Piedmont Natural Gas Company, Inc.

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended October 31, 2005


o		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 þ No o

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes o No þ

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

Indicate by check mark 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. þ

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

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

State the aggregate market value of the voting common equity held by non-affiliates of the registrant as of April 30, 2005.

Common Stock, no par value — $1,744,011,535

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 January 10, 2006

Common Stock, no par value		76,612,685

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 3, 2006, are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

2005 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS


		Page
Part I.

Item 1.	Business		1
Item 2.	Properties		6
Item 3.	Legal Proceedings		7
Item 4.	Submission of Matters to a Vote of Security Holders		7

Part II.

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		8
Item 6.	Selected Financial Data		9
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		9
Item 7A.	Quantitative and Qualitative Disclosure about Market Risk		28
Item 8.	Financial Statements and Supplementary Data		29
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		67
Item 9A.	Controls and Procedures		67
Item 9B.	Other Information		71

Part III.

Item 10.	Directors and Executive Officers of the Registrant		72
Item 11.	Executive Compensation		72
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		72
Item 13.	Certain Relationships and Related Transactions		73
Item 14.	Principal Accountant Fees and Services		73

Part IV.

Item 15.	Exhibits and Financial Statement Schedules		74

	Signatures		80

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 primarily engaged in the distribution of natural gas to 990,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

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

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of North Carolina Natural Gas Corporation (NCNG) from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million in cash for estimated working capital. We paid an additional $.3 million in cash for actual working capital in our second quarter ended April 30, 2004. At the time of the acquisition, NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing.

On September 30, 2003, we also purchased for $7.5 million in cash Progress’ equity interest in Eastern North Carolina Natural Gas Company (EasternNC). At that time, EasternNC was a regulated utility with a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. Effective at the close of business on October 25, 2005, we purchased for $1 the remaining 50% interest in common stock of EasternNC from Albemarle Pamlico Economic Development Corporation. EasternNC was merged into Piedmont immediately following the closing.

We have two reportable business segments, regulated utility and non-utility activities. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. Operations of both segments are conducted within the United States of America. For further information on equity method investments and segments, see Note 10 and Note 11, respectively, to the consolidated financial statements.

Operating revenues shown in the consolidated statements of income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For the year ended October 31, 2005, 39% of our operating revenues were from residential customers, 24% from commercial customers, 13% from industrial and power generation customers, 21% from secondary market activity and 3% from various other sources. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments.”

Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

We hold non-exclusive franchises for natural gas service in the communities we serve, with expiration dates from 2005 to 2055. The franchises are adequate for the operation of our gas distribution business and do not contain materially burdensome restrictions or conditions. Two franchise agreements have expired as of October 31, 2005, and nine will expire during the 2006 fiscal year. We continue to operate in those areas pursuant to the provisions of the expired franchises with no significant impact on our business. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed with no material adverse impact on us as most government entities do not want to prevent their citizens from having access to gas service or to interfere with our required system maintenance. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action.

The natural gas distribution business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. During the year ended October 31, 2005, the amount of natural gas in storage varied from 10.1 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 25.4 million dekatherms, and the

aggregate commodity cost of this gas in storage varied from $58.6 million to $151.5 million.

During the year ended October 31, 2005, 106.7 million dekatherms of gas were sold to or transported for large industrial and power-generation customers, compared with 102.5 million dekatherms in 2004. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 89 million dekatherms in 2005, compared with 89.9 million dekatherms in 2004. Weather, as measured by degree days, was 5% warmer than normal in 2005 and 6% warmer than normal in 2004.

The following is a five-year comparison of operating statistics for the years ended October 31, 2001 through 2005. The information presented is not comparable for all periods due to the acquisitions of NCNG and an equity interest in EasternNC effective September 30, 2003.


	2005			2004			2003			2002		2001
Operating Revenues (in thousands):
Sales and Transportation:
Residential	$	686,304		$	624,487		$	524,933		$	358,027	$	525,650
Commercial		421,499			360,355			299,281			191,988		299,672
Industrial		215,505			179,302			112,986			102,127		128,831
For Power Generation		16,248			18,782			3,071			2,368		1,316
For Resale		40,122			38,074			1,948			374		371

Total		1,379,678			1,221,000			942,219			654,884		955,840
Secondary Market Sales		373,353			301,886			273,369			173,592		145,712
Miscellaneous		8,060			6,853			5,234			3,552		6,304

Total	$	1,761,091		$	1,529,739		$	1,220,822		$	832,028	$	1,107,856


Gas Volumes — Dekatherms (in thousands):
System Throughput:
Residential		52,966			54,412			52,603			40,047		47,869
Commercial		36,000			35,483			33,648			25,892		31,002
Industrial		81,102			83,957			60,054			58,414		54,285
For Power Generation		25,591			18,580			2,396			1,734		1,169
For Resale		8,779			8,912			623			41		29

