director Independence			117
Item 14. Principal Accounting Fees and Services			117
Part IV.
Item 15. Exhibits, Financial Statement Schedules			118
Signatures			125
EX-10.37
EX-12
EX-21
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I

Item 1. Business

     Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina.

     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 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, 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, Monroe, 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 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, 2009, 84% 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, interstate natural gas storage and intrastate natural gas transportation. For the year ended October 31, 2009, the earnings before taxes from our non-utility segment was 16%, which consisted of 4% from regulated non-utility activities and 12% 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 11 and Note 12, 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 on 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, 2009, 48% of our operating revenues were from residential customers, 28% from commercial customers, 10% from large volume customers, including industrial, power generation and resale customers, and 14% 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. We are also regulated by the NCUC as to the issuance of 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 and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the 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 regulations, such as those relating to employment 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 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 franchise agreements have expired as of October 31, 2009. We continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. No franchise agreements will expire during the 2010 fiscal year. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed or service continued in the ordinary course of business without the necessity of franchises with no material adverse impact on us, as most government entities do not want to prevent their citizens from having access to gas service or to interfere with our required system maintenance.

     The natural gas distribution business is seasonal in nature as variations in weather conditions 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. 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 months (principally November through March) when customer demand is higher. During the year ended October 31, 2009, the amount of natural gas in storage varied from 12.3 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 28.4 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $92.7 million to $265.4 million.

     During the year ended October 31, 2009, 123.1 million dekatherms of gas were sold to or transported for large volume customers compared with 121.6 million dekatherms in 2008. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 93.8 million dekatherms in 2009, compared with 88.7 million dekatherms in 2008. Weather, as measured by degree days, was 3% colder than normal in 2009 and 5% warmer than normal in 2008.

     The following is a five-year comparison of operating statistics for the years ended October 31, 2005 through 2009.

		2009				2008				2007				2006				2005
Operating Revenues (in thousands):
Sales and Transportation:
Residential		$	787,994			$	813,032			$	743,637			$	841,051			$	686,304
Commercial			462,160				503,317				418,426				498,956				421,499
Industrial			126,855				209,341				190,204				205,384				215,505
For Power Generation			19,609				25,266				29,135				22,963				16,248
For Resale			11,746				12,326				13,907				11,342				40,122
Total			1,408,364				1,563,282				1,395,309				1,579,696				1,379,678
Secondary Market Sales			221,300				515,968				308,904				337,278				373,353
Miscellaneous			8,452				9,858				7,079				7,654				8,060
Total		$	1,638,116			$	2,089,108			$	1,711,292			$	1,924,628			$	1,761,091
Gas Volumes — Dekatherms (in thousands):
System Throughput:
Residential			55,298				51,909				50,072				49,119				52,966
Commercial			38,526				36,766				33,647				34,476				36,000
Industrial			74,363				81,780				79,266				80,490				81,102
For Power Generation			39,639				30,875				34,096				26,099				25,591
For Resale			9,048				8,921				8,923				8,472				8,779
Total			216,874				210,251				206,004				198,656				204,438
Secondary Market Sales			46,057				53,442				42,049				40,994				47,057
Number of Retail Customers Billed (12-month average):
Residential			855,670				852,586				835,636				815,579				792,061
Commercial			94,404				94,045				93,472				92,692				91,645
Industrial			2,358				2,937				2,959				3,008				3,146
For Power Generation			20				20				15				12				16
For Resale			17				17				15				19				15
Total			952,469				949,605				932,097				911,310				886,883
Average Per Residential Customer:
Gas Used — Dekatherms			64.63				60.88				59.92				60.23				66.87
Revenue		$	920.91			$	953.61			$	889.90			$	1,031.23			$	866.48
Revenue Per Dekatherm		$	14.25			$	15.66			$	14.85			$	17.12			$	12.96
Cost of Gas (in thousands):
Natural Gas Commodity Costs		$	727,744			$	1,454,073			$	1,055,600			$	1,229,326			$	1,226,999
Capacity Demand Charges			128,081				127,640				116,977				99,333				117,287
Natural Gas Withdrawn From (Injected Into) Storage, net			126,480				(78,283	)			(12,815	)			15,709				(35,151	)
Regulatory Charges (Credits), net			94,237				32,705				27,365				56,781				(47,183	)
Total		$	1,076,542			$	1,536,135			$	1,187,127			$	1,401,149			$	1,261,952

		2009				2008				2007				2006				2005
Supply Available for Distribution (dekatherms in thousands):
Natural Gas Purchased			149,696				159,857				143,598				140,999				155,614
Transportation Gas			115,519				108,332				108,355				101,414				97,959
Natural Gas Withdrawn From (Injected Into) Storage, net			1,010				(2,980	)			(1,640	)			(197	)			856
Company Use			(283	)			(135	)			(141	)			(127	)			(133	)
Total			265,942				265,074				250,172				242,089				254,296

     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, 2009, we had contracts for the following pipeline firm transportation capacity in dekatherms per day.

Williams-Transco			632,200
El Paso-Tennessee Pipeline			74,100
Spectra-Texas Eastern (through East Tennessee and Transco)			38,000
NiSource-Columbia Gas (through Transco and Columbia Gulf)			42,800
NiSource-Columbia Gulf			10,000
ONEOK-Midwestern (through Tennessee, Columbia Gulf, East Tennessee and Transco)			120,000
Total			917,100

     As of October 31, 2009, 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.

Piedmont Liquefied Natural Gas (LNG)			278,000
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			861,800

     As of October 31, 2009, we own or have under contract 36.2 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. As part of our long-term plan 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), a storage facility in West Virginia, and 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.

     We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on our current growth projections, which indicate that we may need to resume development of the project in 2011 to prepare for construction in 2012 in order provide service in 2015. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the project when needed to meet future customer requirements. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K and Note 2 to the consolidated financial statements.

     During the year ended October 31, 2009, 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, 2009, no bypass occurred. During 2009, the City of Monroe, a wholesale customer, began construction of a pipeline to bypass our system with a direct connection to Transco. This action will have no impact on our utility margin as a result of a regulatory provision approved in our last North Carolina rate case. The future level of bypass activity cannot be predicted.

     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 continue to attract the majority of the new residential construction market on or near our distribution mains, and 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. Natural gas has historically maintained a price advantage over electricity in our service areas. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. However, 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.

     As noted above, many of our industrial 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 with natural gas historically having a price advantage over fuel oil. 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 revenues could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

     During the year ended October 31, 2009, our largest customer contributed $52.6 million, or 3.2%, of total operating revenues and less than 1% 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.

     As of October 31, 2009, our fiscal year end, we had 1,821 employees, compared with 1,833 as of October 31, 2008.

     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 Securities and Exchange Commission (SEC).

Item 1A. Risk Factors

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. 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 higher than historical levels, 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 upstream, 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, freeze off of natural gas wells, terrorist attacks or other acts of war, could reduce our normal interstate supply of gas, which could reduce our earnings. Moreover, if additional natural gas infrastructure, including but not limited to exploration and drilling 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 are facing increasing competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and, as it relates to sources of energy for electric power plants, coal. The primary competitive factor is price.

     In residential and commercial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, fuel oil and propane. 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 special competitive contracts 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 and safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of these 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 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. Any Congressional legislation or agency regulation that would alter these or other similar statutory and regulatory structures in a way to significantly raise costs that could not be recovered in rates from our customers, would reduce the availability of supply or capacity, or would reduce our competitiveness, and that could negatively impact our earnings.

Climate change legislation or regulations could increase our operating costs, negatively affecting our growth, cash flows and earnings.

