UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

    For the fiscal year ended October 31, 2012

or

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

    For the transition period from                          to                         

    Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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

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 x No ¨

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

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

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

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

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

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

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

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2012.

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

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 14, 2012
Common Stock, no par value	72,276,272

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 6, 2013 are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

2012 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

		Page
Part I.
Item 1.	Business		1
Item 1A.	Risk Factors		8
Item 1B.	Unresolved Staff Comments		16
Item 2.	Properties		16
Item 3.	Legal Proceedings		17
Item 4.	Mine Safety Disclosures		17
Part II.
Item 5.	Market for Registrant’s Common Equity, Related   Stockholder Matters and Issuer Purchases of Equity Securities		18
Item 6.	Selected Financial Data		20
Item 7.	Management’s Discussion and Analysis of Financial   Condition and Results of Operations		21
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		55
Item 8.	Financial Statements and Supplementary Data		58
Item 9.	Changes in and Disagreements With Accountants on   Accounting and Financial Disclosure		129
Item 9A.	Controls and Procedures		130
Item 9B.	Other Information		133
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance		133
Item 11.	Executive Compensation		133
Item 12.	Security Ownership of Certain Beneficial Owners and   Management and Related Stockholder Matters		133
Item 13.	Certain Relationships and Related Transactions, and Director   Independence		134
Item 14.	Principal Accounting Fees and Services		134
Part IV.
Item 15.	Exhibits, Financial Statement Schedules		135
	Signatures		144

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 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.

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

We have two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. The percentage of assets as of October 31, 2012 and earnings before taxes by segment for the year ended October 31, 2012 are presented below.

	Assets		Earnings Before Taxes
Regulated Utility		97%		88%
Non-utility Activities:
Regulated non-utility activities		2%		5%
Unregulated non-utility activities		1%		7%
Total non-utility activities		3%		12%

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

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

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities.

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency (EPA) relating to the environment. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

We hold non-exclusive franchises for natural gas service in many of the communities we serve, with expiration dates from December 2012 to 2058. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. From time to time, some of our franchise agreements expire; however, we continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. Depending on the jurisdiction, we believe that these franchises will be renewed or that service will be continued in the ordinary course of business while we negotiate renewals or continue to operate under our state-granted franchise rights without the specific franchise agreements with each city or municipality. The likelihood of cessation of service under an expired franchise is remote, and we do not believe there will be a material adverse impact on us.

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

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storage during the summer months (principally April through October) when customer demand is lower for withdrawal from storage during the winter heating season (principally November through March) when customer demand is higher. During the year ended October 31, 2012, the amount of natural gas in storage varied from 17 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 26.2 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $70.6 million to $125 million.

The following is a five-year comparison of operating statistics for the years ended October 31, 2008 through 2012.

	2012		2011		2010		2009		2008
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	534,321	$	658,892	$	743,346	$	787,994	$	813,032
Commercial		301,013		379,846		428,085		462,160		503,317
Industrial		95,177		104,774		116,122		126,855		209,341
Power Generation		36,027		28,969		21,708		19,609		25,266
For Resale		9,512		9,692		11,061		11,746		12,326
Total		976,050		1,182,173		1,320,322		1,408,364		1,563,282
Secondary Market Sales		140,380		244,824		224,973		221,300		515,968
Miscellaneous		6,350		6,908		7,000		8,452		9,858
Total	$	1,122,780	$	1,433,905	$	1,552,295	$	1,638,116	$	2,089,108
Gas Volumes - Dekatherms
(in thousands):
System Throughput:
Residential		43,788		57,778		58,327		55,298		51,909
Commercial		33,774		40,749		39,994		38,526		36,766
Industrial		89,234		90,842		82,805		74,363		81,780
Power Generation		151,675		83,522		63,024		39,639		30,875
For Resale		5,829		6,870		8,465		9,048		8,921
Total		324,300		279,761		252,615		216,874		210,251
Secondary Market Sales		48,373		48,835		46,823		46,057		53,442
Number of Customers Billed
(12-month average):
Residential		878,851		871,401		864,205		855,670		852,586
Commercial		95,100		94,485		94,287		94,404		94,045
Industrial		2,265		2,265		2,273		2,358		2,937
Power Generation		22		22		20		20		20
For Resale		15		15		16		17		17
Total		976,253		968,188		960,801		952,469		949,605
Average Per Residential Customer:
Gas Used - Dekatherms		49.82		66.30		67.49		64.63		60.88
Revenue	$	607.98	$	756.13	$	860.15	$	920.91	$	953.61
Revenue Per Dekatherm	$	12.20	$	11.40	$	12.74	$	14.25	$	15.66

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	2012		2011		2010		2009		2008
Cost of Gas (in thousands):
Natural Gas Commodity Costs	$	379,145	$	666,930	$	753,529	$	727,744	$	1,454,073
Capacity Demand Charges		129,090		136,139		127,137		128,081		127,640
Natural Gas Withdrawn From
(Injected Into) Storage, net		27,580		11,362		5,293		126,480		(78,283)
Regulatory Charges (Credits), net		11,519		45,835		113,744		94,237		32,705
Total	$	547,334	$	860,266	$	999,703	$	1,076,542	$	1,536,135
Supply Available for Distribution
(dekatherms in thousands):
Natural Gas Purchased		132,426		155,550		157,021		149,696		159,857
Transportation Gas		235,474		175,005		147,038		115,519		108,332
Natural Gas Withdrawn From
(Injected Into) Storage, net		(378)		196		(1,309)		1,010		(2,980)
Company Use		(296)		(309)		(282)		(283)		(135)
Total		367,226		330,442		302,468		265,942		265,074

During the year ended October 31, 2012, we delivered 324.3 million dekatherms to our retail customers compared to 279.8 million dekatherms the year before. Of this amount, 246.7 million dekatherms of gas were sold to or transported for large volume customers compared with 181.2 million dekatherms in 2011. Of these volumes sold to or transported for large volume customers, we transported 151.7 million dekatherms this year to power generation facilities compared with 83.5 million dekatherms in the prior year. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 77.6 million dekatherms in 2012, compared with 98.5 million dekatherms in 2011. Weather, as measured by degree days, was 19% warmer than normal in 2012 and 10% colder than normal in 2011.

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

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

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

As of October 31, 2012, 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)	250,000
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
Kinder Morgan -Tennessee Pipeline Storage	55,900
Total	833,800

As of October 31, 2012, we own or have under contract 36.1 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement or replace regular pipeline supplies.

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

To diversify our reliance away from the Gulf Coast region, we receive firm, long-term market area storage service from Hardy Storage Company, LLC (Hardy Storage) located in West Virginia, Columbia Gas Storage located in West Virginia, Ohio and Pennsylvania, and Dominion Storage located in West Virginia, Pennsylvania and New York that may be filled with Appalachian sourced supply. We also contract for firm, long-term transportation service from Midwestern Gas Transmission Company that provides access to gas supplies from Canadian and Rocky Mountain supply basins and the Chicago hub that can supply city gate demand or be used to fill storage facilities on Tennessee Gas Pipeline, Columbia Gas, Pine Needle and Transco.

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In November 2012, we executed our supply diversification strategy to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm contract with Williams-Transco for its Leidy Southeast expansion project to transport those gas supplies to our markets. These new supply arrangements are scheduled to begin in December 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

We completed pipeline expansion projects in December 2011 and June 2012 to provide long-term natural gas delivery service to two power generation customers in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under construction in North Carolina with a targeted in service date of June 2013. In addition to delivering the natural gas supply to achieve the environmental benefits of replacing coal-fired power plants with new natural gas-fired power plants, the construction of natural gas pipelines for two of these projects increases our natural gas infrastructure in the eastern part of North Carolina and enhances future opportunities for economic growth and development. See the following discussion of our forecasted capital investment related to the construction of the natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Residential new home construction	7,939
Residential conversion	3,789
Commercial	1,546
Total new customers	13,274

We forecast continuing gross customer growth for fiscal 2013 of approximately 1%.

Our business model supports new clean energy technologies and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security. We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We are executing a plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently own and operate eight company CNG fueling stations at Company resource centers with 14% of our vehicle fleet capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 38,000 dekatherms of CNG to commercial customers for the year ended October 31, 2012, which is equivalent to approximately 579 homes, and used 4,880 dekatherms of CNG in our own fleets. Through sales of CNG to commercial customers and use by our own fleet, this CNG usage displaced more than 344,000 gallons of gasoline and diesel fuel.

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

During the year ended October 31, 2012, 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, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price and alternative fuels. 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 margin could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

Under FERC policies, certain large volume customers located in proximity to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended October 31, 2012, no bypass occurred. 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. Numerous factors can influence customer demand for natural gas including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. The direct use of natural gas in homes and businesses is the most efficient and cost effective use of natural gas and results in overall lower carbon emissions.

During the year ended October 31, 2012, our largest revenue generating customer contributed $59.2 million, or 5%, of total operating revenues. Our largest margin generating customer contributed $27.5 million, or 5% of total margin.

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

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

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

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net income. Labor and employee benefits are components of the cost of service, and construction costs are the primary component of rate base. In order to recover increased costs and earn a fair return on rate base, we file general rate cases for review and approval by regulatory authorities in North Carolina and Tennessee, when necessary. The ratemaking process has a natural time lag between incurrence of additional costs and the setting of new rates. In South Carolina, we operate under a rate stabilization mechanism that reduces the lag to one year. This regulatory lag can impact earnings.

As of October 31, 2012, our fiscal year end, we had 1,752 employees compared with 1,782 as of October 31, 2011.

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

Item 1A. Risk Factors

An overall economic downturn could negatively impact our earnings.

Weakening economic activity in our markets could result in a loss of customers, a decline in customer additions, especially in the new home construction market, or a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. It may become more difficult for customers to pay their gas bills, leading to slow collections and higher-than-normal levels of accounts receivable. This could increase our financing requirements and non-gas cost bad debt expense. Deteriorating economic conditions could also affect pension costs by reducing the value of the investments that fund our pension plan and negatively affect actuarial assumptions, resulting in increased pension costs. The foregoing could negatively affect earnings and liquidity, reducing our ability to grow the business.

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

The supply and demand balance in natural gas markets could cause an increase in the price of natural gas. Recently, the increased production of U.S. shale natural gas has put downward pressure on the wholesale cost of natural gas; accordingly, restrictions or regulations on shale gas production could cause natural gas prices to increase. Additionally, the Commodities Futures Trading Commission (CFTC) under the 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives markets. Regulations affecting derivatives could increase the price of our gas supply. The prudently incurred cost we pay for natural gas is passed directly through to our customers. Therefore, significant increases in the price of natural gas may cause our existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders and new customers to select alternative sources of energy. Decreases in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures, and a decline in new customers could impede growth in our future earnings. In addition, during periods when natural gas prices are high, our working capital costs could increase due to higher carrying costs of gas storage inventories, adding further upward pressure on customers’ bills. Customers may have trouble paying those higher bills which may lead to bad debt expenses, ultimately reducing our earnings.