Total		204,438			201,344			149,324			126,128		134,354


Secondary Market Sales		47,057			51,707			45,937			55,679		29,545


Number of Retail Customers Billed (12-month average):
Residential		792,061			771,037			657,965			620,642		601,682
Commercial		91,645			90,328			75,924			72,323		71,069
Industrial		3,146			3,194			2,626			2,583		2,764
For Power Generation		16			13			5			3		3
For Resale		15			15			4			3		3

Total		886,883			864,587			736,524			695,554		675,521


Average Per Residential Customer:
Gas Used — Dekatherms		66.87			70.57			79.95			64.53		79.56
Revenue	$	866.48		$	809.93		$	797.81		$	576.87	$	873.63
Revenue Per Dekatherm	$	12.96		$	11.48		$	9.98		$	8.94	$	10.98

Cost of Gas (in thousands):
Natural Gas Commodity Costs	$	1,226,999		$	943,890		$	790,118		$	408,407	$	670,594
Capacity Demand Charges		117,287			125,178			89,514			89,103		80,622
Natural Gas Withdrawn From (Injected Into) Storage, net		(35,151	)		(11,116	)		(44,069	)		11,620		(868	)


	2005			2004			2003			2002			2001
Regulatory Charges (Credits), net		(47,183	)		(16,582	)		2,379			(12,896	)		19,530

Total	$	1,261,952		$	1,041,370		$	837,942		$	496,234		$	769,878


Supply Available for Distribution (dekatherms in thousands):
Natural Gas Purchased		155,614			163,257			143,716			136,206			121,465
Transportation Gas		97,959			91,795			52,895			48,179			44,285
Natural Gas Withdrawn From (Injected Into) Storage, net		856			775			(2,490	)		(1,461	)		1,648
Company Use		(133	)		(135	)		(147	)		(139	)		(167	)

Total		254,296			255,692			193,974			182,785			167,231

As of October 31, 2005, we had contracts for the following pipeline firm transportation capacity in dekatherms of daily deliverability:


Williams-Transco (including certain upstream arrangements with Dominion and Texas Gas)			645,400
El Paso-Tennessee Pipeline			74,100
Duke-Texas Eastern			37,000
Duke-East Tennessee (through arrangements with Transco)			25,000
NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)			42,800
NiSource-Columbia Gulf			10,000

Total			834,300

As of October 31, 2005, 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. This availability varies from five days to one year:


Piedmont Liquefied Natural Gas (LNG)			278,000
Pine Needle LNG			263,400
Williams-Transco Storage			86,100
NiSource-Columbia Gas Storage			96,400
El Paso-Tennessee Pipeline Storage			55,900
Duke Energy (delivered peaking service)			76,000

Total			855,800

We own or have under contract 29.5 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 purchase natural gas under firm contractual commitments 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 arrangements. The pipeline capacity contracts require the payment of fixed demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement firm contractual commitments with other supply arrangements to serve our interruptible market, or as an alternate supply for inventory withdrawals or injections.

The source of the gas we distribute is primarily the Gulf Coast production region, and is purchased primarily from major producers and marketers. The natural gas production,

processing and pipeline infrastructure in the Gulf of Mexico was significantly affected by hurricanes in August and September 2005, with supplies being shut-in at various levels for extended periods due to lack of power, damage to facilities and lack of gas flow. As part of our long-term plan to diversify our reliance away from the Gulf Coast region, we have contracted with a proposed underground storage facility in West Virginia and with a proposed extension of a natural gas pipeline that accesses gas supplies from Canada and the Rocky Mountains. For further information on gas supply and regulation see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K and Note 3 to the consolidated financial statements.

During the year ended October 31, 2005, 8% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under FERC regulations, certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. Through October 31, 2005, only minimal bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms. The future level of bypass activity cannot be predicted.

The regulated utility competes in the residential and commercial customer markets with other energy products. The most significant competition between natural gas and electricity is for space heating, water heating and cooking. There are four major electric companies within our service areas. We continue to attract the majority of the new residential construction market on or near our distribution mains, and we believe that the consumer’s preference for natural gas includes such factors as reliability, comfort and convenience. Natural gas has historically maintained a price advantage over electricity in our service areas; however, with a tighter national supply and demand balance, wholesale natural gas prices and price volatility have increased over recent years. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer.

As indicated above, many of our customers can utilize a fuel other than natural gas, and 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. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market prices of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers. With higher wholesale gas prices, we anticipate that there may be more fuel switching by large industrial customers in the near term.

During the year ended October 31, 2005, our largest customer contributed $14.2 million, or less than 1%, to total operating revenues.

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

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

As of October 31, 2005, our fiscal year end, we had 2,124 employees, compared with 2,120 as of October 31, 2004.

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 web site at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the Securities and Exchange Commission.

Item 2. Properties

All property shown in the consolidated balance sheets in “Utility Plant” is owned by us and used in our regulated utility segment. This property consists of intangible plant, production plant, storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with 93% of the total invested in distribution and transmission plant to serve our customers. We have approximately 3,000 miles of lateral pipelines up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,700 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on private property. All of these properties are located within our service areas 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.

We own or lease for varying periods district and regional offices in the locations shown below. Lease payments for these various offices totaled $1.9 million for the year ended October 31, 2005.