     There are proposed federal legislative initiatives that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide. Regulatory agencies may also issue similar climate change regulations. These initiatives could result in various new laws or regulations. 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, when and if enacted, the final form of 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, 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 timely recover 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 approved, they are still subject to challenge for their reasonableness by various appropriate entities. Regulatory authorities may also review whether our gas cost purchases 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.

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

     Our earnings can vary from year to year, depending in part on weather conditions.

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. We estimate that 80% to 85% of our annual utility margin is collected from temperature-sensitive customers. As a result, 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 and over-the-counter 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 activities caused by accidents, work stoppage, severe weather such as a major hurricane, pandemic or acts of terrorism could adversely impact earnings.

     Inherent in our gas distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, mechanical problems and third party excavation damage. Weather events such as hurricanes, as well as acts of terrorism, can 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.

Opposition to infrastructure development may delay or prevent us from expanding our business.

     In order to serve new customers or expand our service to existing customers, we often need to expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations or LNG storage tanks. Such infrastructure development requires us to seek approval from local, state and/or federal regulatory and governmental bodies. The approval process may involve the opportunity for the public to voice

opposition. Such opposition may delay or prevent such development, or may make it materially more costly to do so. As a result, we may not be able to adequately support customer growth, which would negatively impact our earnings.

A downgrade in our credit rating 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 rating be downgraded, the interest rate on our borrowings under our revolving credit agreement would increase. An increase in borrowing costs without the recognition of 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. 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.

Changes in federal and state fiscal and monetary policy could significantly increase our costs.

     Changes in federal and state fiscal and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods and services. This could increase our expenses and decrease our earnings if such increased costs are not reflected in allowed rates charged to customers. This series of events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Any of these events may negatively affect our ability to make capital expenditures to grow the business and negatively affect earnings.

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

     Historically, we have made large capital expenditures in order to finance the expansion and upgrading of our distribution system. We have also purchased and will continue to 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 profitability. Volatility in gas prices may require us to post cash collateral as part of our regulated gas price hedging program. We have funded 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 securities in the open market. 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 and risk management programs, the reduction or elimination of the dividend payment or other discretionary uses of cash.

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.

Certain purchasers of our common stock under our dividend reinvestment and stock purchase plan (DRIP) may be entitled to rescind their purchases.

     As a result of an administrative error, sales of 568,000 shares of our common stock under the DRIP between December 1, 2008 and November 16, 2009, which represent less than 1% of our outstanding shares of common stock as of November 16, 2009, have not complied with the registration requirements of applicable securities laws, making them unregistered shares. A number of remedies may be available to DRIP participants who acquired shares during that period, including a right to rescind their purchases not later than one year after the date of the Form S-3 rescission offer to receive the full price paid by the DRIP participants, plus interest less any dividends received. DRIP participants who purchased unregistered shares pursuant to the DRIP and whose unregistered shares have fallen in value since the date of purchase could have an incentive to seek and to accept such a rescission. The sale of unregistered shares could also subject us to regulatory sanctions by the SEC or other regulatory authorities that might result in the imposition of civil penalties, which could include fines or a cease and desist order. We have reported these events and are cooperating with the relevant regulatory authorities, including the SEC and NCUC. Although we do not expect any rescissions or regulatory actions to have a material adverse effect on us, we are unable to predict the full consequences of these events and regulatory actions.

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

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

Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.

     Our costs of providing for the 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, future government regulation and our required or voluntary contributions made to the plan. A significant decline in the value of investments that fund our pension plan, if not offset or mitigated by a decline in our liabilities, may significantly differ from or alter the values and actuarial assumptions used to calculate our future pension expense. A decline in the value of these investments 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 new and existing 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 an incorrect or inadequate interpretation of these laws and regulations may lead to a failure to comply. Such a failure for this or other reasons 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.

An overall economic downturn could negatively impact our earnings.

     Weakening of economic activity in our markets could result in a loss of customers or a decline in customer additions and 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. Earnings and liquidity would be negatively affected, reducing our ability to grow the business.

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 technically skilled workforce. Without such 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.

Item 1B. Unresolved Staff Comments

     None.

Item 2. Properties

     All property included in the consolidated balance sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, 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 2,600 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 28,400 miles (three-inch equivalent) of distribution mains. The transmission pipelines and distribution mains are located on or under public streets and highways, or 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 the Robeson County LNG facility on which we deferred the development and construction in March 2009 based on revised growth projections.

     We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and district and regional offices in the locations shown below. Lease payments for these various offices totaled $5.3 million for the year ended October 31, 2009.

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

     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 residential and commercial water heaters leased to natural gas customers. The property owned by the subsidiary is real estate. None of our other subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.

Item 3. Legal Proceedings

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

Item 4. Submission of Matters to a Vote of Security Holders

     No matters were submitted to a vote of security holders during our fourth quarter ended October 31, 2009.

PART II

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

Market Information

     Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices from the NYSE Composite for each quarterly period for the years ended October 31, 2009 and 2008.

2009		High				Low
Quarter ended:
January 31		$	33.92			$	24.77
April 30			27.55				20.68
July 31			25.50				21.65
October 31			25.87				23.10

2008		High				Low
Quarter ended:
January 31		$	27.98			$	24.01
April 30			27.68				24.05
July 31			27.95				25.00
October 31			35.29				20.52

Holders

     As of December 11, 2009, our common stock was owned by 14,587 shareholders of record. A holder of record excludes the individual security owners whose shares are held in the name of an investment company.

Dividends

     The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 2009 and 2008. We expect that comparable cash dividends will continue to be paid in the future.

		Dividends Paid
2009		Per Share
Quarter ended:
January 31			26¢
April 30			27¢
July 31			27¢
October 31			27¢

		Dividends Paid
2008		Per Share
Quarter ended:
January 31			25¢
April 30			26¢
July 31			26¢
October 31			26¢

     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, 2009, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Recent Sale of Unregistered Securities

     Between December 1, 2008 and November 16, 2009, we sold 568,000 shares of common stock under our dividend reinvestment and stock purchase plan (DRIP) at prices ranging from $21.59 to $31.56. On November 16, 2009, we discovered that the offer and sale of these shares of common stock under the DRIP during this period were not registered under applicable securities laws and were not exempt from registration under those laws, making them unregistered shares. We received $13.6 million in the aggregate from these sales, which was used for financing the construction of additions to our facilities and for general corporate purposes. To ensure compliance with the Securities Act of 1933, as amended, to provide a remedy to any DRIP participant aggrieved by the failure to register and to notify DRIP participants of their rights as generally prescribed by the applicable securities laws, we intend to file a registration statement on Form S-3 to register a rescission offer to DRIP participants for the unregistered shares and to register the unregistered shares. The sale of unregistered shares could also subject us to regulatory sanctions by the Securities and Exchange Commission (SEC) or other regulatory authorities that might result in the imposition of civil penalties, which could include fines or a cease and desist order. We have reported these events and are cooperating with the relevant regulatory authorities, including the SEC and the North Carolina Utilities Commission (NCUC). Although we do not expect any rescissions or regulatory actions to have a material adverse effect on us, we are unable to predict the full consequences of these events and regulatory actions.

Share Repurchases

     The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2009.

										Total Number of				Maximum Number
		Total Number								Shares Purchased				of Shares that May
		of Shares				Average Price				as Part of Publicly				Yet be Purchased
Period		Purchased (2)				Paid Per Share				Announced Program				Under the Program (1)
Beginning of the period															6,310,074
8/1/09 - 8/31/09			—			$	—				—				6,310,074
9/1/09 - 9/30/09			6,458			$	24.24				—				6,310,074
10/1/09 - 10/31/09			—			$	—				—				6,310,074
Total			6,458			$	24.24				—

Comparisons of Cumulative Total Shareholder Returns

     The following performance graph compares our cumulative total shareholder return from October 31, 2004 through October 31, 2009 (a five-year period), with the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500) and with our utility peer group. 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 graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2004 and that all dividends were reinvested. Stock price performances shown on the graph are not indicative of future price performance.