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

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

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

Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies set the rates that we charge our customers for our services. We monitor allowed rates of return and our ability to earn appropriate rates of return based on factors, such as increased operating costs, and initiate general rate proceedings as needed. If a state regulatory commission were to prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable return by significantly lowering our allowed return or negatively altering our cost allocation, rate design, cost trackers, including margin decoupling and cost of gas, recovery of regulatory assets, including deferred gas costs, 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.” Additionally, our capital investment in recent years has been and is projected to remain at higher levels, increasing the risk of cost recovery. The foregoing may negatively impact our results of operations and earnings.

Rate cases also involve a risk of rate reduction, because once rates have been filed, they are still subject to challenge for their reasonableness by various intervenors. Regulatory authorities also review whether our gas costs are prudent and can adjust the amount of our gas costs that we pass through to our customers. Additionally, our state regulators foster a competitive regulatory model that, for example, allows us to recover any margin losses associated with negotiated transactions designed to retain large volume customers that could use alternative fuels or that may directly access natural gas supply through their own connection to an interstate pipeline. If there are changes in the regulatory compact that alter our ability to compete for these customers, then we could lose customers or incur significant unrecoverable expenses or margin losses to retain them. The occurrence of any of the foregoing could negatively impact our results of operations, financial condition and cash flows.

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Our debt and equity financings are also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our ability to access or take advantage of changes in the capital markets. This could negatively impact our liquidity or earnings.

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

The natural gas business is competitive, and we face competition from other companies that supply energy, including electric companies, oil and propane dealers, renewable energy providers and coal companies in relation to sources of energy for electric power plants, as well as nuclear energy. A significant competitive factor is price.

In residential, commercial and industrial customer markets, our natural gas distribution operations compete with other energy products, primarily electricity, propane and fuel oil. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas or decreases in the price of other energy sources could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. In the case of industrial customers, such as manufacturing plants, adverse economic or market conditions, including higher gas costs, could cause these customers to suspend business operations or to use alternative sources of energy or bypass our systems in favor of energy sources with lower per-unit costs.

Higher gas costs or decreases in the price of other energy sources may allow competition from alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas-fired equipment to equipment fueled by other energy sources. Competition between natural gas and other forms of energy is also based on efficiency, performance, reliability, safety and other non-price factors. Technological improvements in other energy sources and events that impair the public perception of the non-price attributes of natural gas could erode our competitive advantage. These factors in turn could decrease the demand for natural gas, impair our ability to attract new customers, and cause existing customers to switch to other forms of energy or to bypass our systems in favor of alternative competitive sources. This could result in slow or no customer growth and could cause customers to reduce or cease using our product, thereby reducing our ability to make capital expenditures and otherwise grow our business and adversely affecting our earnings.

Our business activities are concentrated in three states.

Approximately 97% of our assets and 88% of our earnings before taxes come from our regulated utility businesses. Further, approximately 70% of our natural gas utility customers and most of our utility transmission and distribution pipelines are located in North Carolina, with the remainder located in South Carolina and Tennessee. Changes in the regional economies, politics, regulations and weather patterns of North Carolina, South Carolina and Tennessee could negatively impact the growth opportunities available to us and the usage patterns and financial condition of customers and could adversely affect our earnings.

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

Our business and operations are subject to regulation by the FERC, the NCUC, the PSCSC, the TRA, the DOT, the EPA, the CFTC and other agencies, and we are subject to numerous federal and state laws and regulations. Compliance with existing or new laws and regulations may result

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in increased capital, operating and other costs which may not be recoverable in rates from our customers. Furthermore, because the language in some laws and regulations is not prescriptive, there is a risk that our interpretation of these laws and regulations may not be consistent with expectations of regulators. Any compliance failure related to these laws and regulations may result in fines, penalties or injunctive measures affecting operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. All of the above could result in a material adverse effect on our business, results of operations or financial condition.

Climate change, carbon neutral or energy efficiency legislation or regulations could increase our operating costs or restrict our market opportunities, negatively affecting our growth, cash flows and earnings.

The federal and/or state governments may enact legislation or regulations that attempt to control or limit the causes of climate change, including greenhouse gas emissions such as carbon dioxide. Such laws or regulations could impose costs tied to carbon emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could negatively impact the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas, and impact the competitive position of natural gas and the ability to serve new customers, negatively affecting our growth opportunities, cash flows and earnings.

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

Our earnings can vary from year to year, depending in part on weather conditions. Warmer-than-normal weather can reduce our utility margins as customer consumption declines. We have in place regulatory mechanisms and rate design that normalize the margin we collect from certain customer classes during the winter, providing for an adjustment up or down, to take into account warmer-than-normal or colder-than-normal weather. If our rates and tariffs are modified to eliminate weather protection provisions, such as weather normalization and rate decoupling tariffs, then we would be exposed to significant risk associated with weather. Additionally, our weather normalization mechanisms provide reduced protection for significantly warmer-than-normal winter weather. As a result of the foregoing, our results of operations and earnings could vary and be negatively impacted.

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

Inherent in our gas distribution and transmission activities, including natural gas and LNG storage, are a variety of hazards and operational risks, such as third party excavation damage, leaks, ruptures and mechanical problems. Severe weather conditions, as well as acts of terrorism or cyber-attacks, could also damage our pipelines and other infrastructure and disrupt our ability to

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conduct our natural gas distribution and transportation business. The outbreak of a pandemic could result in a significant part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. If the 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. The occurrence of any of these events could adversely affect our financial position, results of operations and cash flows.

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

In order to serve new customers or expand our service to existing customers, we need to maintain, expand or upgrade our distribution, transmission and/or storage infrastructure, including laying new pipeline and building compressor stations. Various factors may prevent or delay us from completing such projects or make completion more costly, such as the inability to obtain required approval from local, state and/or federal regulatory and governmental bodies, public opposition to the project, inability to obtain adequate financing, competition for labor and materials, construction delays, cost overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction or other material development components. As a result, we may not be able to adequately serve existing customers or support customer growth, which would negatively impact our earnings. In addition, the counterparty to one of our power generation construction agreements may elect to terminate the agreement prior to the in-service date for the project, which would negatively affect future earnings and cash flows.

A downgrade in our credit ratings could negatively affect our cost of and ability to access capital.

Our ability to obtain adequate and cost effective financing depends in part on our credit ratings. A negative change in our ratings outlook or any downgrade in our current investment-grade credit ratings by our rating agencies, particularly below investment grade, could adversely affect our costs of borrowing and/or access to sources of liquidity and capital. Such a downgrade could further limit our access to private credit markets and increase the costs of borrowing under available credit lines. Should our credit ratings be downgraded, the interest rate on our borrowings under our revolving credit agreement and commercial paper program would increase. An increase in borrowing costs without the ability to recover these higher costs in the rates charged to our customers could adversely affect earnings by limiting our ability to earn our allowed rate of return.

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

Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of the financial markets, in addition to our credit ratings. Disruptions in the capital and credit markets 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

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commitments if they experience shortages of capital and liquidity. Disruptions and volatility in the global credit markets could cause the interest rate we pay on our short-term credit facility, which is based on the London Interbank Offered Rate, to increase, could result in higher interest rates on future financings, and could impact the liquidity of the lenders under our short-term credit facility, potentially impairing their ability to meet their funding commitments. 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. Tax rates on dividends may increase, which could increase the cost of equity. The inability to access adequate capital or the increase in cost of capital may require us to conserve cash, prevent or delay us from making capital expenditures, and require us to reduce or eliminate the dividend or other discretionary uses of cash. A significant reduction in our liquidity could cause a negative change in our ratings outlook or even a reduction in our credit ratings. This could in turn further limit our access to credit markets and increase our costs of borrowing.

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

Changes in federal and state fiscal, tax and monetary policy may result in increased taxes, interest rates, and inflationary pressures on the costs of goods, services and labor. This could increase our expenses and decrease our earnings if we are not able to recover such increased costs from our customers. This series of events may increase our rates to customers and thus may negatively impact customer billings and customer growth. Changes in accounting or tax rules could negatively affect our cash flows. Any of these events may cause us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to grow the business or require us to reduce or eliminate the dividend or other discretionary uses of cash, and could negatively affect earnings.

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

Historically, we have made large capital expenditures in order to finance the expansion, upgrading and maintenance of our transmission and distribution systems. We also purchase natural gas for storage. We have made several equity method investments and will continue to pursue other similar investments, all of which are and will be important to our growth and profitability. We fund a portion of our cash needs for these purposes, as well as contributions to our employee pensions and benefit plans, through borrowings under credit arrangements and by offering new debt and equity securities. Our dependency on external sources of financing creates the risk that our profits could decrease as a result of higher borrowing costs and that we may not be able to secure external sources of cash necessary to fund our operations and new investments on terms acceptable to us. Volatility in seasonal cash flow requirements, including requirements for our gas supply procurement and risk management programs, may require increased levels of borrowing that could result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a credit rating downgrade. Any disruptions in the capital and credit markets could require us to conserve cash until the markets stabilize or until alternative credit arrangements or other funding required for our needs can be secured. Such measures could cause deferral of major capital expenditures, changes in our gas supply procurement program, the reduction or elimination of the dividend payment or other discretionary uses of cash, and could negatively affect our future growth and earnings.

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

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

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

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

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

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

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

We are invested in several natural gas related businesses as an equity method investor. The businesses in which we invest are subject to laws, regulations or market conditions, or have risks inherent in their operations, that could adversely affect their performance. Those that are not directly regulated by state or federal regulatory bodies could be subject to adverse market conditions not experienced by our regulated utility segment. We do not control the day to day operations of our equity method investments, and thus the management of these businesses by our partners could adversely impact their performance. We may not be able to fully direct the management and policies of these businesses, and other participants in those relationships may take action contrary to our interests, including making operational decisions that could affect our costs and liabilities related to our investment. In addition, other participants may withdraw from the business, become financially distressed or bankrupt, or have economic or other business interests or goals that are inconsistent with ours. All the foregoing could adversely affect our

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

We may be unable to attract and retain professional and technical employees, which could adversely impact our earnings.

Our ability to implement our business strategy and serve our customers is dependent upon the continuing ability to employ talented professionals and attract and retain a skilled workforce. We are subject to the risk that we will not be able to effectively replace the knowledge and expertise of an aging workforce as those workers retire. Without a skilled workforce, our ability to provide quality service to our customers and meet our regulatory requirements will be challenged, and this could negatively impact our earnings.

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

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

Cyber-attack, acts of cyber-terrorism or failure of technology systems could disrupt our business operations, shut down our facilities or result in the loss or exposure of confidential or sensitive customer, employee or Company information.