North Carolina	South Carolina	Tennessee

Burlington Charlotte Elizabeth City Fayetteville Goldsboro Greensboro Hickory High Point Indian Trail New Bern Reidsville Rockingham	Anderson Gaffney Greenville Spartanburg	Nashville


Salisbury Spruce Pine Tarboro Wilmington Winston-Salem

We sold our corporate headquarters building in 2005 and entered into a ten-year lease on new office space beginning November 1, 2005. The lease payments for the ten-year term range from $3 million to $3.4 million annually.

All property shown in the consolidated balance sheets in “Other Physical Property” is owned by the parent company and primarily consists of residential and commercial water heaters leased to natural gas customers. None of our 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 litigation in the normal course of business and do not expect the outcomes to have any material impact on our financial position or results of operations.

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

No matters were submitted to a vote of security holders during our fourth quarter ended October 31, 2005.

PART II

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

(a) 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, 2005 and 2004.


2005	High	Low	2004	High	Low
Quarter ended:			Quarter ended:
January 31	$24.35	$22.01	January 31	$21.98	$19.71
April 30	24.44	21.76	April 30	21.53	19.90
July 31	24.99	22.84	July 31	21.59	19.16
October 31	25.80	22.33	October 31	23.03	20.45

(b) As of January 10, 2006, our Common Stock was owned by 16,606 shareholders of record.

(c) The following table provides information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2005 and 2004. We expect that comparable cash dividends will continue to be paid in the future.


	Dividends Paid		Dividends Paid
2005	Per Share	2004	Per Share
Quarter ended:		Quarter ended:
January 31	21.50¢	January 31	20.75¢
April 30	23.00¢	April 30	21.50¢
July 31	23.00¢	July 31	21.50¢
October 31	23.00¢	October 31	21.50¢

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, 2005, net earnings available for restricted payments were greater than retained earnings; therefore, none of our retained earnings were restricted.

The following table provides information with respect to repurchases of our Common Stock under the Common Stock Open Market Purchase Program during the fourth quarter ended October 31, 2005.


					Total Number of		Maximum Number
	Total Number				Shares Purchased		of Shares that May
	of Shares		Average Price		as Part of Publicly		Yet be Purchased
Period	Purchased		Paid Per Share		Announced Program		Under the Program *
								1,896,100
8/1/05 – 8/31/05		110,000	$	24.10		110,000		1,786,100
9/1/05 – 9/30/05		25,000	$	24.78		25,000		1,761,100
10/1/05 – 10/31/05		69,000	$	24.34		69,000		1,692,100

Total		204,000				204,000


*		Common Stock Open Market Purchase Program was announced on June 4, 2004, to repurchase up to three million shares of Common Stock.

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 stock split in 2004. The Board also approved the repurchase of up to four million additional shares of currently outstanding shares of Common Stock and amended the program to provide for repurchases to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares.

Item 6. Selected Financial Data

The following table provides selected financial data for the years ended October 31, 2001 through 2005. The information presented is not comparable for all periods due to the acquisitions of North Carolina Natural Gas Corporation (NCNG) and an equity interest in Eastern North Carolina Natural Gas Company (EasternNC) effective September 30, 2003, as discussed in Note 2 to the consolidated financial statements.


In thousands except per share amounts	2005		2004*		2003*		2002*		2001*

Operating Revenues	$	1,761,091	$	1,529,739	$	1,220,822	$	832,028	$	1,107,856
Margin (Operating Revenues less Cost of Gas)	$	499,139	$	488,369	$	382,880	$	335,794	$	337,978
Net Income	$	101,270	$	95,188	$	74,362	$	62,217	$	65,485
Earnings per Share of Common Stock:
Basic	$	1.32	$	1.28	$	1.11	$	.95	$	1.02
Diluted	$	1.32	$	1.27	$	1.11	$	.94	$	1.01
Cash Dividends Per Share of Common Stock	$	.905	$	.8525	$	.8225	$	.7925	$	.76
Total Assets	$	2,602,490	$	2,392,164	$	2,339,283	$	1,478,014	$	1,407,521
Long-Term Debt (less current maturities)	$	625,000	$	660,000	$	460,000	$	462,000	$	509,000


*		Total assets for the years 2001 through 2004 have been restated. See Note 13 to the consolidated financial statements.

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

The following discussion gives effect to the restatement of the consolidated balance sheet and the consolidated statements of cash flows discussed in Note 13 to the consolidated financial statements.

Overview Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in portions of North

Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments.

The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers.

The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.

Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are generated during the winter season. During warm winters or unevenly cold winters, heating customers may significantly reduce their consumption of natural gas. Although we have weather normalization adjustment (WNA) mechanisms that are designed to protect a portion of our revenues against warmer-than-normal weather, deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In a general rate case proceeding during 2005, the North Carolina Utilities Commission (NCUC) ordered the establishment of a Customer Utilization Tracker (CUT) and the elimination of the WNA, effective November 1, 2005. The North Carolina Office of the Attorney General has filed a notice of appeal in this rate proceeding challenging the lawfulness of the NCUC’s authorization and approval of the CUT. For further information, see Note 3 to the consolidated financial statements.