Comparisons of Five-Year Cumulative Total Returns
Value of $100 Invested as of October 31, 2004

Item 6. Selected Financial Data

     The following table provides selected financial data for the years ended October 31, 2005 through 2009.

In thousands except per share amounts		2009				2008				2007				2006				2005
Operating Revenues		$	1,638,116			$	2,089,108			$	1,711,292			$	1,924,628			$	1,761,091
Margin (operating revenues less cost of gas)		$	561,574			$	552,973			$	524,165			$	523,479			$	499,139
Net Income		$	122,824			$	110,007			$	104,387			$	97,189			$	101,270
Earnings per Share of Common Stock:
Basic		$	1.68			$	1.50			$	1.41			$	1.28			$	1.32
Diluted		$	1.67			$	1.49			$	1.40			$	1.28			$	1.32
Cash Dividends per Share of Common Stock		$	1.070			$	1.030			$	0.990			$	0.950			$	0.905
Total Assets *		$	3,118,819			$	3,138,401			$	2,823,106			$	2,743,826			$	2,611,117
Long-Term Debt (less current maturities)		$	732,512			$	794,261			$	824,887			$	825,000			$	625,000

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

Forward-Looking Statements

     This report, as well as other documents we file with the 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 and information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to:

	•		Regulatory issues affecting us and those from whom we purchase natural gas transportation and storage service, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our ability to earn appropriate rates of return and initiate general rate proceedings as needed.
	•		Residential, commercial, industrial and power generation growth and energy consumption in our service areas. The ability to grow our customer base, the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.
	•		Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies, and we expect this competitive environment to continue.
	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.
	•		The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and the cost and availability of labor and materials. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.
	•		Access to capital markets. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets or our financial condition could affect access to and cost of capital.

	•		Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating, regulatory and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations. Since such risks may affect the availability and cost of natural gas, they also may affect the competitive position of natural gas relative to other energy sources.
	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.
	•		Changes in environmental, safety, system integrity, tax and other laws and regulations, including climate change legislation, and the cost of compliance. We are subject to extensive federal, state and local laws and regulations. Compliance with such laws and regulations could increase capital or operating costs, affect our reported earnings, increase our liabilities or change the way our business is conducted.
	•		Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.
	•		Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities, and could affect our reported earnings or increase our liabilities.
	•		Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.
	•		Changes in outstanding shares. The number of outstanding shares may fluctuate due to repurchases under our Common Stock Open Market Purchase Program or new issuances.

     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,” “will,” “assume,” “can,” “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 only 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. Please reference our website at www.piedmontng.com for current information. 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 as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Executive Overview

     Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, 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 Greenville, Monroe, 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 utility include 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, 2009, 84% 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, interstate natural gas storage and intrastate natural gas transportation. For the year ended October 31, 2009, the earnings before taxes from our non-utility segment was 16%, which consisted of 4% from regulated non-utility activities and 12% from unregulated non-utility activities. For further information on business segments, see Note 12 to the consolidated financial statements. For information about our equity method investments, see Note 11 to the consolidated financial statements.

     Our utility operations are regulated by the 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. We are also regulated by the NCUC as to the issuance of 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 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 regulations, such as those relating to employment 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 for our shareholders. 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 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 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 results in an increase in revenues when weather is warmer than normal and a decrease in 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.

     Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. Part of our strategic plan is to responsibly manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers, and the pursuit of profitable customer growth opportunities in our service areas. We strive for quality customer service by investing in technology, processes and people. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

     We seek to maintain a long-term debt-to-capitalization ratio within a range of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

     With the combination of the global recession and the movement to implement climate change policies that will impact how energy is used in this country, we are working toward a business model that positions us for long-term success in a carbon-constrained energy economy. This includes continual assessment of the nature of our business and examination of alternative cost recovery mechanisms and rate structures that are more appropriate in a changing energy economy. Additionally, we are seeking opportunities for regulatory innovation and strategic

alliances to advance our customers’ interests in energy conservation and efficiency and environmental stewardship.

     One of our 2009 objectives has been to focus on future growth opportunities in a low-carbon energy economy. We are continually reviewing our business processes for quality and efficiency with a concentration on customer-oriented process improvements. We will continue this focus to be in a position to seize future business opportunities.

     We must leverage our regulatory structure to realize future growth opportunities in a low-carbon energy economy. One example of this is our pursuit of 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 breaking the link between energy consumption and margin revenues, or decoupling as we say, utilities’ interests are aligned with customers’ interests around conservation and energy efficiency. In North Carolina, we have decoupled rates. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling with a one-year lag. In Tennessee, we have filed to decouple our rates; that filing has been contested by the state Attorney General and went to hearing on December 17 – 18, 2009.

     Even as we implement energy efficiency programs for our customers so that individual residential and business customers can save on their total natural gas bill by using natural gas as efficiently as possible, we also will continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles. Our message is simple: the expanded use of domestic natural gas can help revitalize our economy, reduce overall greenhouse gas emissions and enhance our national energy security. Recent production of domestic natural gas supplies from shale formations has resulted in an increase of supply, which in turn has contributed to a moderation in the price of gas. This price moderation, if it continues as many in the industry anticipate, should lead to an increase in the competitiveness of natural gas as compared to other fuels.

     One example is our October 2009 announcement of an agreement with Progress Energy Carolinas, Inc., a subsidiary of Progress Energy, Inc., to provide natural gas delivery service to a new power generation facility to be built at their Wayne County, North Carolina power generation site. In addition to the environmental benefits associated with using natural gas at this new plant, the construction of the natural gas pipeline for this project will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for additional economic growth and development.

     We are seeing the impacts of the economic recession in our market area with a decline in customer growth in our new construction market and continued customer conservation practices. While we have also experienced a decline in margin in our commercial and industrial markets from lower energy consumption related to company closings and reduced production and business activities, we have recently seen some rebound in these markets. As discussed above, we are positioning ourselves to capitalize on new opportunities as the economy improves.

     The decline in gross residential and commercial customer additions was 39% from 2008. To mitigate this, we are actively seeking customer conversions to natural gas in order to gain new customers outside of the new construction market.

     Earlier this year, we deferred the development and construction of our previously announced liquefied natural gas (LNG) peak storage facility in Robeson County, North Carolina based on growth projections at that time. Our current growth projections indicate that we may need to resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. With the uncertain economic outlook and recovery, we will continue to monitor customer growth trends in our markets and plan for the development of this project and other infrastructure projects when needed to meet future customer requirements.

     Under current economic conditions, it has become more difficult for some customers to pay their gas bills, leading to slower collections and higher non-gas bad debt expense. With a slower turnover of accounts receivable, our level of borrowings could increase in order to meet our working capital needs. This series of events may be mitigated by the expectation of lower gas prices for the 2009-2010 heating season as lower natural gas prices were realized in 2009.

     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 a projected rate of return greater than the returns allowed in our utility operations due to the higher 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. We have entered into an agreement to sell half of our 30% interest in SouthStar Energy Services LLC (SouthStar) to Georgia Natural Gas Company (GNGC) for $57.5 million to be effective January 1, 2010. For further information, see Note 11 to the consolidated financial statements.

Results of Operations

     The following tables present our financial highlights for the years ended October 31, 2009, 2008 and 2007.