We are placing greater reliance on technological tools that support our operations and corporate functions and processes. We may own these tools or have a license to use them, or we may rely on the technological tools of third parties to whom we outsource processes. We use such tools to manage our natural gas distribution and transmission pipeline operations, maintain customer, employee, Company and vendor data, prepare our financial statements, manage supply chain and other business processes. One or more of these technologies may fail due to physical disruption such as flooding, design defects or human error, or we may be unable to have these technologies supported, updated, expanded or integrated into other technologies. Additionally, our business operations and information technology systems may be vulnerable to attack by individuals or organizations that could result in disruption to them.

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

Our insurance coverage may not be sufficient.

We currently have general liability and property insurance in place in amounts that we consider appropriate based on our business risk and best practices in our industry and in general business. Such policies are subject to certain limits and deductibles and include business interruption coverage for limited circumstances. Insurance coverage covering risks against which we and others in our industry typically insure may not be available in the future, or may be available but at materially increased costs, reduced coverage or on terms that are not commercially reasonable. Premiums and deductibles may increase substantially. The insurance proceeds received for any loss of, or any damage to, any of our facilities or to third parties may not be sufficient to restore the total loss or damage. Further, the proceeds of any such insurance may not be paid in a timely manner. The occurrence of any of the foregoing could have a material adverse effect on our financial position, results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

All property included in the Consolidated Balance Sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, other storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with the majority of the total invested in utility distribution and transmission plant to serve our customers. We have approximately 2,800 linear miles of transmission pipeline up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,000 linear miles of distribution mains up to 16 inches in diameter. The transmission pipelines and distribution mains are generally underground, located near public streets and highways, or on property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on such property. All of these properties are located in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in progress” which primarily represents distribution, transmission and general plant projects that have not been placed into service pending completion.

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

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storage facility due to the expansion capacity, cost effectiveness, timing and design scope of another construction project that will enhance our ability to serve our North Carolina customers in this area. The future use of this property is dependent upon annual updates to our ongoing five-year plan for forecasted growth requirements.

We own or lease for varying periods our corporate headquarters building located in Charlotte, North Carolina and our resource centers located in North Carolina, South Carolina and Tennessee. Lease payments for these various offices totaled $3.7 million for the year ended October 31, 2012.

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

Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

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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, 2012 and 2011.

2012	High		Low		2011	High		Low
Quarter ended:					Quarter ended:
January 31		$  34.74	$	29.90	January 31	$	30.10	$	27.57
April 30		34.00		29.05	April 30		32.00		27.88
July 31		33.03		28.90	July 31		31.98		28.80
October 31		33.72		31.03	October 31		33.60		25.86

Holders

As of December 14, 2012, our common stock was owned by 13,392 shareholders of record. Holders of record exclude the individual and institutional security owners whose shares are held in street name or in the name of an investment company.

Dividends

The following table provides information with respect to quarterly dividends paid on common stock for the years ended October 31, 2012 and 2011. We expect that comparable cash dividends will continue to be paid in the future.

	Dividends Paid		Dividends Paid
2012	Per Share	2011	Per Share
Quarter ended:		Quarter ended:
January 31	29¢	January 31	28¢
April 30	30¢	April 30	29¢
July 31	30¢	July 31	29¢
October 31	30¢	October 31	29¢

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

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Share Repurchases

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended October 31, 2012.

				Total Number of	Maximum Number
	Total Number			Shares Purchased	of Shares that May
	of Shares	Average Price Paid Per Share		as Part of Publicly	Yet be Purchased
Period	Purchased			Announced Program	Under the Program (1)
Beginning of the period					2,910,074
8/1/12 - 8/31/12	-	$	-	-	2,910,074
9/1/12 - 9/30/12	-	$	-	-	2,910,074
10/1/12 - 10/31/12	-	$	-	-	2,910,074
Total	-	$	-	-

(1) The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

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

Comparisons of Cumulative Total Shareholder Returns

The following performance graph compares our cumulative total shareholder return from October 31, 2007 through October 31, 2012 (a five-year period) with the average performance of our industry peer group and the Standard & Poor’s 500 Stock Index, a broad market index (the S&P 500 Index). Our LDC Peer Group index is comprised of peer group companies that are publicly traded, have a focus on natural gas distribution in multi-state territories and have similar annual revenues and market capitalization to ours. We attempt to have our peer group companies meet a majority of these criteria for inclusion in the group, and we use the same peer group to calculate our cumulative shareholder return as we use for market benchmarking for our executive compensation plans when the end of the three-year performance period of a share-based plan award aligns with the current year of our report.

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

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The graph assumes that the value of an investment in Common Stock and in each index was $100 at October 31, 2007 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, 2007

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

	2007		2008		2009		2010		2011		2012
Piedmont	$	100	$	134	$	99	$	130	$	150	$	152
LDC Peer Group		100		100		97		123		142		149
S&P 500 Index		100		64		70		82		88		102

Item 6. Selected Financial Data

The following table provides selected financial data for the years ended October 31, 2008 through 2012.

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In thousands except per share amounts	2012		2011		2010		2009		2008
Operating Revenues	$	1,122,780	$	1,433,905	$	1,552,295	$	1,638,116	$	2,089,108
Margin (operating revenues less cost of gas)	$	575,446	$	573,639	$	552,592	$	561,574	$	552,973
Net Income	$	119,847	$	113,568	$	141,954	$	122,824	$	110,007
Earnings per Share of Common Stock:
Basic	$	1.67	$	1.58	$	1.96	$	1.68	$	1.50
Diluted	$	1.66	$	1.57	$	1.96	$	1.67	$	1.49
Cash Dividends per Share of Common Stock	$	1.19	$	1.15	$	1.11	$	1.07	$	1.03
Total Assets *	$	3,769,939	$	3,242,541	$	3,053,275	$	3,118,819	$	3,138,401
Long-Term Debt (less current maturities)	$	975,000	$	675,000	$	671,922	$	732,512	$	794,261
* Total assets for 2008 have been adjusted to reflect the gross presentation rather than a net presentation in accordance with the adoption of new accounting guidance related to offsetting of amounts related to certain contracts with the same counterparty.

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

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Item 1A. Risk Factors:

• economic conditions in our markets

• wholesale price of natural gas

• availability of adequate interstate pipeline transportation capacity and natural gas supply

• regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis

• competition from other companies that supply energy

• changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated

• costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us

• effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities

• weather conditions

• operational interruptions to our gas distribution and transmission activities

• ability to complete necessary or desirable pipeline expansion or infrastructure development projects

• our credit ratings

• availability and cost of capital

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• federal and state fiscal, tax and monetary policy

• ability to generate sufficient cash flows to meet all our cash needs

• ability to satisfy all of our outstanding debt obligations

• ability of counterparties to meet their obligations to us

• costs of providing pension benefits

• earnings from the joint venture businesses in which we invest

• ability to attract and retain professional and technical employees

• changes in accounting standards

• risk of cyber-attack, acts of cyber-terrorism, or failure of technology systems

• ability to obtain and maintain sufficient insurance

• change in number of outstanding shares

Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not place undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

Forward-looking statements are based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 51,600 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

We have two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-K.

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Regulation

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities.

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the environment. In addition, we are subject to numerous other regulations, such as those relating to employment and benefit practices, which are generally applicable to companies doing business in the United States of America.

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

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. Alternative rate structures and cost recovery mechanisms are rate designs and mechanisms that allow utilities to encourage energy efficiency and conservation by separating or decoupling the link between energy consumption and margin revenues, thereby aligning the interests of shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, we operate under a rate stabilization adjustment mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the rate stabilization adjustment tariff mechanism, we restate our rates in South Carolina based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism in South Carolina that partially offsets the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March to residential and commercial customers. In March 2012, we expanded our WNA mechanism in Tennessee to include bills rendered during the months of October through April to residential and commercial customers. Our WNA formulas calculate the actual weather variance

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from normal, using 30 years of history and increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns significantly vary from consumption patterns used to establish the WNA factors.

In all three states, 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 mechanism. For the year ended October 31, 2012, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 72% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 17% of our utility margins, including the rate stabilization adjustment mechanism in South Carolina and WNA mechanisms in South Carolina and Tennessee; and volumetric or periodic renegotiation of 11% of our utility margins, including our secondary marketing programs. For further information, see Note 2 to the consolidated financial statements.

Strategic Focus

Our strategic directives focus on our customers, our communities, our employees and our shareholders and reflect what we believe is the inherent advantages of natural gas compared to other types of energy. They are as follows:

• Promote the benefits of natural gas

• Expand our core natural gas and complementary energy-related businesses to enhance shareholder value

• Be the energy and service provider of choice

• Achieve excellence in customer service every time

• Preserve financial strength and flexibility

• Execute sustainable business practices

• Enhance our healthy, high performance culture

We believe natural gas is a safe and reliable energy source that is clean, efficient and abundant. We incorporate this belief into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We promote the increased awareness and use of natural gas and want our customers to choose us because of the value of natural gas and the quality of our service to them. With the environmental and cost benefits of using natural gas compared to coal in the generation of electricity, we have encouraged the development of gas-fired power generation facilities in our market area. We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and enhancing long-term shareholder value. We support our employees with improved processes and technology to better serve our customers while continuing to build a healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our business model supports new clean energy technologies and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.

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We have always placed a high priority on the safety of our system, the public and our employees, as safety is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing transmission and distribution pipeline integrity programs to inspect our system for corrosion and leaks as well as monitoring key metrics of our system for its safe operation. We anticipate federal legislative and regulatory enactments that will increase in scope and add further requirements and costs to our pipeline safety and integrity programs and our capital expenditure programs. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

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

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

Executive Summary

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

Focus Areas and Achievements

Managing Gas Supplies and Prices. Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have sufficient and reliable supplies of competitively-priced natural gas to meet the needs of our utility customers. Natural gas development and

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production in North America continues to provide supply stability and price moderation for natural gas as an energy commodity. In the past two years, the lower price of natural gas has allowed us to significantly lower the cost of gas to our customers. Currently, natural gas has a price advantage over many other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant sources of shale gas reserves. In November 2012, in order to provide diversification, reliability and gas cost benefits to our customers, we signed long-term contracts to source more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These new supply arrangements are scheduled to begin in December 2015.

Customer Growth. With some improvement in economic conditions and targeted marketing programs on the benefits of natural gas, we have gains in utility customer growth in our service areas. Lower wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Customer gains in our residential market increased 29% in 2012 compared to 2011 from growth in new construction and conversion markets. Commercial customer additions increased 10% in 2012 compared to 2011, reflecting improvements in both commercial new construction activity and commercial conversion opportunities. We forecast continuing gross customer growth for fiscal 2013 of approximately 1%. Overall, total customers billed increased 1% in 2012 compared to 2011.