Over the past few years, there have been significant increases in the wholesale cost of natural gas. The relationship between supply and demand has the greatest impact on wholesale gas prices. The natural gas production, processing and pipeline infrastructure in the Gulf of Mexico was significantly affected by hurricanes in August and September 2005. After the hurricanes, this production was shut-in at various levels for extended periods due to lack of power, damage to facilities and lack of gas flow. Some of the production remains closed or is operating at reduced capacity. As a result of this disruption in supply and other supply and demand factors, wholesale gas prices are expected to remain high and significantly increase customers’ bills during the 2005-2006 heating season. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers; however, price increases could shift our customers’ preference away from natural gas toward other energy sources, particularly in the industrial market. Price increases could also affect the consumption levels of our customers or make it more difficult for them to pay their bills. We expect that the wholesale price of natural gas will remain high and volatile until natural gas supply and demand are in better balance.

On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005, the first major energy legislation passed by Congress in 13 years. We believe this legislation is the first step towards addressing our nation’s energy issues, but it falls short. We believe the legislation does not adequately stimulate domestic natural gas supply development and

additional measures are necessary to provide access to supplies in areas such as the Outer Continental Shelf, the Rocky Mountains and Alaska. It is too early to identify the impact of this legislation on us.

Although we have been operating in a relatively low-interest-rate environment for both short- and long-term debt financing during the past few years, the federal funds rate has steadily increased and is the highest it has been in over four years. We anticipate that interest rates will continue to rise, which could result in an increase in rates on our borrowings.

Part of our strategic plan is to manage our gas distribution business through sound rate and regulatory initiatives, control of our operating costs and implementation of new technologies. We are working to enhance the value and growth of our utility assets by good management of capital spending, both for improvements for current customers and the pursuit of customer growth opportunities in our service areas. We strive for quality customer service by investing in systems, processes and people. We will continue to work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

Our strategic plan includes a focus on maintaining a debt-to-capitalization ratio within a range of 45 to 50%. We will continue to stress the importance of maintaining a strong balance sheet and investment-grade credit ratings to support our operating and investment needs. We continually monitor our level of short-term borrowings and secure short-term bank lines that meet our short-term operating needs.

Results of Operations Net income increased $6.1 million in 2005 compared with 2004 primarily due to the following changes which increased net income:

	•		$10.8 million increase in margin (operating revenues less cost of gas).

	•		$3.1 million decrease in utility interest charges.

	•		$1.5 million gain on the sale of marketable securities.

	•		$7.4 million decrease in charitable contributions.

	•		$1.6 million decrease in income tax expense due to true-up of the effective federal income tax rate following the sale of our propane interests.

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

	•		$6.7 million increase in operations and maintenance expenses.

	•		$4.7 million decrease from the non-recurring gain in 2004 on the sale of our equity method investment in propane.

	•		$2.9 million increase in depreciation expense.

	•		$2.8 million increase in general taxes.

Operating results for 2004 reflect the full effect of the acquisitions of NCNG and an equity interest in EasternNC on September 30, 2003. The net income increase of $20.8 million in 2004 compared with 2003 was primarily due to the following changes which increased net income:

	•		$105.5 million increase in margin.

	•		$9.4 million increase in income from equity method investments.

	•		$4.7 million gain on the sale of our equity method investment in propane.

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

	•		$48.2 million increase in operations and maintenance expenses.

	•		$19.1 million increase in depreciation expense.

	•		$8.4 million increase in charitable contributions.

	•		$7.2 million increase in interest on long-term debt.

	•		$2.6 million increase in general taxes.

Compared with the prior year, weather in our service area, as measured by degree days, was 2% warmer in 2005, 9% warmer in 2004 and 21% colder in 2003. Volumes of gas delivered to customers were 204.4 million dekatherms in 2005, compared with 201.3 million dekatherms in 2004 and 149.3 million dekatherms in 2003. In addition to volumes delivered to customers, secondary market sales volumes were 47.1 million dekatherms in 2005, compared with 51.7 million dekatherms in 2004 and 45.9 million dekatherms in 2003.

Operating revenues in 2005 increased $231.4 million compared with 2004 primarily due to the following increases:

	•		$133.4 million from increased commodity gas costs passed through to customers.

	•		$71.5 million from secondary market activity. Secondary market transactions consist of off-system sales and capacity release arrangements.

	•		$11.1 million from changes in delivery mix, including the impacts of sales revenues versus transportation revenues and sales and transportation to power generation customers.

	•		$6.3 million from the WNA due to charges of $8.4 million in 2005 compared with charges of $2.1 million in 2004. As discussed in “Financial Condition and Liquidity” below, we had, through October 31, 2005, a WNA in all three states designed to offset the impact of unusually cold or warm weather on residential and commercial customer billings and margin.

Operating revenues in 2004 increased $308.9 million compared with 2003 primarily due to the following increases:

	•		$259.9 million from the increase in volumes of 59.6 million dekatherms and facility charges from NCNG customers, including the impact of WNA credits of $1.6 million.