Income Statement Components

														Percent Change
														2009 vs.				2008 vs.
In thousands except per share amounts		2009				2008				2007				2008				2007
Operating Revenues		$	1,638,116			$	2,089,108			$	1,711,292				(21.6	)%			22.1	%
Cost of Gas			1,076,542				1,536,135				1,187,127				(29.9	)%			29.4	%
Margin			561,574				552,973				524,165				1.6	%			5.5	%
Operations and Maintenance			208,105				210,757				214,442				(1.3	)%			(1.7	)%
Depreciation			97,425				93,121				88,654				4.6	%			5.0	%
General Taxes			34,590				33,170				32,407				4.3	%			2.4	%
Income Taxes			70,079				62,814				51,315				11.6	%			22.4	%
Total Operating Expenses			410,199				399,862				386,818				2.6	%			3.4	%
Operating Income			151,375				153,111				137,347				(1.1	)%			11.5	%
Other Income (Expense), net of tax			18,124				16,169				24,312				12.1	%			(33.5	)%
Utility Interest Charges			46,675				59,273				57,272				(21.3	)%			3.5	%
Net Income		$	122,824			$	110,007			$	104,387				11.7	%			5.4	%
Average Shares of Common Stock:
Basic			73,171				73,334				74,250				(0.2	)%			(1.2	)%
Diluted			73,461				73,612				74,472				(0.2	)%			(1.2	)%
Earnings per Share of Common Stock:
Basic		$	1.68			$	1.50			$	1.41				12.0	%			6.4	%
Diluted		$	1.67			$	1.49			$	1.40				12.1	%			6.4	%

Gas Deliveries, Customers, Weather Statistics and Number of Employees

														Percent Change
														2009 vs.				2008 vs.
		2009				2008				2007				2008				2007
Deliveries in Dekatherms (in thousands):
Sales Volumes			110,379				110,801				105,606				(0.4	)%			4.9	%
Transportation Volumes			106,495				99,450				100,398				7.1	%			(0.9	)%
Throughput			216,874				210,251				206,004				3.2	%			2.1	%
Secondary Market Volumes			46,057				53,442				42,049				(13.8	)%			27.1	%
Customers Billed (at period end)			937,962				935,724				922,961				0.2	%			1.4	%
Gross Customer Additions			12,608				20,506				30,437				(38.5	)%			(32.6	)%
Degree Days
Actual			3,413				3,195				2,977				6.8	%			7.3	%
Normal			3,324				3,358				3,388				(1.0	)%			(0.9	)%
Percent colder (warmer) than normal			2.7	%			(4.9	)%			(12.1	)%			n/a				n/a
Number of Employees (at period end)			1,821				1,833				1,876				(0.7	)%			(2.3	)%

Net Income

     Net income increased $12.8 million in 2009 compared with 2008 primarily due to the following changes which increased net income:

•

$12.6 million decrease in utility interest charges.

•

$8.6 million increase in margin (operating revenues less cost of gas).

•

$5.7 million increase in income from equity method investments.

•

$2.7 million decrease in operations and maintenance expenses.

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

•

$8.4 million increase in income taxes.

•

$4.3 million increase in depreciation.

•

$2.7 million decrease in net other income (expense) items.

•

$1.4 million increase in general taxes.

     Net income increased $5.6 million in 2008 compared with 2007 primarily due to the following changes which increased net income:

•

$28.8 million increase in margin.

•

$3.7 million decrease in operations and maintenance expenses, primarily due to lower pension expense accruals due to the restructuring of our defined benefit pension program.

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

•

$9.4 million decrease in earnings from equity method investments.

•

$7.9 million increase in income taxes.

•

$4.5 million increase in depreciation.

•

$2.3 million decrease in net other income (expense) items.

•

$2 million increase in utility interest charges.

•

$.8 million increase in general taxes.

Operating Revenues

     Operating revenues in 2009 decreased $451 million compared with 2008 primarily due to the following decreases:

•

$294.7 million from revenues in secondary market transactions due to decreased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

•

$112.1 million primarily from lower gas costs passed through to sales customers.

•

$19.4 million from revenues under the margin decoupling mechanism. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to conservation and weather.

•

$12.7 million of commodity gas costs from decreased volume deliveries to sales customers.

•

$8 million from revenues under the WNA in South Carolina and Tennessee.

•

$5.4 million from a decrease in volumes delivered to transportation customers other than power generation.

     Operating revenues in 2008 increased $377.8 million compared with 2007 primarily due to the following increases:

•

$207.1 million from revenues in secondary market transactions due to increased activity and higher gas costs.

•

$143.7 million primarily from increased commodity and demand costs passed through to sales customers.

•

$29.3 million of commodity gas costs from higher volume deliveries to sales customers.

     These increases were partially offset by a $7.3 million decrease from revenues under the margin decoupling mechanism.

Cost of Gas

     Cost of gas in 2009 decreased $459.6 million compared with 2008 primarily due to the following decreases:

•

$294.2 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

•

$127.2 million primarily from lower gas costs passed through to sales customers.

•

$12.7 million of commodity gas costs from decreased volume deliveries to sales customers.

     Cost of gas in 2008 increased $349 million compared with 2007 primarily due to the following increases:

•

$207.7 million from commodity gas costs in secondary market transactions due to increased activity and higher gas costs.

•

$111.9 million from increased commodity and demand costs passed through to sales customers.

•

$29.3 million of commodity gas costs from higher volume deliveries to sales customers.

     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.

Margin

     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 impact of volatile wholesale commodity

prices, which accounts for 52% of revenues for the twelve months ended October 31, 2009, and transportation and storage costs, which account for 8%.

     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 (RSA) in South Carolina, secondary market activity in North Carolina and South Carolina, the Tennessee Incentive Plan (TIP) in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the collection 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 $8.6 million in 2009 compared with 2008 primarily due to an increase of $15.7 million from increased rates approved in the North Carolina general rate case effective November 1, 2008.

     This increase was partially offset by the following decreases:

•

$4.7 million from net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost reviews.

•

$2.9 million from decreased volumes delivered to industrial customers.

     Margin increased $28.8 million in 2008 compared with 2007 primarily due to the following increases:

•

$12.8 million from period to period net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews.

•

$11.3 million from growth in our residential and commercial customer base.

•

$5.4 million from the regulatory ruling that discontinued the capitalizing and amortizing of storage demand charges effective November 1, 2007.

     These increases were partially offset by a $.9 million decrease from lower sales volumes in our power generation market.

Operations and Maintenance Expenses

     Operations and maintenance expenses decreased $2.7 million in 2009 compared with 2008 primarily due to the following decreases:

•

$3.6 million in employee benefits expense due to reductions in pension expense resulting from changes in the discount rate and plan design, regulatory deferral of the Tennessee portion of the annual plan funding and lower group insurance expense from

claims experience, and fewer employees.

•

$1.4 million in contract labor for contract billing services, telecom and financial, gas accounting and compliance systems.

     These decreases were partially offset by an increase of $2.7 million in regulatory amortization expense.

     Operations and maintenance expenses decreased $3.7 million in 2008 compared with 2007 primarily due to the following decreases:

•

$9.1 million in employee benefits expense due to reductions in pension expense resulting from changes in plan design and lower group insurance expense from claims experience, and fewer employees.

•

$1 million in office supplies due to customer billing outsourcing which resulted in reduced postage and billing supply expenses.

•

$.6 million in transportation costs primarily due to fewer vehicles being used as a result of our automated meter reading initiative and other fleet management efforts.

     These decreases were partially offset by the following increases:

•

$3.6 million in payroll expense primarily due to an increase in long-term incentive plan accruals in 2008 because of a higher share price and performance levels, partially offset by the impact of fewer employees.

•

$2.3 million in contract labor primarily due to contract billing services, telecom and financial, gas accounting and compliance systems.

•

$.5 million in utilities primarily due to increased charges for measurement systems.

•

$.5 million in advertising.

Depreciation

     Depreciation expense increased from $88.7 million to $97.4 million over the three-year period 2007 to 2009 primarily due to increases in plant in service.

General Taxes

     General taxes increased $1.4 million in 2009 compared with 2008 primarily due to increases in property taxes related to a larger property tax base and reassessments.