We see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We are executing a plan to build CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently own and operate eight company CNG fueling stations at Company resource centers with 14% of our vehicle fleet capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 38,000 dekatherms of CNG to commercial customers for the year ended October 31, 2012, which is equivalent to approximately 579 homes, and used 4,880 dekatherms of CNG in our own fleets. Through sales of CNG to our commercial customers and use by our own fleet, this CNG usage displaced more than 344,000 gallons of gasoline and diesel fuel.

Capital Expenditures. We continue to make progress with capital projects that we expect will provide benefits to our customers through safe and reliable natural gas service, while providing our shareholders a reasonable return on invested capital. We completed pipeline expansion projects in December 2011 and June 2012 to provide long-term natural gas delivery service to two power generation customers in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under construction in North Carolina with a targeted in service date of June 2013. See the discussion of our forecasted capital investment related to the construction of natural gas pipelines and compressor stations to serve new power generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We are increasing our utility capital expenditures for pipeline integrity, safety and compliance programs as well as system and technology infrastructure. To ensure safe pipeline operations, we are focusing on new technology through the development of a new work and asset management system. These capital expenditures will require rate cases or other regulatory mechanisms to obtain a return of and on those capital costs. See further discussion in the section below on “Business Process and Technology Improvements.”

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Regulatory Activity. We continue our regulatory strategy to implement rate structures that better align and balance the interests of shareholders and customers. In January 2012, the TRA approved an annual general rate increase of $11.9 million, effective March 2012, for Tennessee customers based on an approved rate of return of equity of 10.2%. This represented a 6.3% increase in annual revenue. In that rate case, we shifted more of our cost recovery to the fixed portion of our customers’ bills to mitigate margin recovery fluctuations from volumetric usage. Our annual margin recovery from fixed monthly charges to Tennessee customers increased from 29% to 37% with a resulting decrease in annual margin recovery from volumetric charges from 71% to 63%. The TRA also approved an expansion of the WNA period by two months to October through April with updated WNA factors and the recovery of various deferred regulatory assets.

Even though we have WNA mechanisms in South Carolina and Tennessee, we are not fully insulated from the effects of weather that is significantly warmer than normal, such as that experienced during the 2011-2012 winter heating season. Weather in 2012 was 19% warmer than normal and 27% warmer than 2011.

For the year ended October 31, 2012, the margin decoupling mechanism in North Carolina increased margin by $46.8 million, and the WNA mechanisms in South Carolina and Tennessee increased margin by $13.3 million, which included the additional months of April and October 2012 in Tennessee.

Business Process and Technology Improvements. To support our strategic objectives of excellence in customer service, as discussed above in the “Strategic Focus,” we have reorganized our field customer service, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service with an end goal of increasing customer loyalty and satisfaction while improving operational efficiencies. We have also implemented centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

We are in the process of a multi-year program designed to bring additional technology and automation to our field operations by providing systems and information to enable operations employees to more effectively and efficiently manage our pipeline assets, ensure operating efficiencies and facilitate compliance with pipeline safety and integrity regulations. This enhanced and new systems and process program, which includes multiple projects, will be integrated with our current and future financial and other business systems.

Cost Containment Measures. We continue to focus on improving operating efficiency and productivity and cost containment discipline where possible in payroll, corporate overhead charges and various discretionary spending categories. We have benefited from cost containment measures during the current and prior fiscal years, and we will continue to manage our business as efficiently as possible consistent with providing safe, reliable and cost effective services to our customers.

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Financial Strength and Flexibility. In order to profitably fund our Company’s investment in growth and our ongoing capital needs, we have executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings. In March 2012, we initiated a commercial paper (CP) program that is backstopped by our syndicated revolving credit facility for a combined borrowing capacity of $650 million. Also in March 2012, we entered into an agreement to issue $300 million of senior unsecured long-term debt in a private placement with a blended interest rate of 3.54%. We issued $100 million on July 16, 2012 and $200 million on October 15, 2012 with the proceeds used to repay short-term debt incurred in part for funding of capital expenditures. Both issuances will mature on July 16, 2027. In addition to these debt issuances during this fiscal year, we have an open shelf registration filed with the SEC in June 2011 that is available for future issuances of debt or equity.

On October 1, 2012, we renegotiated and extended the maturity of our syndicated revolving credit facility to further take advantage of favorable borrowing terms and reductions in our borrowing costs. This amended revolving credit facility extended our term to October 1, 2017 and continues to include the CP program in our borrowing capacity of $650 million with an option to request an increase of our capacity to $850 million. We anticipate annual savings of approximately $800,000 from lower unused fees and amortization of debt issuance costs over the life of the new agreement.

Additional information on operating results for the years ended October 31, 2012, 2011 and 2010 follows.

Results of Operations

Comprehensive Income Statement Components
							Percent Change
							2012 vs.			2011 vs.
In thousands except per share amounts	2012		2011		2010		2011			2010
Operating Revenues	$	1,122,780	$	1,433,905	$	1,552,295		(21.7	)%		(7.6	)%
Cost of Gas		547,334		860,266		999,703		(36.4	)%		(13.9	)%
Margin		575,446		573,639		552,592		0.3	%		3.8	%
Operations and Maintenance		242,599		225,351		219,829		7.7	%		2.5	%
Depreciation		103,192		102,829		98,494		0.4	%		4.4	%
General Taxes		34,831		38,380		33,909		(9.2	)%		13.2	%
Utility Income Taxes		69,101		64,068		62,082		7.9	%		3.2	%
Total Operating Expenses		449,723		430,628		414,314		4.4	%		3.9	%
Operating Income		125,723		143,011		138,278		(12.1	)%		3.4	%
Other Income (Expense), net of tax		14,221		14,549		47,387		(2.3	)%		(69.3	)%
Utility Interest Charges		20,097		43,992		43,711		(54.3	)%		0.6	%
Net Income	$	119,847	$	113,568	$	141,954		5.5	%		(20.0	)%
Average Shares of Common Stock:
Basic		71,977		72,056		72,275		(0.1	)%		(0.3	)%
Diluted		72,278		72,266		72,525		-	%		(0.4	)%
Earnings per Share of Common Stock:
Basic	$	1.67	$	1.58	$	1.96		5.7	%		(19.4	)%
Diluted	$	1.66	$	1.57	$	1.96		5.7	%		(19.9	)%

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Margin by Customer Class
In thousands	2012				2011				2010
Sales and Transportation:
Residential	$	321,056	56	%	$	319,675	56	%	$	316,368	57	%
Commercial		150,306	26	%		150,681	26	%		148,884	27	%
Industrial		46,993	8	%		47,176	8	%		44,078	8	%
Power Generation		32,289	6	%		23,970	4	%		17,384	3	%
For Resale		7,465	1	%		8,550	2	%		10,446	2	%
Total		558,109	97	%		550,052	96	%		537,160	97	%
Secondary Market Sales		9,681	2	%		14,016	2	%		10,702	2	%
Miscellaneous		7,656	1	%		9,571	2	%		4,730	1	%
Total	$	575,446	100	%	$	573,639	100	%	$	552,592	100	%

Gas Deliveries, Customers, Weather Statistics and Number of Employees

							Percent Change
							2012 vs.		2011 vs.
	2012		2011		2010		2011		2010
Deliveries in Dekatherms (in thousands):
Sales Volumes		82,087		104,740		105,583		(21.6)%		(0.8)%
Transportation Volumes		242,213		175,021		147,032		38.4 %		19.0 %
Throughput		324,300		279,761		252,615		15.9 %		10.8 %
Secondary Market Volumes		48,373		48,835		46,823		(0.9)%		4.3 %
Customers Billed (at period end)		969,239		958,307		946,785		1.1 %		1.2 %
Gross Residential and Commercial Customer Additions		13,274		10,522		10,975		26.2 %		(4.1)%
Degree Days
Actual		2,668		3,662		3,535		(27.1)%		3.6 %
Normal		3,310		3,318		3,321		(0.2)%		(0.1)%
Percent (warmer) colder than normal		(19.4)%		10.4 %		6.4 %		n/a		n/a
Number of Employees (at period end)		1,752		1,782		1,788		(1.7)%		(0.3)%

Net Income

2012 compared to 2011:

Net income increased $6.3 million in 2012 compared with 2011 primarily due to the following changes, which increased net income:

• $23.9 million decrease in utility interest charges.

• $3.5 million decrease in general taxes.

• $1.8 million increase in margin (operating revenues less cost of gas).

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

• $17.2 million increase in operations and maintenance expenses.

• $5.9 million increase in income taxes.

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2011 compared to 2010:

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

• $49.7 million decrease due to a gain on the sale of an interest in an equity method investment in the prior year.

• $5.5 million increase in operations and maintenance expenses.

• $4.8 million decrease in income from equity method investments.

• $4.5 million increase in general taxes.

• $4.3 million increase in depreciation.

• $.6 million increase in non-operating expense.

• $.5 million increase in charitable contributions.

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

• $21 million increase in margin.

• $19.6 million decrease in income taxes.

• $1.1 million increase in non-operating income.

Operating Revenues

Changes in operating revenues for 2012 and 2011 compared with the same prior periods are presented below.

Changes in Operating Revenues - Increase (Decrease)
	2012 vs.
In millions	2011
Residential and commercial customers	$	(275.4)
Industrial customers		(9.8)
Power generation customers		7.1
Secondary market		(104.4)
Margin decoupling mechanism		53.7
WNA mechanisms		18.2
Other		(.5)
Total	$	(311.1)

2012 compared to 2011:

• Residential and commercial customers – the decrease is primarily due to lower consumption from warmer weather and lower wholesale gas costs passed through in rates.

• Industrial customers – the decrease is primarily due to lower consumption and lower wholesale gas costs passed through to sales customers.

• Power generation customers – the increase is due to increased transportation services.

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• Secondary market – the decrease is due to lower secondary market margins in the wholesale market. 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.

• Margin decoupling mechanism – the increase is due to warmer weather in North Carolina. 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 weather and conservation.

• WNA mechanisms – the increase is due to warmer weather in South Carolina and Tennessee.

2011 compared to 2010:

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

• $150.8 million of lower gas costs passed through to sales customers.

• $1.1 million from decreased revenues under the margin decoupling mechanism.

These decreases were partially offset by the following increases:

• $19.8 million from higher revenues in secondary market transactions due to increased activity and gas costs.

• $5.8 million from an increase in volumes delivered to transportation customers.

• $3.9 million from increased revenues under the WNA mechanisms in South Carolina and Tennessee.

Cost of Gas

Changes in cost of gas for 2012 and 2011 compared with the same prior periods are presented below.