	•		$28.5 million from secondary market activity.

	•		$32.2 million from increased commodity gas costs.

	•		$13.3 million from the WNA due to charges of $3.7 million in 2004 compared with credits of $9.6 million in 2003, excluding the impact of the WNA for NCNG.

	•		$8.4 million from increased customer rates and charges, including changes in rate design, in Tennessee, effective November 1, 2003.

Excluding NCNG, volumes decreased 7.8 million dekatherms in 2004 primarily due to 9% warmer weather. This decrease resulted in a decrease in operating revenues of $46.8 million.

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

Cost of gas in 2005 increased $220.6 million compared with 2004 primarily due to the following increases:

	•		$133.4 million from increased commodity gas costs.

	•		$68.5 million from increased secondary market activity.

	•		$13.1 million from increased volumes and changes in delivery mix.

Cost of gas in 2004 increased $203.4 million compared with 2003 primarily due to the following increases:

	•		$166.3 million from the increase in volumes from NCNG customers.

	•		$30.3 million from increased secondary market activity.

	•		$32.2 million from increased commodity gas costs.

Excluding NCNG, volumes decreased 7.8 million dekatherms in 2004 which resulted in a decrease in cost of gas of $32.8 million.

Margin increased $10.8 million in 2005 compared with 2004 primarily due to growth in the residential and commercial customer base, partially offset by decreased consumption because of warmer weather, equipment efficiencies and conservation. The margin increase of $105.5 million in 2004 compared with 2003 was primarily due to the increase in volumes and facility charges from NCNG customers and growth in the residential and commercial customer base.

Operations and maintenance expenses increased $6.7 million in 2005 compared with 2004 primarily due to the following increases:

	•		$5.5 million in employee benefits expense primarily due to pension and postretirement health care and life insurance costs.

	•		$3.8 million in payroll costs primarily due to increases in vacation benefits, merit and bargaining unit contract increases and long-term incentive plan accruals.

	•		$1.2 million in utilities primarily due to increased telecommunication costs.

	•		$1.1 million in rents and leases primarily due to buyout of lease contracts on printers and copiers and other maintenance costs.

	•		$.6 million in transportation primarily due to an increase in fuel costs.

These increases were partially offset by the following decreases:

	•		$2.3 million due to the accrual in the prior year of the projected benefit obligation for a retirement plan for certain current and former members of the Board of Directors.

	•		$2 million in outside consultant fees primarily for a continuous business process improvement program and an integrated mapping project.

	•		$1.4 million in other corporate expenses primarily due to accruals for severance agreements and sales tax expense in 2004 that did not recur in 2005 and lower bank fees.

Operations and maintenance expenses increased $48.2 million in 2004 compared with 2003 primarily due to the following increases:

•

$22.8 million in payroll costs primarily due to merit increases, the addition of NCNG employees for a full year and accruals of short-term incentive plans.

	•		$5.9 million in other corporate expenses primarily due to amortization of NCNG integration costs and the deferral in 2003 to a regulatory asset of EasternNC’s operations and maintenance costs that were expensed prior to September 30, 2003. See Note 3 to the consolidated financial statements.

	•		$4.3 million in employee benefits expense primarily due to pension and postretirement health care and life insurance costs.

	•		$4 million in outside labor primarily due to NCNG operations and increased costs of outsourced mainframe utilization.

	•		$2.4 million in transportation primarily due to NCNG operations.

	•		$2.3 million due to accrual of the projected benefit obligation for the Board of Directors’ retirement plan.

	•		$1.6 million in utilities primarily due to NCNG operations.

	•		$1.2 million in materials primarily due to NCNG operations.

	•		$1.2 million in outside consulting fees primarily for a continuous business process improvement program, the pipeline integrity management program and an integrated mapping project.

Depreciation expense increased from $63.2 million to $85.2 million over the three-year period 2003 to 2005 primarily due to increases in plant in service, including a full year of depreciation expense in 2005 and 2004 compared with only one month in 2003 on plant acquired from NCNG.

General taxes increased $2.8 million in 2005 compared with 2004 primarily due to the following changes:

	•		$1.8 million increase in property taxes as the expense in 2004 reflected the impact of a favorable court ruling that reduced assessed property values and the estimated tax accruals for prior periods.

	•		$.3 million increase in other property taxes.

	•		$.4 million increase in payroll taxes.

General taxes increased $2.6 million in 2004 compared with 2003 primarily due to the following changes:

	•		$1.7 million increase in payroll taxes primarily due to NCNG operations.

	•		$1.5 million increase in property taxes primarily due to NCNG operations.

	•		$.3 million decrease in Tennessee gross receipts taxes.

Income from equity method investments increased $.3 million in 2005 compared with 2004.

Income from equity method investments increased $9.4 million in 2004 compared with 2003 primarily due to an increase of $8.9 million in earnings from SouthStar, including a one-time benefit of $2.5 million from the resolution of certain disproportionate sharing issues between the members of SouthStar.