     General taxes increased $.8 million in 2008 compared with 2007 primarily due to the following changes:

•

$.6 million increase in property taxes related to a refund for South Carolina taxes in the prior year.

•

$.4 million increase in gross receipts taxes in Tennessee.

•

$.2 million decrease in payroll taxes primarily related to organizational restructuring and process improvement initiatives that began in 2007, partially offset by an increase in the social security wage limit.

Other Income (Expense)

     Other Income (Expense) is comprised of income from equity method investments, 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, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of other miscellaneous expenses.

     The primary changes to Other Income (Expense) were in income from equity method investments discussed below. All other changes were not significant.

     Income from equity method investments increased $5.7 million in 2009 compared with 2008 primarily due to an increase of $6.3 million in earnings from SouthStar largely due to higher contributions from the management of storage and transportation assets, margin impacts from lower of cost or market inventory adjustments, higher operating margins in Ohio, a 2008 pricing settlement with the Georgia Public Service Commission (Georgia PSC) and increased average customer usage, partially offset by a change in retail pricing plan mix and a decrease in the average number of customers.

     Income from equity method investments decreased $9.4 million in 2008 compared with 2007 primarily due to the following changes:

•

$9.9 million decrease in earnings from SouthStar primarily due to lower of cost or market inventory adjustments, lower contributions from the management of storage and transportation assets, a loss on weather derivatives and a Georgia PSC consent agreement related to retail pricing.

•

$.9 million increase in earnings from Hardy Storage Company, LLC (Hardy Storage) primarily due to its first full year of operations, partially offset by higher operations and maintenance expenses, depreciation and general taxes.

Utility Interest Charges

     Utility interest charges decreased $12.6 million in 2009 compared with 2008 primarily due to the following changes:

•

$9.1 million decrease in net interest expense due to an increase in interest earned on amounts due from customers in the current period.

•

$4.7 million decrease in interest on short-term debt primarily due to the average interest rates during the current period being 290 basis points lower than the prior year period even though borrowings were higher in the current period.

•

$1.7 million increase in the allowance for borrowed funds.

     Utility interest charges increased $2 million in 2008 compared with 2007 primarily due to the following changes:

•

$2.7 million increase in regulatory interest expense primarily due to interest true-ups related to amounts due to customers.

•

$.3 million increase in interest on short-term debt due to higher balances outstanding.

•

$.9 million decrease in interest expense related to a federal tax audit settlement in 2007.

•

$.3 million decrease in interest on regulatory treatment of certain components of deferred income taxes.

Financial Condition and Liquidity

     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. Even though we have been operating in tighter credit markets for over a year, we believe that these sources, including amounts available to us under our existing credit facility, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions and dividend payments.

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 resulting from such factors as 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 in storage and the collection of amounts billed to customers during the winter heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for 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 volatility in the price of natural gas, which is a function of market fluctuations in the price 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/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 economic recession, we may incur additional bad debt expense during the winter heating season, 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, will significantly mitigate the impact these factors may have on our results of operations.

     Net cash provided by operating activities was $344.3 million in 2009, $69.2 million in 2008 and $233.5 million in 2007. Net cash provided by operating activities reflects a $12.8 million increase in net income for 2009 compared with 2008. The effect of changes in working capital on net cash provided by operating activities is described below:

•

Trade accounts receivable and unbilled utility revenues decreased $29.3 million in the current period primarily due to the decrease in unbilled volumes and amounts billed to customers reflecting lower gas costs in 2009 as compared with 2008, partially offset by weather in the current period being 7% colder than the same prior period. Volumes sold to residential and commercial customers increased 5.1 million dekatherms as compared with the same prior period primarily due to the colder weather. Total throughput increased 6.6 million dekatherms as compared with the same prior period.

•

Net amounts due from customers increased $14.4 million in the current period primarily resulting from realized and unrealized losses on hedging activities, partially offset by decreases for gas cost differences deferred and the impact of the decrease in amounts recorded under the margin decoupling mechanism.

•

Gas in storage decreased $86.7 million in the current period primarily due to a decrease in the average cost of gas in storage as well as decreased volumes in storage in 2009 as compared with 2008.

•

Prepaid gas costs decreased $37.2 million in the current period primarily due to the lower average cost of gas in prepaid storage. Prepaid gas costs represent purchases of gas during the summer months under gas supply contracts that are not available for sale, and therefore not recorded in inventory, until the winter heating season.

•

Trade accounts payable decreased $25.4 million in the current period primarily due to gas purchases at lower costs during the fourth quarter.

     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 $1.2 million in 2009, and charges of $6.8 million in 2008 and $6.4 million in 2007. 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 increased margin by $6 million in 2009, $25.4 million in 2008 and $32.7 million in 2007. 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.

     In July 2009, we reached an agreement with GNGC to sell half of our 30% membership interest in SouthStar to GNGC, effective January 1, 2010, retaining a 15% earnings and membership share in SouthStar after the sale. Currently, earnings and losses are allocated to us at 25% with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our membership percentage of 30%. At closing, we will receive $57.5 million from GNGC resulting in an estimated after-tax gain of $30 million in 2010, or $.42 per diluted share. The agreement was approved by the Georgia PSC in October 2009.

Cash Flows from Investing Activities. Net cash used in investing activities was $129.6 million in 2009, $177.4 million in 2008 and $148.2 million in 2007. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures were $129 million in 2009, a 29% decrease from the $181 million in 2008, primarily due to lower system infrastructure investments consistent with slower customer growth.

     We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $195.4 million are budgeted for 2010. The $195.4 million includes $46.3 million in capital expenditures, largely deferred from 2009, for pipeline infrastructure to serve two gas-fired

power generation projects in North Carolina. We are not contractually obligated to expend capital until the work is completed. Even though we are seeing a slower pace of core residential and commercial customer growth in our service territory due to the downturn in the housing market and other economic factors, significant utility construction expenditures are expected to continue to meet long-term growth and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

     We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on our current growth projections, which indicate that we may need to resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. This LNG peak storage facility, with an intended capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand, is part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand. We intend to design, construct, own and operate this facility as a regulated utility project. Preliminary estimates place the cost of the facility in the $300 million to $350 million range, with $5.2 million incurred in fiscal year 2009. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the Robeson project when needed to meet future customer requirements.

     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, which is subject to NCUC approval, calls for us to construct 38 miles of 20-inch transmission pipeline along with additional compression facilities to provide natural gas delivery service to the plant by July 2012. Our investment in the pipeline and compression facilities is estimated at $85 million and is supported by a long-term service agreement. We anticipate making the capital expenditures related to the project during 2011 and 2012. 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 as much as $39.2 million to expand its system. As a 22% equity venture partner of Cardinal, we will invest as much as $8.7 million in Cardinal’s system expansion.

     During 2007, $2.2 million of supplier refunds was recorded as restricted cash. In 2008, restrictions on cash totaling $2.2 million were removed pursuant to a 2007 NCUC order, and we liquidated all certificates of deposit and similar investments that held any supplier refunds due to customers and transferred these funds upon maturity to the North Carolina deferred account.

     In 2009 and 2008, we contributed $.9 million and $10.9 million, respectively, to our Hardy Storage joint venture as part of our equity contribution for construction of the FERC regulated interstate storage facility.