Changes in Cost of Gas - Increase (Decrease)
	2012 vs.		2011 vs.
In millions	2011		2010
Commodity gas costs passed through to sales customers	$	(194.3)	$	(80.5)
Commodity gas costs in secondary market transactions		(100.1)		16.5
Pipeline demand charges		(7.0)		9.0
Regulatory approved gas cost mechanisms		(11.5)		(83.2)
Other		-		(1.2)
Total	$	(312.9)	$	(139.4)

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2012 compared to 2011:

• Commodity gas costs passed through to sales customers – the decrease is due to lower volumes sold due to warmer weather and lower wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the decrease is due to lower average wholesale gas costs.

• Pipeline demand charges – the decrease is primarily due to changing asset manager agreement terms.

• Regulatory approved gas cost mechanisms – decrease is due to the effects of various regulatory true-up mechanisms.

2011 compared to 2010:

• Commodity gas costs passed through to sales customers – the decrease is due to lower wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the increase is due to increased activity and higher average wholesale gas costs.

• Pipeline demand charges – the increase is primarily due to timing of asset manager agreement terms.

• Regulatory approved gas cost mechanisms – the decrease is primarily due to commodity gas cost true ups.

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

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory passthrough of changes in wholesale commodity gas costs. Our utility margin is defined as natural gas revenues less natural gas commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 36% of revenues for the year ended October 31, 2012, and our pipeline transportation and storage costs accounted for 11%.

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In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers under terms and conditions of service that are competitive with alternative energy sources and allow such service to be provided without general subsidies from Piedmont’s other system customers.

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

Changes in margin for 2012 and 2011 compared with the same prior periods are presented below.

Changes in Margin - Increase (Decrease)
	2012 vs.		2011 vs.
In millions	2011		2010
Residential and commercial customers	$	1.0	$	5.1
Industrial customers		(1.3)		1.2
Power generation customers		8.3		6.6
Secondary market activity		(4.3)		3.3
Net gas cost adjustments		(1.9)		4.8
Total	$	1.8	$	21.0

2012 compared to 2011:

• Residential and commercial customers – the increase is primarily due to the general rate increase in Tennessee effective March 1, 2012 and customer growth in all three states, offset by lower consumption in Tennessee and South Carolina where the WNA mechanisms did not perfectly adjust for significantly warmer-than-normal weather.

• Industrial customers – the decrease is primarily due to lower consumption in the industrial market from warmer weather.

• Power generation customers – the increase is due to increased transportation services.

• Secondary market activity – the decrease is due to less wholesale natural gas price volatility.

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2011 compared to 2010:

• Residential and commercial customers – the increase is primarily due to growth in those markets.

• Industrial customers – the increase is primarily due to increases in volumes and services to industrial customers.

• Power generation customers – the increase is due to increases in volumes and services to power generation customers.

• Secondary market activity – the increase is due to increased activity and margins.

Operations and Maintenance Expenses

Changes in operations and maintenance expenses for 2012 and 2011 compared with the same prior periods are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)

In millions	2012 vs.       2011		2011 vs.       2010
Employee benefits	$	7.1	$	.8
Payroll		4.0		1.1
Contract labor		3.7		(.4)
Regulatory		1.3		(.9)
Transportation		.8		2.5
Materials		-		1.5
Other		.3		.9
Total	$	17.2	$	5.5

2012 compared to 2011:

• Employee benefits – the increase is primarily due to increases in medical coverage premiums and defined benefit pension costs and the absence of pension plan funding and a regulatory pension deferral in the current year.

• Payroll – the increase is due to increases in incentive plan accruals.

• Contract labor – the increase is primarily due to increased process improvement projects and pipeline integrity, maintenance and safety programs.

• Regulatory – the increase is primarily due to amortization of regulatory assets that began with the Tennessee general rate increase.

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2011 compared to 2010:

• Payroll – the increase is primarily due to merit increases, partially offset by a decrease in long-term incentive plan accruals.

• Transportation – the increase is primarily due to increased fuel costs and new vehicles placed into service in 2011.

• Materials – the increase is primarily due to the implementation of an integrated supply chain process in 2011.

• Regulatory – the decrease is primarily due to the cessation of the amortization of certain regulatory assets in South Carolina.

• Other – the increase is primarily due to a recovery disallowance of some prior years’ franchise fees in one of our jurisdictions and higher bank fees from increased activity and unused amounts of the revolving syndicated credit facility, partially offset by decreases in insurance, utility and advertising expenses.

Depreciation

Depreciation expense increased from $98.5 million to $103.2 million over the three-year period 2010 to 2012 primarily due to increases in plant in service, particularly with the addition of major pipeline and compression facilities used to provide service to new power generation customers.

General Taxes

Changes in general taxes for 2012 and 2011 compared with the same prior periods are presented below.

Changes in General Taxes Expense - Increase (Decrease)

In millions	2012 vs.       2011		2011 vs.       2010
Sales tax accrual	$	(2.5)	$	2.5
Gross receipts tax		(.8)		(.1)
Property taxes		.4		1.8
Other		(.6)		.3
Total	$	(3.5)	$	4.5

2012 compared to 2011:

• Sales tax accrual – the decrease is primarily due to the accrual of a liability of $2.7 million in 2011 for sales taxes on certain customer accounts.

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• Gross receipts tax – the decrease is due to lower accruals in the current period for Tennessee gross receipts tax as a result of lower revenues.

2011 compared to 2010:

• Sales tax accrual – the increase is primarily due to the accrual of a liability of $2.7 million in 2011 for sales taxes on certain customer accounts.

• Property taxes – the increase is related to a larger property base and property value reassessments by taxing authorities.

Other Income (Expense)

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

2012 compared with 2011:

The primary change to Other Income (Expense) in 2012 compared with 2011 was income from equity method investments, primarily from SouthStar Energy Services LLC (SouthStar) and Cardinal Pipeline Company, L.L.C. (Cardinal). All other changes for the year ended October 31, 2012 compared with 2011 were insignificant.

Income from equity method investments from SouthStar decreased $1.4 million in 2012 primarily due to lower customer usage related to warmer-than-normal weather, net of weather derivatives, partially offset by lower transportation and gas costs and higher commercial asset optimization.

The decrease from SouthStar was partially offset by a $1 million increase in earnings from Cardinal primarily due to higher capitalized interest from the allowance for funds used during construction (AFUDC) and increased revenues as a result of the expansion project to serve Progress Energy Carolinas’ (PEC) Wayne County generation project, partially offset by higher depreciation and operating expenses.

2011 compared with 2010:

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

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

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

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

Utility Interest Charges

Changes in utility interest charges for 2012 and 2011 compared with the same prior periods are presented below.

Changes in Utility Interest Charges - Increase (Decrease)

In millions	2012 vs.       2011		2011 vs.       2010
Borrowed AFUDC	$	(16.6)	$	1.4
Interest expense on long-term debt		(4.6)		(6.6)
Regulatory interest expense, net		(3.8)		3.7
Interest expense on short-term debt		.8		1.1
Other		.3		.7
Total	$	(23.9)	$	.3

2012 compared to 2011:

• Borrowed AFUDC – the decrease is due to an increase in capitalized interest primarily as a result of increased project construction expenditures.

• Interest expense on long-term debt – the decrease is primarily due to the replacement of higher rate debt with lower rate debt.

• Regulatory interest expense, net – the decrease is primarily due to an increase in interest charged on amounts due from customers, which is recorded as interest income.

• Interest expense on short-term debt – the increase is primarily due to higher balances outstanding during the current period used for utility capital expenditures and other corporate purposes at interest rates that are 28 basis points lower than the prior year period.

2011 compared to 2010:

• Borrowed AFUDC – the increase in interest expense is due to a decrease in capitalized interest, primarily due to the closing of approximately half of our construction expenditures to utility plant in service in the first half of the current year as compared with the prior year.

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• Interest expense on long-term debt – the decrease is primarily due to lower amounts of debt outstanding.

• Regulatory interest expense, net – the increase in net interest expense is primarily due to a decrease in interest charged on amounts due from customers, which earned a carrying charge, as those balances were lower in the current period.

• Interest expense on short-term debt – the increase is primarily due to average interest rates during the current period that were 44 basis points higher than the prior year period due to higher spreads under the new revolving syndicated credit facility that was put into place in January 2011.

Financial Condition and Liquidity

Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. The need for long-term capital is driven by long-term debt maturities and the level of and timing of capital expenditures. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC.

To meet our capital and liquidity requirements outside of the long-term capital market, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily provides the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs.

Short-term debt is vital to meet our working capital needs, such as our seasonal requirements for gas supply, pipeline capacity, payment of dividends, general corporate liquidity, a portion of our capital expenditures and approved investments. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support our system infrastructure and the growth in our customer base.

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

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

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upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by the extension of bonus depreciation legislation. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities.”

Short-Term Debt. In October 2012, we amended and restated the agreement underlying our $650 million three-year revolving syndicated credit facility. The amended and restated agreement provides for a five-year revolving syndicated credit facility that expires in October 2017 and has an option to request an expansion of up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million. The five-year revolving syndicated credit facility continues to have the same financial covenants. We anticipate annual savings of approximately $800,000 from lower unused fees and extended amortization of debt issuance costs under the amended and restated revolving credit facility.

In March 2012, we established a $650 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.

Highlights for our short-term debt as of October 31, 2012 and 2011 and for the quarter and year ended October 31, 2012 and 2011 are presented below.

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In thousands	Credit          Facility			Commercial       Paper			Total     Borrowings
2012
End of period (October 31, 2012):
Amount outstanding	$	-		$	365,000		$	365,000
Weighted average interest rate		-	%		.42	%		.42	%
During the period (August 1, 2012 - October 31, 2012):
Average amount outstanding	$	-		$	444,300		$	444,300
Minimum amount outstanding	$	-		$	335,000		$	335,000
Maximum amount outstanding	$	-		$	535,000		$	535,000
Minimum interest rate		-	%		.30	%		.30	%
Maximum interest rate		-	%		.45	%		.45	%
Weighted average interest rate		-	%		.39	%		.39	%
Maximum amount outstanding during the month:
August 2012	$	-		$	450,000		$	450,000
September 2012		-			500,000			500,000
October 2012		-			535,000			535,000
During the year ended October 31, 2012:
Average amount outstanding	$	144,700		$	404,700		$	416,300
Minimum amount outstanding (1)	$	-		$	-		$	328,500
Maximum amount outstanding (1)	$	475,500		$	535,000		$	535,000
Minimum interest rate (2)		1.15	%		.22	%		.22	%
Maximum interest rate		1.20	%		.45	%		1.20	%
Weighted average interest rate		1.17	%		.38	%		.66	%
2011
End of period (October 31, 2011):
Amount outstanding	$	331,000		$	-		$	331,000
Weighted average interest rate		1.15	%		-	%		1.15	%
During the period (August 1, 2011 - October 31, 2011):
Average amount outstanding	$	236,000		$	-		$	236,000
Weighted average interest rate		1.14	%		-	%		1.14	%
Maximum amount outstanding during the month:
August 2011	$	269,500		$	-		$	269,500
September 2011		288,500			-			288,500
October 2011		342,500			-			342,500
During the year ended October 31, 2011:
Average amount outstanding	$	203,500		$	-		$	203,500
Weighted average interest rate		.94	%		-	%		.94	%
Maximum amount outstanding	$	426,000		$	-		$	426,000
(1) During March 2012, we were borrowing under both the credit facility and CP program for a portion of the month.
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program.