The gain on sale of equity method investments of $4.7 million in 2004 resulted from the sale of our propane interests effective January 20, 2004. See Note 10 to the consolidated financial statements.

The gain on sale of marketable securities of $1.5 million in 2005 resulted from the sale in February 2005 of common units of Energy Transfer Partners, L.P., which we received in connection with the sale of our propane interests in 2004.

The equity portion of the allowance for funds used during construction (AFUDC) was zero in 2005, $.9 million in 2004 and $1.1 million in 2003. AFUDC is allocated between equity and debt based on actual amounts computed and the ratio of construction work in progress to average short-term borrowings.

Non-operating income is comprised of merchandising, service work, the non-equity-method portion of the activities of our subsidiaries, interest income and other miscellaneous income. Non-operating income in 2005 includes a pre-tax gain on the sale of the corporate office land of $1.7 million. Changes in all other non-operating income were not significant.

Charitable contributions decreased $7.4 million in 2005 compared with 2004 primarily due to the initial commitment in October 2004 of $7 million to the newly established charitable foundation. We contributed an additional $1 million to the foundation in 2005. Charitable contributions increased $8.4 million in 2004 compared with 2003 primarily due to the $7 million gift to the foundation.

Utility interest charges decreased $3.1 million in 2005 compared with 2004 primarily due to the following changes:

	•		$3.5 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2005.

	•		$1 million decrease in interest on short-term debt from commercial paper used to temporarily finance the NCNG and EasternNC acquisitions.

	•		$1.5 million decrease due to an increase in AFUDC allocated to debt.

	•		$1.7 million increase in interest on short-term debt due to higher balances outstanding at higher interest rates, largely due to purchases of gas at higher prices.

	•		$1.2 million increase in interest on long-term debt due to higher balances outstanding, including amounts due to the permanent financing of the NCNG and EasternNC acquisitions.

Utility interest charges increased $7.2 million in 2004 compared with 2003 primarily due to the following changes:

	•		$7.2 million increase in interest on long-term debt due to higher balances outstanding, including amounts due to the permanent financing of the NCNG and EasternNC acquisitions.

	•		$.8 million increase for interest in connection with the Internal Revenue Service audit of our federal income tax return for 2001.

	•		$1.3 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2004 compared with significantly higher net payables in 2003.

Our Business Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 990,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

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

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of NCNG from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million for estimated working capital. We paid an additional $.3 million for actual working capital in the second quarter ended April 30, 2004. At the time of the acquisition, NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing.

On September 30, 2003, we also purchased for $7.5 million in cash Progress’ equity interest in EasternNC. At that time, EasternNC was a regulated utility with a certificate of public convenience and necessity from the NCUC to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. Effective at the close of business on October 25, 2005, we purchased for $1 the remaining 50% interest in common stock of EasternNC from Albemarle Pamlico Economic Development Corporation. EasternNC was merged into Piedmont immediately following the closing. For further information on this transaction, see Note 2 to the consolidated financial statements.

We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us. We also regularly evaluate opportunities for obtaining natural gas supplies from different production regions and supply sources to maximize our natural gas portfolio flexibility and reliability. For further information, see “Gas Supply and Regulatory Proceedings” below and Note 3 and Note 6 to the consolidated financial statements.

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 11 to the consolidated financial statements.

Our utility operations are regulated by the NCUC, the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission (FERC) that affect the availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that

affect the construction, operation, maintenance, integrity and safety of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

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

We invest in joint ventures to complement or supplement income from utility operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate the project with a major factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding existing joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

Financial Condition and Liquidity We believe we have access to adequate resources to meet our needs for working capital, construction expenditures, anticipated debt redemptions and dividend payments. These resources include net cash flow from operating activities, access to capital markets, cash generated from our investments in joint ventures and bank lines of credit.

Cash Flows from Operating Activities. The natural gas distribution business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to such factors as weather, natural gas prices, collections from customers, natural gas purchases and gas inventory storage activity. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally have positive cash flows from the sale of flowing gas and gas in storage and the collection of accounts billed to customers. We use this cash to reduce short-term debt to zero during much of the second and third quarters. We realize most of our annual earnings in the winter period, which is the first five months of our fiscal year. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage and decreases in receipts from customers.

Net cash provided by operating activities was $183.4 million in 2005, $183.7 million in 2004 and $103.8 million in 2003. Cash flows from operations are impacted by weather which affects gas purchases and sales. Warmer weather can lead to lower total margin 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 consumption. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have had a WNA in place in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in

November through March for weather-sensitive customers. The WNA generated charges to customers of $8.4 million in 2005 and $2.1 million in 2004 and credits to customers of $9.6 million in 2003. In North Carolina and Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or refund to all customers in the class. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the WNA.

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 minimal 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.

In anticipation of higher gas prices for the 2005-2006 winter heating season, we have worked with our regulators to design mechanisms to assist residential customers who experience difficulty in paying their winter bills by expanding the availability of alternative billing arrangements. We have held educational forums in each of our jurisdictions, and have communicated via radio and newspaper, to educate customers on winter gas prices and available payment plans and to encourage conservation efforts. In addition, we have established a web site, NaturalGasAnswers.com, to help customers learn how to reduce the cost of heating their homes. We have also asked our representatives in Congress to approve additional funds for Low Income Home Energy Assistance Program funds, and have encouraged our customers to do so also.