     During 2008, we sold various properties located in Burlington and High Point, North Carolina, Spartanburg, South Carolina and Nashville, Tennessee for $13.2 million, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land from these sales as a pre-tax gain of $1.2 million with a deferral of $.5 million related to the Nashville sale. The net pre-tax gain of $.7 million was recorded in “Other Income (Expense)” in the consolidated statements of income. We recorded a gain of $3.1 million on the disposition of the buildings as a charge to “Accumulated depreciation” in the consolidated balance sheets. We

entered into a sale-leaseback agreement on the Nashville property for a lease of 18 ¹/2 months, where the $.5 million deferred gain will be amortized on a straight-line basis over the life of the lease and recorded to “Other Income (Expense)” in the consolidated statements of income. During 2009 and 2008, we recorded amortization of the deferred gain of $309,088 and $38,636, respectively.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was ($214.1) million in 2009, $107.7 million in 2008 and ($86.6) million in 2007. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock purchase plans, net of purchases under the common stock repurchase program. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term bank borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of October 31, 2009, our current assets were $513.1 million and our current liabilities were $600.2 million, primarily due to seasonal requirements as discussed above.

     As of October 31, 2009, we had committed lines of credit of $450 million with the ability to expand up to $600 million under our syndicated credit facility that expires April 2011 to meet working capital needs. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. Outstanding short-term bank borrowings decreased from $406.5 million as of October 31, 2008 to $306 million as of October 31, 2009 primarily due to lower commodity gas costs and lower interest payments for short-term debt. During the twelve months ended October 31, 2009, short-term bank borrowings ranged from $131.5 million to $556.5 million, and interest rates ranged from .50% to 2.84% (weighted average of .85%).

     Effective December 3, 2008, we entered into a syndicated seasonal credit facility with aggregate commitments totaling $150 million. Advances under this seasonal facility bore interest at a rate based on the 30-day LIBOR rate plus from 75 to 175 basis points, based on our credit ratings. This seasonal credit facility expired on March 31, 2009. We entered into this facility to provide lines of credit in addition to the syndicated credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements and general corporate needs. This seasonal credit facility replaced the two short-term credit facilities with banks for unsecured commitments totaling $75 million that were effective from October 27 and 29, 2008 through December 3, 2008.

     As of October 31, 2009, we had available letters of credit of $5 million under our syndicated credit facility, of which $2.4 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. As of October 31, 2009, unused lines of credit available under our syndicated credit facility, including the issuance of the letters of credit, totaled $141.6 million.

     The level of short-term bank borrowings can vary significantly due to changes in the wholesale prices of natural gas, the level of purchases of natural gas supplies for storage and hedging transactions 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.

     At this time, we do not anticipate issuing long-term debt in fiscal 2010, but intend to issue up to $125 million in long-term debt in fiscal 2011 for general operating purposes. The timing of this issuance has not yet been determined. We will continue to monitor customer growth trends 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.

     In September 2009, the balance of $30 million of our 7.35% medium-term notes became due and was retired. The balance of $60 million of our 7.8% medium-term notes becomes due in September 2010.

     We had a shelf registration statement filed with the SEC that expired on December 1, 2008 that could have been used for the issuance of either debt or equity. The remaining balance of unused long-term financing available under this shelf registration statement as of October 31, 2008 was $109.4 million.

     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 5 to the consolidated financial statements. On March 6, 2009, the Board of Directors authorized the consolidation of these programs and the repurchase of up to an additional four million shares. Upon this authorization, 7,010,074 shares were available for repurchase. Upon repurchase, such shares will be cancelled and become authorized shares available for issuance.

     On March 20, 2009, through an ASR agreement with an investment bank, we repurchased and retired 700,000 shares of common stock for $18.4 million, leaving a balance of 6,310,074 shares in the Common Stock Open Market Purchase Program. On April 21, 2009, final settlement of the transaction occurred, and we received cash of $.6 million from the investment bank. During 2008 and 2007, 1.6 million shares and 2 million shares were repurchased for $42.7 million and $54.2 million, respectively. We anticipate repurchasing 1.8 million shares of common stock through an ASR agreement in our fiscal year 2010.

     During 2009, we issued $14.4 million of common stock through dividend reinvestment and stock purchase and employee stock purchase plans. As a result of an administrative error, we received $13.2 million from December 1, 2008 through October 31, 2009 from the sale of shares of common stock under our dividend reinvestment and stock purchase plan that were from unregistered shares. To ensure compliance with the Securities Act of 1933, as amended, to provide a remedy to any participant aggrieved by the failure to register and to notify participants of their rights as generally prescribed by the applicable securities laws, we intend to file a registration statement on Form S-3 to register a rescission offer to dividend reinvestment and stock purchase plan participants for the unregistered shares and to register the unregistered shares. For further information, see Note 5 to the consolidated financial statements.

     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 2009, 2008 and 2007. Dividends of $78.4 million, $75.5 million and $73.6 million for 2009, 2008 and 2007, 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, 2009, our retained earnings were not restricted. On December 17, 2009, the Board of Directors declared a quarterly dividend on common stock of $.27 per share, payable January 15, 2010 to shareholders of record at the close of business on December 28, 2009. For further information, see Note 3 to the consolidated financial statements.

     Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. As of October 31, 2009, our capitalization, including current maturities of long-term debt, consisted of 46% in long-term debt and 54% in common equity.

     The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2009 and 2008 are summarized in the table below.

		October 31								October 31
In thousands		2009				Percentage				2008				Percentage
Short-term debt		$	306,000				15	%		$	406,500				19	%
Current portion of long-term debt			60,000				3	%			30,000				1	%
Long-term debt			732,512				36	%			794,261				38	%
Total debt			1,098,512				54	%			1,230,761				58	%
Common stockholders’ equity			927,948				46	%			887,244				42	%
Total capitalization (including short-term debt)		$	2,026,460				100	%		$	2,118,005				100	%

     Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:

•

Ratio of total debt to total capitalization, including balance sheet leverage,

•

Ratio of net cash flows to capital expenditures,

•

Funds from operations interest coverage,

•

Ratio of funds from operations to average total debt,

•

Pension liabilities and funding status, and

•

Pre-tax interest coverage.

     Qualitative factors include, among other things:

•

Stability of regulation in the jurisdictions in which we operate,

•

Consistency of our earnings over time,

•

Risks and controls inherent in the distribution of natural gas,

•

Predictability of cash flows,

•

Quality of business strategy and management,

•

Corporate governance guidelines and practices,

•

Industry position, and

•

Contingencies.

     As of October 31, 2009, 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 (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. 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, 2009, there has been no event of default giving rise to acceleration of our debt.

     The default provisions of our senior notes include:

•

Failure to make principal, interest or sinking fund payments,

•

Interest coverage of 1.75 times,

•

Total debt cannot exceed 70% of total capitalization,

•

Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total company capitalization,

•

Failure to make payments on any capitalized lease obligation,

•

Bankruptcy, liquidation or insolvency, and

•

Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal.

     The default provisions of our medium-term notes are:

•

Failure to make principal, interest or sinking fund payments,

•

Failure after the receipt of a 90-day notice to observe or perform for any covenant or agreement in the notes or in the indenture under which the notes were issued, and

•

Bankruptcy, liquidation or insolvency.

Contractual Obligations and Commitments

     We have incurred various contractual obligations and commitments in the normal course of business. As of October 31, 2009, our estimated recorded and unrecorded contractual obligations are as follows.