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As of October 31, 2012, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $3.6 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of October 31, 2012, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $281.4 million.

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

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

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

Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, are expected to mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. With the unusually warmer-than-normal winter of 2011-2012 together with lower natural gas prices this fiscal year, we have experienced lower levels of bad debt expense.

Net cash provided by operating activities was $304.5 million in 2012, $311.2 million in 2011 and $360.5 million in 2010. Net cash provided by operating activities reflects a $6.3 million increase in net income for 2012 compared with 2011 primarily due to lower interest expense partially offset by higher operating costs in 2012. The effect of changes in working capital on net cash provided by operating activities is described below:

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• Trade accounts receivable and unbilled utility revenues decreased $4.8 million in the current period primarily due to a decrease in unbilled volumes and amounts billed to customers reflecting lower gas costs. Volumes sold to weather-sensitive residential and commercial customers decreased 21 million dekatherms as compared with the same prior period primarily due to 27.1% warmer weather during the current period. Total throughput increased 44.5 million dekatherms as compared with the same prior period, largely from 68.2 million dekatherms, or 81.6%, increased deliveries to power generation customers, partially offset by decreased sales to residential, commercial and industrial customers.

• Net amounts due from customers increased $45.6 million in the current period primarily due to the accrual of amounts due from customers under the North Carolina margin decoupling and South Carolina WNA tariff mechanisms.

• Gas in storage decreased $18.5 million in the current period due to a decrease in the weighted average cost of gas and decreased volumes in storage.

• Prepaid gas costs decreased $9 million in the current period primarily due to a decrease in the weighted average cost of gas and gas being made available for sale during the period. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

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 WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA mechanism in Tennessee, effective in March 2012, was extended to the months of October through April for residential and commercial billings. The WNA mechanisms in South Carolina and Tennessee, which includes the additional months of April and October 2012 in Tennessee, generated charges to customers of $13.3 million in 2012 and credits of $4.9 million and $8.8 million in 2011 and 2010, respectively. 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” in “Current Assets” or “Amounts due to customers” in “Current Liabilities” 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 $46.8 million in 2012 and reduced margin by $7 million and $5.9 million in 2011 and 2010, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the Act), enacted in December 2010, extended the 50% bonus depreciation that expired December 2009 and temporarily increased bonus depreciation for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. Based on current capital projections and timelines, we are anticipating that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010-2014 by $130-170 million as compared with cash tax needs prior to the Act. While reducing cash tax payments, bonus depreciation will increase deferred tax liabilities by a similar amount. Rate base generally consists of net utility plant in service less utility deferred income tax liabilities. Rate base upon which authorized revenue requirements are determined is expected to increase for the remainder of 2012, but less than if bonus depreciation had not been in effect.

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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, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

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

Cash Flows from Investing Activities. Net cash used in investing activities was $549.3 million in 2012, $252.6 million in 2011 and $128.6 million in 2010. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures were $529.6 million in 2012 as compared to $243.6 million in 2011, primarily due to expending $284.3 million and $103.6 million, respectively, for the construction of power generation service delivery projects. Gross utility capital expenditures were $199.1 million in 2010 with $52.3 million of investments in plant to serve power generation customers.

We have a substantial capital expansion program for construction of transmission and distribution facilities, purchase of equipment and other general improvements. We are increasing our spending for pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. Our program primarily supports our system infrastructure and the growth in our customer base. Significant utility construction expenditures are expected to meet long-term growth, including growth in the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed. To ensure safe pipeline operations, we are also focusing on new technology through the development of a new work and asset management system.

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We anticipate making utility capital expenditures, including AFUDC, in the range of $525 – $575 million in our fiscal year 2013, including $75 - $85 million for the completion of the Sutton power generation delivery project and higher utility capital expenditures related to pipeline integrity, safety and compliance programs and systems and technology infrastructure. Our estimates of utility capital expenditures shown below for 2013 - 2015 include utility transmission pipeline integrity projects. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits. Additional detail for the anticipated capital expenditures follows.

In millions	2013		2014		2015
Utility	$	450 - 490	$	275 - 325	$	275 - 325
Sutton power generation project		75 - 85		-		-
Total forecasted capital expenditures	$	525 - 575	$	275 - 325	$	275 - 325

In October 2009, we reached an agreement with PEC, now a subsidiary of Duke Energy Corporation (DEC), to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. This required us to construct 38 miles of transmission pipeline along with additional compression facilities to provide service in June 2012. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. We also executed an agreement with Cardinal to expand our firm capacity requirement on Cardinal to serve the PEC Wayne County site. This required Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million related to this system expansion from January 2011 through June 2012; our current fiscal year contributions related to this expansion were $3.6 million. Cardinal’s expansion service for the project was also placed into service in June 2012. In June 2012, due to Cardinal obtaining permanent financing on the expansion, we received $5.4 million as a partial return of our capital investment. For further information regarding this agreement, see Note 12 to the consolidated financial statements.

In April 2010, we reached another agreement with PEC to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013, and our investment in the pipeline and compression facilities is supported by a long-term service agreement.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. We anticipate that a portion of the cost of this project will be included in our North Carolina utility rate base because the facilities will enhance our ability to serve other North Carolina customers.

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During fiscal 2011, we placed into service natural gas pipeline and compression facilities to provide natural gas delivery service to a PEC power generation facility located in Richmond County, North Carolina. During fiscal 2011, we also placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rowan County, North Carolina. In December 2011, we placed into service natural gas pipeline facilities to provide natural gas delivery service to a DEC power generation facility located in Rockingham County, North Carolina.

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

In November 2012, we entered into an agreement to become a 24% equity member of Constitution Pipeline Company, LLC, a Delaware limited liability company. The purpose of the joint venture is to construct and operate a 121 mile interstate natural gas pipeline and related facilities connecting gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. The target in-service date is March 2015. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is estimated at $700 – 800 million. In November 2012, we made an initial contribution of $4.8 million, and we expect our total contributions will be an estimated $180 million through 2015 with approximately 90% of funding to occur during our fiscal 2014 and 2015 years. For further information regarding this agreement, see Note 12 to the consolidated financial statements.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $240 million in 2012, ($57.5) million in 2011 and ($233.9) million in 2010. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP), our employee stock purchase plan (ESPP) and bonus depreciation. We may sell common stock and long-term debt when market and other conditions favor such long-term financing to maintain our target capital structure of 50-55% equity to total long-term capital. Funds are primarily used to retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock.

Outstanding debt under our syndicated revolving credit facility and CP program increased from $331 million as of October 31, 2011 to $365 million as of October 31, 2012 primarily due to higher capital expenditures. Over the three-year period from 2010 to 2012, our short-term debt has included two revolving syndicated credit facilities. Our previous five-year revolving syndicated credit facility was replaced with our three-year revolving syndicated credit facility, which in October 2012 was amended and restated as a five-year revolving syndicated credit facility. Our unsecured CP program, which is backstopped by our credit facility, was established in March 2012. For further information on short-term debt, see the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We have an open combined debt and equity shelf registration filed with the SEC in July 2011 that is available for future use. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate

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purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities. We anticipate issuing $250 million in long-term debt and approximately 4 million shares of our common stock under our shelf registration in fiscal 2013.

We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt. In March 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended interest rate of 3.54%. In July 2012, we issued $100 million with an interest rate of 3.47%. In October 2012, we issued $200 million with an interest rate of 3.57%. Both issuances will mature in July 2027. These proceeds were used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our accelerated share repurchase program as described in Note 6 to the consolidated financial statements. During 2012, we repurchased and retired .8 million shares for $26.5 million under our Common Stock Open Market Purchase Program, leaving a balance of 2,910,074 shares available for repurchase under the program. During 2011 and 2010, we repurchased .8 million shares and 1.8 million shares for $23 million and $47.3 million, respectively. We do not anticipate repurchasing our common stock in our fiscal year 2013.

During 2012, we issued $22.1 million of common stock through DRIP and ESPP. During 2011 and 2010, we issued $20.2 million and $19.1 million, respectively, through these plans.

We have paid quarterly dividends on our common stock since 1956. We increased our common stock dividend on an annualized basis by $.04 per share in 2012, 2011 and 2010. Dividends of $85.7 million, $82.9 million and $80.3 million for 2012, 2011 and 2010, respectively, were paid on common stock. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of October 31, 2012, our retained earnings were not restricted. On December 13, 2012, the Board of Directors declared a quarterly dividend on common stock of $.30 per share, payable December 31, 2012 to shareholders of record at the close of business on December 24, 2012. For further information, see Note 4 to the consolidated financial statements.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. As of October 31, 2012, our capitalization, including current maturities of long-term debt, if any, consisted of 49% in long-term debt and 51% in common equity.

The components of our total debt outstanding (short-term and long-term) to our total capitalization as of October 31, 2012 and 2011 are summarized below.

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	October 31				October 31
In thousands	2012		Percentage		2011		Percentage
Short-term debt	$	365,000		16 %	$	331,000		16 %
Long-term debt		975,000		41 %		675,000		34 %
Total debt		1,340,000		57 %		1,006,000		50 %
Common stockholders’ equity		1,027,004		43 %		996,923		50 %
Total capitalization (including short-term debt)	$	2,367,004		100 %	$	2,002,923		100 %

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving credit facility and our CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.

As of October 31, 2012, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A3” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our CP program at “A1” and “P2”, respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, capital structure or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of October 31, 2012, there has been no event of default giving rise to acceleration of our debt.

The default provisions of some or all of our senior debt include:

• Failure to make principal or interest payments,

• Bankruptcy, liquidation or insolvency,

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

• Specified events under the Employee Retirement Income Security Act of 1974,

• Change in control, and

• Failure to observe or perform covenants, including:

• Interest coverage of at least 1.75 times. Interest coverage was 4.72 times as of October 31, 2012;

• Funded debt cannot exceed 70% of total capitalization. Funded debt was 57% of total capitalization as of October 31, 2012;

• Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization. There is no funded debt of our subsidiaries as of October 31, 2012;

• Restrictions on permitted liens;

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

• Restrictions on burdensome agreements.