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. 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, 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. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers. With significantly higher wholesale gas costs due in part to the recent hurricanes, we anticipate that there may be more fuel switching by large industrial customers in the near term.

Cash Flows from Investing Activities. Net cash used in investing activities was $159 million in 2005, $65.7 million in 2004 and $522.3 million in 2003. The net cash used in investing activities was primarily for utility construction expenditures, and in 2003, the purchases of NCNG and EasternNC. Gross utility construction expenditures were $191.4 million ($157.9 million net of

AFUDC, contributions in aid of construction and bond reimbursements for EasternNC’s expenditures). As expenditures are made in EasternNC’s service territory, reimbursement requests are made to the State of North Carolina under orders issued by the NCUC granting EasternNC a total of $188.3 million of bond funds. Such funds are available to pay for the uneconomic portion of the construction of the natural gas distribution infrastructure in the eastern part of the state. For further information about the bond fund, see Note 3 to the consolidated financial statements.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. Net utility construction expenditures in 2005 were $157.9 million, compared with $103.2 million in 2004 and $80.3 million in 2003. Gross utility construction expenditures totaling $181.2 million, primarily to serve customer growth, are budgeted for 2006; however, we are not contractually obligated to expend capital until the work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

On May 12, 2005, we sold our corporate office building located in Charlotte, North Carolina for $6.7 million in cash, net of expenses. In accordance with utility plant accounting, we recorded the disposition of the land as a pre-tax gain of $1.7 million in “Other Income (Expense)” in the consolidated statement of income and a loss of $1.8 million on the disposition of the building as a charge to “Accumulated depreciation” in the consolidated balance sheet, based on the sales price allocation from an independent third party. Under the terms of the purchase and sale agreement, we leased back the building from the new owner until our new office space was ready for occupancy. We negotiated a ten-year lease with renewable options in a building that we relocated to in November 2005. The lease payments for the ten-year term range from $3 million to $3.4 million annually.

We received $2.4 million in cash in 2005 from the sale of marketable securities which we received in connection with the sale of our propane interests in 2004.

We received $36.1 million in cash in 2004 from the sale of equity method investments, $26.9 million from our investment in US Propane, L.P., and $9.2 million from our investment in Greenbrier Pipeline Company, LLC.

In 2003, we acquired 100% of the common stock of NCNG and a 50% equity interest in EasternNC from Progress. In 2005, we acquired the remaining 50% equity interest in EasternNC. These acquisitions were a part of our focus on growing our core utility business. For further information regarding the acquisitions, see Note 1.E and Note 2 to the consolidated financial statements.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $(22.9) million in 2005, $(123.5) million in 2004 and $424.6 million in 2003. Funds were primarily provided from bank borrowings and, in 2004 and 2003, the issuance of Common Stock through dividend reinvestment and employee stock plans. Financing activities in 2004 and 2003 also reflect the temporary and permanent financing of the acquisitions of NCNG and EasternNC. When required, we sell Common Stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. As of October 31, 2005, our current assets were $504.9 million and our current liabilities were $528.6 million, primarily due to seasonal requirements as discussed above.

Under committed bank lines of credit totaling $250 million, for which we pay a maximum annual fee of $.3 million, outstanding short-term borrowings during 2005 ranged from zero to $229.5 million, and interest rates ranged from 2.11% to 4.34%. As of October 31, 2005, we had additional uncommitted lines of credit totaling $113 million on a no fee and as needed, if available, basis. As of January 17, 2006, we have increased the amount of uncommitted lines to $225 million.

As of October 31, 2005, we had a line of credit for letters of credit of $1.5 million, of which $1.2 million were issued and outstanding. These letters of credit are used to guarantee claims from self-insurance under our general liability policies.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high, we may incur more short-term debt to pay for natural gas supplies 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.

During 2005, we issued $23.5 million of Common Stock through dividend reinvestment and stock purchase plans. Under the Common Stock Open Market Purchase Program discussed in Note 5 to the consolidated financial statements, during 2005 we paid $26.1 million for 1.1 million shares of Common Stock that are available for reissuance to these plans.

We increased our Common Stock dividend on an annualized basis by $.06 per share in 2005 and $.03 per share in 2004 and 2003. Dividends of $69.4 million, $63.3 million and $54.9 million for 2005, 2004 and 2003, respectively, were paid on Common Stock. 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; however, as of October 31, 2005, none of our retained earnings were restricted. For further information, see Note 4 to the consolidated financial statements.

In July 2006, we expect to make the scheduled payment of $35 million on the 9.44% senior notes. We expect to issue long-term debt in 2006 depending upon our needs for long-term financing and current market conditions.