		Payments Due by Period
		Less than				1-3				4-5				After
In thousands		1 year				Years				Years				5 Years				Total
Recorded contractual obligations:
Long-term debt (1)		$	60,000			$	60,000			$	100,000			$	572,512			$	792,512
Short-term debt (2)			306,000				—				—				—				306,000
Uncertain income tax obligations (3)			293				—				—				—				293
Total		$	366,293			$	60,000			$	100,000			$	572,512			$	1,098,805

		Less than				1-3				4-5				After
In thousands		1 year				Years				Years				5 Years				Total
Unrecorded contractual obligations and commitments: (1)
Pipeline and storage capacity (2)		$	151,370			$	392,726			$	134,333			$	261,694			$	940,123
Gas supply (3)			14,929				191				—				—				15,120
Interest on long-term debt (4)			54,443				139,560				81,699				573,068				848,770
Telecommunications and information technology (5)			15,660				7,366				—				—				23,026
Qualified and nonqualified pension plan funding (6)			22,704				34,721				11,438				—				68,863
Postretirement benefits plan funding (6)			2,700				4,800				1,500				—				9,000
Operating leases (7)			5,008				12,515				7,886				1,984				27,393
Other purchase obligations (8)			8,084				—				—				—				8,084
Letters of credit (9)			2,714				8,142				5,428				—				16,284
Total		$	277,612			$	600,021			$	242,284			$	836,746			$	1,956,663

Off-balance Sheet Arrangements

     We have no off-balance sheet arrangements other than operating leases, letters of credit and the credit extended by our counterparty in over-the-counter (OTC) derivative contracts. The letters of credit and operating leases are discussed in Note 4 and Note 7, respectively, to the consolidated financial statements and are reflected in the table above. The credit extended by our counterparty in OTC derivative contracts is discussed in Note 6 to the consolidated financial statements.

     Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million as of October 31, 2009 and 2008. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 11 to the consolidated financial statements.

Critical Accounting Estimates

     We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions 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. Regulatory assets as of October 31, 2009 and 2008, totaled $337.5 million and $263.2 million, respectively. Regulatory liabilities as of October 31, 2009 and 2008, totaled $409.3 million and $383.7 million, respectively. The detail of these regulatory assets and liabilities is presented in Note 1.B 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 or margin decoupling mechanism, our operating revenues in 2009, 2008 and 2007 would have been lower by $4.8 million, $32.2 million and $39.1 million, respectively.

     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, 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. For eligible employees hired on or before December 31, 2007 (December 31, 2008 for employees covered under the bargaining unit contract in Nashville, Tennessee), we have a traditional defined benefit pension plan, which was amended to close the plan to employees hired after December 31, 2007 (December 31, 2008 for employees covered under the bargaining unit contract in Nashville, Tennessee) and to modify how benefits are accrued. We also provide certain postretirement health care and life insurance benefits to eligible employees. For further information and our reported costs of providing these benefits, see Note 8 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.

     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 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 8.15% in 2008 to 5.99% in 2009. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 8.46% in 2008 to 5.28% in 2009. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 8.5% in 2008 to 5.58% in 2009. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we changed the initial health care cost trend rate assumed for next year from 8.25% in 2008 to 8% in 2009, declining gradually to 5% in 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. The expected long-term rate of return on plan assets was 8.5% in 2007 and 8% in 2008 and 2009. Based on a fairly stagnant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.99% in 2007, decreasing to 3.97% in 2008 and decreasing to 3.92% in 2009 due to changes in the demographics of the participants.

     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.

		Change in				Impact on 2009				Impact on Projected
Actuarial Assumption		Assumption				Benefit Cost				Benefit Obligation
						Increase (Decrease)
						In thousands
Discount rate			(.25	)%		$	62			$	4,783
Rate of return on plan assets			(.25	)%			523				N/A
Rate of increase in compensation			.25	%			235				2,495

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

						Impact on 2009				Impact on Accumulated
		Change in				Postretirement				Postretirement Benefit
Actuarial Assumption		Assumption				Benefit Cost				Obligation
						Increase (Decrease)
						In thousands
Discount rate			(.25	)%		$	5			$	798
Rate of return on plan assets			(.25	)%			37				N/A
Health care cost trend rate			.25	%			16				244

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

Gas Supply and Regulatory Proceedings

     In recent years, we have sought to diversify our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have 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. We have firm, long-term market-area storage service in West Virginia from Hardy Storage, a venture in which we have a 50% equity interest in the project which is more fully discussed in Note 11 to the consolidated financial statements.

     We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on revised growth projections and the economic downturn. Based on our current growth projections, we may resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the project when needed to meet future customer requirements.

     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, which is subject to NCUC approval, calls for us to construct 38 miles of 20-inch transmission pipeline along with additional compression facilities to provide natural gas delivery service to the plant by July 2012. Our investment in the pipeline and compression facilities is estimated at $85 million and is supported by a long-term service agreement. We anticipate making the capital expenditures related to the project during 2011 and 2012. To provide the additional delivery service, we have executed an agreement with Cardinal pipeline to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend as much as $39.2 million to expand its system. As a 22% equity venture partner of Cardinal, we will invest as much as $8.7 million in Cardinal’s system expansion. For further information on our equity venture, see Note 11 to the consolidated financial statements. This project will increase our natural gas infrastructure in the eastern part of North Carolina and will enhance future opportunities for economic growth and development.

     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. A sharing mechanism is in effect where 75% of any margin is passed through to customers in all of our jurisdictions. However, secondary market transactions in Tennessee are included in the TIP discussed in Note 2 to the consolidated financial statements.

     We entered into a stipulation and agreement with FERC’s Office of Enforcement regarding certain instances of alleged non-compliance with FERC’s capacity release regulations regarding posting and bidding requirements for short-term releases. The agreement was approved by the FERC and required us, among other matters, to pay a civil penalty in settlement of the matter. The penalty, which was paid in July 2009, did not have a material effect on our financial position, cash flows or results of operations.

     In October 2008, the NCUC approved a settlement in our general rate case proceeding that provided an annual revenue increase of $15.7 million and the continuation of the margin decoupling mechanism. The new rates became effective November 1, 2008. Also in October 2008, the PSCSC issued an order approving a settlement that provided for an annual decrease of $1.5 million in margin under the RSA mechanism based on a return on equity of 11.2%, effective November 1, 2008. In October 2009, the PSCSC issued an order approving a settlement that provides for an annual increase in margin of $1.1 million based on a return on equity of 11.2%, effective November 1, 2009.

     In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy efficiency programs to residential and commercial customers that are designed to promote energy conservation and efficiency. These programs are similar to approved energy efficiency programs in North Carolina. For further information on these programs, see the discussion in Note 2 to the consolidated financial statements.

     In July 2009, we filed a petition with the TRA requesting approval to decouple residential rates in Tennessee and to offer three energy efficiency programs to residential customers. We are proposing a margin decoupling tracker mechanism that is designed to allow us to recover from our residential customers the approved per customer margin as approved in our last general rate proceeding. The proposed energy efficiency programs in Tennessee are designed to promote energy conservation and efficiency by residential customers and are similar to approved energy efficiency programs in North Carolina. A hearing on our requests was held on December 17-18, 2009. We are unable to predict the outcome of this proceeding at this time.

     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.

Equity Method Investments

     For information about our equity method investments, see Note 11 to the consolidated financial statements.

Environmental Matters

     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 7 to the consolidated financial statements.

Accounting Guidance

     We adopted the Financial Accounting Standards Board (FASB) guidance related to the FASB Accounting Standards Codification (ASC) and the Hierarchy of Generally Accepted Accounting Principles (GAAP). This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are prepared in conformity with GAAP in the United States of America. This statement replaces prior guidance related to the hierarchy of GAAP and establishes the FASB ASC as the source of authoritative accounting principles by the FASB. Rules and interpretative releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for all SEC registrants. The adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

     In September 2006, the FASB issued guidance related to fair value measurements and disclosures. In November 2007, the FASB delayed the implementation of the fair value guidance for one year only for other nonfinancial assets and liabilities. This guidance provided enhanced direction for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. We adopted the fair value guidance on November 1, 2008 for our financial assets and liabilities, which consist primarily of derivatives that we record on the consolidated balance sheets in accordance with derivative accounting standards. We adopted the additional fair value guidance on November 1, 2009 for our nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis, such as the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests. The adoption of the fair value guidance for our financial assets and liabilities had no impact on our financial position, results of operations or cash flows. For additional information regarding fair value measurements, see Note 6 to the consolidated financial statements.