Contractual Obligations and Commitments

We have incurred various contractual obligations and commitments in the normal course of business. In November 2012, we contractually committed to provide funding of an estimated $180 million for our 24% equity membership of Constitution Pipeline Company, LLC. For further information about this contractual obligation, which is not reflected in the table below as of October 31, 2012, see the previous discussion in “Cash Flows from Investing Activities” 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. As of October 31, 2012, our estimated recorded and unrecorded contractual obligations are as follows.

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	Payments Due by Period
	Less than		1-3		3-5		More than
In thousands	1 year		Years		Years		5 Years		Total
Recorded contractual obligations:
Long-term debt (1)	$	-	$	140,000	$	35,000	$	800,000	$	975,000
Short-term debt (2)		365,000		-		-		-		365,000
Total recorded contractual obligations		365,000		140,000		35,000		800,000		1,340,000
Unrecorded contractual obligations and commitments: (3)
Pipeline and storage capacity (4)		152,163		349,224		119,902		227,477		848,766
Gas supply (5)		6,149		-		-		-		6,149
Interest on long-term debt (6)		47,831		140,052		86,431		355,200		629,514
Telecommunications and information technology (7)		9,459		12,244		-		-		21,703
Qualified and nonqualified pension plan funding (8)		21,198		34,640		11,885		-		67,723
Postretirement benefits plan funding (8)		1,500		4,000		1,300		-		6,800
Operating leases (9)		4,265		12,109		7,393		28,241		52,008
Other purchase obligations (10)		28,798		-		-		-		28,798
Letters of credit (11)		3,649		-		-		-		3,649
Total unrecorded contractual obligations and commitments		275,012		552,269		226,911		610,918		1,665,110
Total contractual obligations and commitments	$	640,012	$	692,269	$	261,911	$	1,410,918	$	3,005,110

(1) See Note 4 to the consolidated financial statements.

(2) See Note 5 to the consolidated financial statements.

(3) In accordance with generally acceptable accounting principles in the United States (GAAP), these items are not reflected in the Consolidated Balance Sheets.

(4) Recoverable through PGA procedures.

(5) Reservation fees are recoverable through PGA procedures.

(6) See Note 4 to the consolidated financial statements.

(7) Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, and cell phone and pager usage fees.

(8) Estimated funding beyond five years is not available. See Note 9 to the consolidated financial statements.

(9) See Note 8 to the consolidated financial statements. Operating lease payments do not include payments for common area maintenance, utilities or tax payments.

(10) Consists primarily of pipeline products, vehicles, contractors and merchandise.

(11) See Note 5 to the consolidated financial statements.

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Off-balance Sheet Arrangements

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

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.

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 residential and commercial customer revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA mechanisms also serve 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 mechanisms. Without the WNA and margin decoupling mechanisms, our operating revenues and margin in 2012 would have been lower by $60.1 million and higher by $11.9 million and $14.7 million in 2011 and 2010, 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

50

estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable. Secondary market revenues are recognized when the physical sales are delivered based on contract or market prices.

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

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, historical regulatory treatment of similar costs in our jurisdictions, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on our assessment that reflects the current political and regulatory climate at the state and federal levels, we believe that all of our regulatory assets are recoverable in current rates or future rate proceedings. However, this assessment is subject to change in the future.

Regulatory assets as of October 31, 2012 and 2011 totaled $293.1 million and $200.1 million, respectively. Regulatory liabilities as of October 31, 2012 and 2011 totaled $489.7 million and $467 million, respectively. The detail of these regulatory assets and liabilities is presented in “Rate-Regulated Basis of Accounting” in Note 1 to the consolidated financial statements.

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

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

51

differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods, and we cannot predict with certainty what these factors will be in the future.

The discount rate has been separately determined for each plan by projecting the plan’s cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s 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 4.67% in 2011 to 3.51% in 2012. For the nonqualified pension plans, the weighted average discount rate used in the measurement of the benefit obligation changed from 4.10% in 2011 to 2.95% in 2012. Similarly, the weighted average discount rate for postretirement benefits changed from 4.36% in 2011 to 3.34% in 2012. The lower discount rates discussed above reflect the lower yields found in the AA corporate bond market where the bond price has increased. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, the initial health care cost trend rate was assumed to be 7.70% in 2012 declining gradually to 5% by 2027.

In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocations for qualified pension plan assets and other postretirement benefit assets to be approximately 50% equity securities and 50% fixed income securities. To the extent that the actual rate of return on assets realized during the fiscal year is greater or less than the assumed rate, that year’s qualified pension plan and postretirement benefits plan costs are not affected; instead, this gain or loss reduces or increases the future costs of the plans over the average remaining service period for active employees. The expected long-term rate of return on plan assets was 8% in 2010, 2011 and 2012. Based on a fairly constant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.87% in 2010, decreasing to 3.78% in 2011 and further decreasing to 3.76% in 2012 due to changes in the demographics of the participants.

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

During 2012, we recorded costs of $5.5 million related to our qualified pension plan and postretirement benefits plan. We estimate 2013 expenses for these two plans to be in the range of $11 to $12 million representing an increase of $5.5 to $6.5 million over 2012. These estimates reflect the discount rates and assumed rate of return on the plan assets discussed above for each plan.

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

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	Change in			Impact on 2012		Impact on Projected
Actuarial Assumption	Assumption			Benefit Cost		Benefit Obligation
				Increase (Decrease) In thousands
Discount rate		(.25	)%	$	551	$	7,999
Rate of return on plan assets		(.25	)%		634		N/A
Rate of increase in compensation		.25	%		658		4,629

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 2012		Impact on Accumulated
	Change in			Postretirement		Postretirement Benefit
Actuarial Assumption	Assumption			Benefit Cost		Obligation
				Increase (Decrease)
				In thousands
Discount rate		(.25	)%	$	11	$	924
Rate of return on plan assets		(.25	)%		53		N/A
Health care cost trend rate		.25	%		8		167

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

Gas Supply and Regulatory Proceedings

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

In November 2012, we executed our supply diversification strategy to bring abundant and low cost natural gas supplies from the Marcellus supply basin to our natural gas markets in the Carolinas. We signed a long-term contract with Cabot Oil & Gas to purchase firm, price-competitive Marcellus gas supplies. We also signed a long-term firm contract with Williams-Transco for its Leidy Southeast expansion project to transport those gas supplies to our markets. These new supply arrangements are scheduled to begin in December 2015, and we believe they will provide diversification, reliability and gas cost benefits to Piedmont’s customers across the Carolinas.

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Natural gas demand is continuing to grow in our service area, particularly to provide natural gas delivery service to power generation facilities as discussed in the preceding section of “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For further information on our equity venture with Cardinal that expanded our firm capacity requirement in order to serve a power generation facility in Wayne County, North Carolina, see Note 12 to the consolidated financial statements.

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

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

Equity Method Investments

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

Environmental Matters

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

Accounting Guidance

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

International Financial Reporting Standards (IFRS)

In early 2010, the SEC expressed its commitment to the development of a single set of high quality globally accepted accounting standards and directed its staff to execute a work plan addressing specific areas of concern regarding the potential incorporation of IFRS for the U.S. The work plan and progress made by the Financial Accounting Standards Board and the International Accounting Standards Board (IASB) to achieve convergence on some key accounting standards would be foundational to the SEC’s decision on whether, when and how the U.S. might adopt IFRS. The SEC has stated that the fundamental question is whether transitioning to IFRS is in the best interests of the U.S. securities markets generally and U.S. investors specifically.

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In July 2012, the SEC Staff released its final report on the work plan that includes its summary findings by the SEC Staff on the following:

• Development of IFRS,

• Interpretive process,

• Use of national standard setters by the IASB,

• Global application and enforcement,

• Governance of the IASB,

• Status of funding, and

• Investor understanding.

The final report does not contain a recommendation for SEC action. A Staff recommendation will be made at some later unspecified date.

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

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 all of these risks in accordance with defined policies and procedures under the direction of the Treasurer and Chief Risk Officer and also an Enterprise Risk Management program and with the direction of the Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures.

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

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. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

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We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party.

We have mitigated our exposure to the risk of non-payment of utility bills by our customers. In North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. Effective in March 2012, we recover gas costs related to uncollectible accounts through PGA procedures in Tennessee similar to North Carolina and South Carolina. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

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, 2012, 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, 2012, we had $365 million of short-term debt outstanding as commercial paper at an interest rate of .42%. 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 $4.2 million during 2012.

As of October 31, 2012, information about our long-term debt is presented below.

																						Fair Value as
	Expected Maturity Date																					of October 31,
In millions	2013			2014			2015			2016			2017			Thereafter			Total			2012
Fixed Rate Long-term Debt	$	-		$	100		$	-		$	40		$	35		$	800.0		$	975.0		$	1,163.2
Average Interest Rate		-	%		5	%		-	%		2.92	%		8.51	%		5.21	%		5.22	%

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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” in “Current Assets” or any over-recoveries are included in “Amounts due to customers” in “Current Liabilities” in the Consolidated Balance Sheets for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange traded instruments and have used over-the-counter instruments of various durations to hedge price volatility on a portion of our natural gas requirements, subject to regulatory review and approval.

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

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

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. This risk is mitigated by a WNA mechanism designed to offset the impact of colder-than-normal or warmer-than-normal weather during the months of November through March in our residential and commercial markets. Effective in March 2012, the additional months of April and October are included in the Tennessee WNA mechanism. In North Carolina, we manage our weather risk through a year round margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold. We are exposed to weather risks in our industrial markets to the extent our margin is collected through volumetric rates in all of our jurisdictions.

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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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Piedmont Natural Gas Company, Inc.

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the “Company”) as of October 31, 2012 and 2011, and the related consolidated statements of comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2012, 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, 2012, 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 21, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Charlotte, North Carolina

December 21, 2012

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Consolidated Balance Sheets

October 31, 2012 and 2011

ASSETS

In thousands	2012		2011
Utility Plant:
Utility plant in service	$	3,746,178	$	3,377,310
Less accumulated depreciation		1,036,814		974,631
Utility plant in service, net		2,709,364		2,402,679
Construction work in progress		388,979		217,832
Plant held for future use		6,743		6,751
Total utility plant, net		3,105,086		2,627,262
Other Physical Property, at cost (net of accumulated   depreciation of $843 in 2012 and $806 in 2011)		415		452
Current Assets:
Cash and cash equivalents		1,959		6,777
Trade accounts receivable (less allowance for doubtful     accounts of $1,579 in 2012 and $1,347 in 2011)		56,700		57,035
Income taxes receivable		31,606		15,966
Other receivables		2,104		2,547
Unbilled utility revenues		24,012		28,715
Inventories:
Gas in storage		72,661		91,124
Materials, supplies and merchandise		934		1,368
Gas purchase derivative assets, at fair value		3,153		2,772
Amounts due from customers		81,626		38,649
Prepayments		30,600		39,128
Deferred income taxes		-		1,793
Other current assets		287		147
Total current assets		305,642		286,021
Noncurrent Assets:
Equity method investments in non-utility activities		87,867		85,121
Goodwill		48,852		48,852
Marketable securities, at fair value		2,131		1,439
Overfunded postretirement asset		-		22,879
Regulatory asset for postretirement benefits		123,290		81,073
Unamortized debt expense		13,583		11,315
Regulatory cost of removal asset		21,129		19,336
Other noncurrent assets		61,944		58,791
Total noncurrent assets		358,796		328,806
Total	$	3,769,939	$	3,242,541

See notes to consolidated financial statements.