     In February 2007, the FASB issued guidance related to the fair value measurement of financial instruments that provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial

instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although the guidance related to the fair value measurement of financial instruments does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. This guidance is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has elected also to apply the fair value guidance early. Accordingly, we adopted guidance related to the fair value measurement of selected financial assets and liabilities for our fiscal year beginning November 1, 2008 and did not elect the option to measure any applicable financial assets or liabilities at fair value pursuant to those provisions.

     In April 2007, the FASB issued guidance related to “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contracts with the term derivative instruments. The new guidance permits a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. The guidance is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to the new guidance for our fiscal year beginning November 1, 2008. Our policy has been to present our positions, exclusive of any receivable or payable, with the same counterparty on a net basis; however, we elected “not to net” under the new guidance and have reflected reclassifications on our statement of financial position.

     In December 2007, the FASB issued new accounting guidance related to business combinations which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. This guidance changes the accounting for business combinations in various areas, including contingency consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of this guidance to any acquisitions we may complete after November 1, 2009.

     In March 2008, the FASB issued guidance related to disclosures about derivative instruments and hedging activities by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but without changing the scope or accounting under derivatives and hedging and the related accounting interpretations. The guidance requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. The guidance also amended the disclosure requirements to clarify that derivative instruments are subject to concentration-of-credit-risk disclosures. The guidance is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. We adopted the new guidance on February 1, 2009. Since only additional disclosures concerning derivatives and hedging activities were required, there was no impact on our financial position, results of operations, or cash flows.

     In December 2008, the FASB issued new accounting guidance for employers’ disclosures about plan assets of defined benefit pension and other postretirement plans. This guidance requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by the fair value guidance. The guidance is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since only additional disclosures about plan assets of defined benefit pension and other postretirement plans are required, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance on benefit plan assets during our fiscal year ending October 31, 2010.

     In April 2009, the FASB issued additional guidance related to interim disclosures about fair values of financial instruments that requires publicly traded companies to disclose the fair value of financial instruments during interim reporting in addition to the information provided annually. The guidance was effective for periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the guidance for our quarter ended April 30, 2009. The adoption had no impact on our consolidated financial statements. Comparative information is not required at initial adoption. The disclosure requirements are presented in “Fair Value Measurements” in Note 6 to the consolidated financial statements.

     Also in April 2009, the FASB issued guidance for determining fair value when the volume and level of activity for the asset or liability have significantly decreased and identifying transactions that are not orderly. We adopted the guidance effective for our quarter ended April 30, 2009, as concurrent adoption is required with the early adoption of the interim reporting fair value disclosure guidance. The adoption had no impact on our consolidated financial statements.

     In May 2009, the FASB issued new guidance related to management’s review of subsequent events. The guidance is effective for interim and annual periods ending after June 15, 2009. We adopted the guidance for the period ended July 31, 2009. This guidance establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before the date that the financial statements are issued or are available to be issued. It requires disclosure of the date through which an entity has evaluated subsequent events. Such disclosure is included in Note 15 to the consolidated financial statements. It had no impact on our financial position, results of operations or cash flows as the result of our evaluation.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

     We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage market risk and credit risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy 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.

Credit Risk

     We enter into contracts with third parties to buy and sell natural gas. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. The policy specifies limits on the contract amount and duration based on the counterparty’s credit rating. The policy is also designed to mitigate credit risks through a requirement for credit enhancements that include letters of credit or parent guaranties. 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 exposure to the risk of non-payment of utility bills by 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 those customers that do not satisfy our predetermined credit standards. 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.

Interest Rate Risk

     We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of October 31, 2009, 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, 2009, we had $306 million of short-term debt outstanding under our syndicated credit facility at an interest rate of .5%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $3 million during 2009.

     As of October 31, 2009, information about our long-term debt is presented below.

																														Fair Value as
		Expected Maturity Date																												of October 31,
In millions		2010				2011				2012				2013				2014				Thereafter				Total				2009
Fixed Rate Long-term Debt		$	60			$	60			$	—			$	—			$	100			$	572.5			$	792.5			$	910.3
Average Interest Rate			7.80	%			6.55	%			—	%			—	%			5.00	%			6.92	%			6.72	%

Commodity Price Risk

     We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. 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 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.

     Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. Costs have never been disallowed on the basis of prudence in any jurisdiction.

Weather Risk

     We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. 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 in our residential and commercial markets. In North Carolina, we manage our weather risk through a 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.

Item 8. Financial Statements and Supplementary Data

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2009, 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, 2009, 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, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina
December 23, 2009

Consolidated Balance Sheets
October 31, 2009 and 2008

ASSETS

In thousands		2009				2008
Utility Plant:
Utility plant in service		$	3,071,742			$	2,997,186
Less accumulated depreciation			862,079				813,822
Utility plant in service, net			2,209,663				2,183,364
Construction work in progress			87,978				57,470
Plant held for future use			6,751				—
Total utility plant, net			2,304,392				2,240,834
Other Physical Property, at cost (net of accumulated depreciation of $2,497 in 2009 and $2,351 in 2008)			719				864
Current Assets:
Cash and cash equivalents			7,558				6,991
Trade accounts receivable (less allowance for doubtful accounts of $990 in 2009 and $1,066 in 2008)			70,979				82,346
Income taxes receivable			44,413				731
Other receivables			4,712				393
Unbilled utility revenues			33,925				51,819
Inventories:
Gas in storage			103,584				190,275
Materials, supplies and merchandise			5,262				6,524
Gas purchase options, at fair value			2,559				22,645
Amounts due from customers			196,130				181,745
Prepayments			43,930				79,831
Other			96				96
Total current assets			513,148				623,396
Noncurrent Assets:
Equity method investments in non-utility activities			104,430				99,214
Goodwill			48,852				48,852
Marketable securities, at fair value			441				—
Overfunded postretirement asset			—				6,797
Regulatory asset for postretirement benefits			76,905				28,732
Gas purchase options, at fair value			—				32,434
Unamortized debt expense			9,177				9,915
Regulatory cost of removal asset			16,293				6,398
Other			44,462				40,965
Total noncurrent assets			300,560				273,307
Total		$	3,118,819			$	3,138,401

See notes to consolidated financial statements.

Consolidated Balance Sheets
October 31, 2009 and 2008

CAPITALIZATION AND LIABILITIES

In thousands		2009				2008
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized		$	—			$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 73,266 in 2009 and 73,246 in 2008			471,569				471,565
Paid-in capital			—				763
Retained earnings			458,826				414,246
Accumulated other comprehensive income (loss)			(2,447	)			670
Total stockholders’ equity			927,948				887,244
Long-term debt			732,512				794,261
Total capitalization			1,660,460				1,681,505
Current Liabilities:
Current maturities of long-term debt			60,000				30,000
Notes payable			306,000				406,500
Trade accounts payable			67,010				91,142
Other accounts payable			48,431				45,148
Income taxes accrued			—				4,414
Accrued interest			21,294				22,777
Customers’ deposits			25,202				23,881
Deferred income taxes			14,138				6,878
General taxes accrued			19,993				18,932
Gas purchase options, at fair value			30,603				42,205
Other			7,540				12,300
Total current liabilities			600,211				704,177
Noncurrent Liabilities:
Deferred income taxes			377,562				305,362
Unamortized federal investment tax credits			2,422				2,626
Regulatory liability for postretirement benefits			—				372
Accumulated provision for postretirement benefits			31,641				16,257
Cost of removal obligations			408,955				367,450
Gas purchase options, at fair value			—				22,177
Other			37,568				38,475
Total noncurrent liabilities			858,148				752,719
Commitments and Contingencies (Note 7)
Total		$	3,118,819			$	3,138,401