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Consolidated Balance Sheets

October 31, 2012 and 2011

CAPITALIZATION AND LIABILITIES

In thousands	2012		2011
Capitalization:
Stockholders’ equity:
Cumulative preferred stock - no par value - 175 shares authorized	$	-	$	-
Common stock - no par value - shares authorized: 200,000;       shares outstanding: 72,250 in 2012 and 72,318 in 2011		442,461		446,791
Retained earnings		584,848		550,584
Accumulated other comprehensive loss		(305)		(452)
Total stockholders’ equity		1,027,004		996,923
Long-term debt		975,000		675,000
Total capitalization		2,002,004		1,671,923
Current Liabilities:
Short-term debt		365,000		331,000
Trade accounts payable		94,269		85,721
Other accounts payable		47,699		43,959
Accrued interest		21,450		20,038
Customers’ deposits		21,739		25,462
Current deferred taxes		13,542		-
General taxes accrued		21,504		21,262
Amounts due to customers		28		2,617
Other current liabilities		7,320		4,073
Total current liabilities		592,551		534,132
Noncurrent Liabilities:
Deferred income taxes		597,211		512,961
Unamortized federal investment tax credits		1,669		2,004
Accumulated provision for postretirement benefits		37,299		14,671
Cost of removal obligations		492,963		466,000
Other noncurrent liabilities		46,242		40,850
Total noncurrent liabilities		1,175,384		1,036,486
Commitments and Contingencies (Note 8)
Total	$	3,769,939	$	3,242,541

See notes to consolidated financial statements.

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Consolidated Statements of Comprehensive Income

For the Years Ended October 31, 2012, 2011 and 2010

	2012		2011		2010
In thousands except per share amounts
Operating Revenues	$	1,122,780	$	1,433,905	$	1,552,295
Cost of Gas		547,334		860,266		999,703
Margin		575,446		573,639		552,592
Operating Expenses:
Operations and maintenance		242,599		225,351		219,829
Depreciation		103,192		102,829		98,494
General taxes		34,831		38,380		33,909
Utility income taxes		69,101		64,068		62,082
Total operating expenses		449,723		430,628		414,314
Operating Income		125,723		143,011		138,278
Other Income (Expense):
Income from equity method investments		23,904		24,027		28,854
Gain on sale of interest in equity method investment		-		-		49,674
Non-operating income		1,288		1,762		659
Charitable contributions		(1,068)		(1,818)		(1,363)
Non-operating expense		(787)		(1,204)		(643)
Income taxes		(9,116)		(8,218)		(29,794)
Total other income (expense)		14,221		14,549		47,387
Utility Interest Charges:
Interest on long-term debt		41,412		46,070		52,666
Allowance for borrowed funds used during construction		(25,211)		(8,619)		(9,981)
Other		3,896		6,541		1,026
Total utility interest charges		20,097		43,992		43,711
Net Income		119,847		113,568		141,954
Other Comprehensive Income, net of tax:
Unrealized loss from hedging activities of equity method     investments, net of tax of ($530), ($371) and ($52) for the years     ended October 31, 2012, 2011 and 2010, respectively.		(826)		(576)		(88)
Reclassification adjustment of realized gain from hedging activities     of equity method investments included in net income, net of tax of     $621, $420 and $1,291 for the years ended October 31, 2012, 2011     and 2010, respectively.		973		654		2,005
Total other comprehensive income		147		78		1,917
Comprehensive Income	$	119,994	$	113,646	$	143,871
Average Shares of Common Stock:
Basic		71,977		72,056		72,275
Diluted		72,278		72,266		72,525
Earnings Per Share of Common Stock:
Basic	$	1.67	$	1.58	$	1.96
Diluted	$	1.66	$	1.57	$	1.96

See notes to consolidated financial statements.

63

Consolidated Statements of Cash Flows

For the Years Ended October 31, 2012, 2011 and 2010

In thousands	2012		2011		2010
Cash Flows from Operating Activities:
Net income	$	119,847	$	113,568	$	141,954
Adjustments to reconcile net income to net     cash provided by operating activities:
Depreciation and amortization		109,230		107,046		102,776
Amortization of investment tax credits		(335)		(141)		(277)
Allowance for doubtful accounts		232		418		(61)
Gain on sale of interest in equity method investment, net of tax		-		-		(30,286)
Net gain on sale of property		-		-		(89)
Income from equity method investments		(23,904)		(24,027)		(28,854)
Distributions of earnings from equity method investments		19,590		22,685		28,834
Deferred income taxes, net		99,494		76,962		21,831
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(381)		47		(30,863)
Receivables		5,403		(3,019)		23,493
Inventories		18,897		13,789		2,565
Amounts due from/to customers		(45,566)		26,304		133,794
Settlement of legal asset retirement obligations		(2,038)		(1,493)		(1,141)
Overfunded postretirement asset		22,879		(5,537)		(17,342)
Regulatory asset for postretirement benefits		(42,217)		(16,298)		12,130
Other assets		(10,388)		972		18,184
Accounts payable		4,283		(4,085)		(3,007)
Provision for postretirement benefits		22,628		(134)		(16,836)
Other liabilities		6,861		4,188		3,706
Net cash provided by operating activities		304,515		311,245		360,511
Cash Flows from Investing Activities:
Utility capital expenditures		(529,576)		(243,641)		(199,059)
Allowance for funds used during construction		(25,211)		(8,619)		(9,981)
Contributions to equity method investments		(3,566)		(6,222)		-
Distributions of capital from equity method investments		5,372		3,029		18,260
Proceeds from sale of interest in equity method investment		-		-		57,500
Proceeds from sale of property		1,250		1,074		1,653
Investments in marketable securities		(606)		(486)		(498)
Other		3,044		2,292		3,554
Net cash used in investing activities		(549,293)		(252,573)		(128,571)

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Consolidated Statements of Cash Flows

For the Years Ended October 31, 2012, 2011 and 2010

In thousands	2012		2011		2010
Cash Flows from Financing Activities:
Borrowings under credit facility		350,000		1,723,000		1,058,000
Repayments under credit facility		(681,000)		(1,634,000)		(1,122,000)
Net borrowings - commercial paper		365,000		-		-
Proceeds from issuance of long-term debt		300,000		200,000		-
Retirement of long-term debt		-		(256,922)		(60,590)
Expenses related to issuance of debt		(3,908)		(3,902)		(46)
Issuance of common stock through dividend reinvestment and employee stock plans		22,123		20,233		19,099
Repurchases of common stock		(26,528)		(23,004)		(47,295)
Dividends paid		(85,693)		(82,913)		(80,255)
Other		(34)		(6)		(792)
Net cash provided by (used in) financing activities		239,960		(57,514)		(233,879)
Net (Decrease) Increase in Cash and Cash Equivalents		(4,818)		1,158		(1,939)
Cash and Cash Equivalents at Beginning of Year		6,777		5,619		7,558
Cash and Cash Equivalents at End of Year	$	1,959	$	6,777	$	5,619
Cash Paid During the Year for:
Interest	$	44,571	$	50,136	$	56,554
Income Taxes:
Income taxes paid	$	4,770	$	5,649	$	32,305
Income taxes refunded		8,437		16,958		1,845
Income taxes, net	$	(3,667)	$	(11,309)	$	30,460
Noncash Investing and Financing Activities:
Accrued construction expenditures	$	43,643	$	18,055	$	3,225
Guaranty		-		-		1,234

See notes to consolidated financial statements.

65

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2012, 2011 and 2010

In thousands except per share amounts	Common Stock		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
Balance, October 31, 2009	$	471,569	$	458,826	$	(2,447)	$	927,948
Comprehensive Income:
Net income				141,954				141,954
Other comprehensive income						1,917		1,917
Total comprehensive income								143,871
Common Stock Issued		21,366						21,366
Common Stock Repurchased		(47,276)						(47,276)
Rescission Offer		(19)						(19)
Costs of Rescission Offer				(792)				(792)
Tax Benefit from Dividends Paid on ESOP Shares				98				98
Dividends Declared ($1.11 per share)				(80,255)				(80,255)
Balance, October 31, 2010		445,640		519,831		(530)		964,941
Comprehensive Income:
Net income				113,568				113,568
Other comprehensive income						78		78
Total comprehensive income								113,646
Common Stock Issued		24,155						24,155
Common Stock Repurchased		(23,004)						(23,004)
Costs of Rescission Offer				(6)				(6)
Tax Benefit from Dividends Paid on ESOP Shares				104				104
Dividends Declared ($1.15 per share)				(82,913)				(82,913)
Balance, October 31, 2011		446,791		550,584		(452)		996,923

66

Consolidated Statements of Stockholders’ Equity

For the Years Ended October 31, 2012, 2011 and 2010

In thousands except per share amounts	Common Stock		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
Comprehensive Income:
Net income				119,847				119,847
Other comprehensive income						147		147
Total comprehensive income								119,994
Common Stock Issued		22,198						22,198
Common Stock Repurchased		(26,528)						(26,528)
Tax Benefit from Dividends Paid on ESOP Shares				110				110
Dividends Declared ($1.19 per share)				(85,693)				(85,693)
Balance, October 31, 2012	$	442,461	$	584,848	$	(305)	$	1,027,004

The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 2012 and 2011 are as follows.

In thousands	2012		2011
Hedging activities of equity method investments	$	(305)	$	(452)

See notes to consolidated financial statements.

67

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation

Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For further information on equity method investments, see Note 12 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

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

Use of Estimates

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

68

Segment Reporting

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

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

Rate-Regulated Basis of Accounting

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

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2012 and 2011 are as follows.

69

In thousands	2012		2011
Regulatory Assets:
Unamortized debt expense	$	13,583	$	11,315
Amounts due from customers		81,626		38,649
Environmental costs *		10,202		9,644
Deferred operations and maintenance expenses *		7,050		7,676
Deferred pipeline integrity expenses *		13,691		7,927
Deferred pension and other retirement benefits costs *		20,139		22,119
Amounts not yet recognized as a component of pension and other retirement benefit costs		123,290		81,073
Regulatory cost of removal asset		21,129		19,336
Other *		2,394		2,396
Total	$	293,104	$	200,135
Regulatory Liabilities:
Regulatory cost of removal obligations	$	464,334	$	438,605
Amounts due to customers		28		2,617
Deferred income taxes*