As of October 31, 2005, our capitalization, including current maturities of long-term debt, consisted of 43% in long-term debt and 57% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

As of October 31, 2005, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors. Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:

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

	•		Ratio of net cash flows to capital expenditures,

	•		Funds from operations interest coverage,

	•		Ratio of funds from operations to average total debt, and

•

Pre-tax interest coverage.

Qualitative factors include, among other things:

	•		Stability of regulation in the jurisdictions in which we operate,

	•		Risks and controls inherent in the distribution of natural gas,

	•		Predictability of cash flows,

	•		Business strategy and management,

	•		Corporate governance guidelines and practices,

	•		Industry position, and

	•		Contingencies.

We are subject to default provisions related to our long-term debt and short-term bank lines of credit. The default provisions of our senior notes are:

	•		Failure to make principal, interest or sinking fund payments,

	•		Interest coverage of 1.75 times,

	•		Total debt cannot exceed 70% of total capitalization,

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

	•		Failure to make payments on any capitalized lease obligation,

	•		Bankruptcy, liquidation or insolvency, and

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

The default provisions of our medium-term notes are:

	•		Failure to make principal, interest or sinking fund payments,

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

	•		Bankruptcy, liquidation or insolvency.

Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of October 31, 2005, we are in compliance with all default provisions.

As of October 31, 2005, our estimated future contractual obligations were as follows.

Payments Due by Period


	Less than		1-3		4-5		After
In thousands	1 Year		Years		Years		5 Years		Total

Long-term debt (1)	$	35,000	$	30,000	$	120,000	$	475,000	$	660,000
Interest on long-term debt (1)		45,927		129,968		77,989		438,601		692,485
Pipeline and storage capacity (2)		121,169		345,968		223,470		350,952		1,041,559
Gas supply (3)		13,351		484		—		—		13,835
Telecommunications and information technology (4)		14,447		47,545		17,361		—		79,353
Defined-benefit pension plan funding (5)		15,300		45,700		—		—		61,000
Postretirement benefits plan funding (5)		2,600		6,300		—		—		8,900
Operating leases (6)		7,143		15,792		8,846		17,652		49,433
Other purchase obligations (7)		19,811		—		—		—		19,811

Total	$	274,748	$	621,757	$	447,666	$	1,282,205	$	2,626,376


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

(2)		100% recoverable through purchased gas adjustment (PGA) procedures.

(3)		Reservation fees that are 100% recoverable through PGA procedures.

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

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

(6)		See Note 7 to the consolidated financial statements.

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

Off-balance Sheet Arrangements We have no off-balance sheet arrangements other than operating leases that are reflected in the table above and discussed in Note 7 to the consolidated financial statements.

Critical Accounting Policies and 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, goodwill and pension and postretirement benefits to be our critical accounting estimates. Management has discussed the selection and development of the critical accounting policies and estimates presented below with the Audit Committee of the Board of Directors.

Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation” (Statement 71), 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 in the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from

the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded. Regulatory assets as of October 31, 2005 and 2004, totaled $85.8 million and $59.3 million, respectively. Regulatory liabilities as of October 31, 2005 and 2004, totaled $333.3 million and $320.2 million, respectively. The detail of these regulatory assets and liabilities is presented in Note 1.B to the consolidated financial statements.

Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. Through October 31, 2005, a WNA factor, based on the margin or base rate component of the billing rate, is included in rates charged to residential and commercial customers during the winter period of November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact that unusually cold or warm weather has on customer billings during the winter season. Without the WNA, our operating revenues in 2005 would have been lower by $8.4 million.

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

Goodwill. All of our goodwill is attributable to the regulated utility segment. We evaluate goodwill for impairment annually, or more frequently if impairment indicators arise, using a weighted average of the guideline company method of the market approach and the discounted cash flow method of the income approach on the premise of continued use, which assumes that a buyer and seller contemplate the continued use of the reporting unit at its present location as part of current and future operations. The guideline company method of the market approach is based on market multiples of companies that are representative of our peers in the natural gas distribution industry. The discounted cash flow method of the income approach consists of estimating annual future cash flows and individually discounting them back to the present value. These calculations are dependent on several subjective factors, including the timing of future cash flows, future growth rates and the discount rate. The calculations also define the reporting unit as the domestic natural gas distribution business. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value.

Using a discounted cash flow model to estimate fair value is subjective and requires significant judgment in applying a discount rate, growth assumptions and continued cash flows. An increase or decrease of 100 basis points in the weighted average cost of capital would have the following effects.


In thousands	100 Basis Point Increase	100 Basis Point Decrease

Change in fair value of the regulated utility segment	$(198,000)	$294,000

The 100 basis point increase or decrease in the weighted average cost of capital would not have required the recording of an impairment charge.

Pension and Postretirement Benefits. We have a defined-benefit pension plan for the benefit of eligible full-time employees. We also provide certain postretirement health care and life insurance benefits to eligible full-time employees. Our reported costs of providing these benefits, as described in Note 8 to the consolidated financial statements, are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.

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

The discount rate in 2005 was 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 for the pension plans changed from 6.25% in 2003 to 5.75% in 2004 and 6% in 2005. Similarly, based on this approach, the weighted average discount rate for postretirement benefits changed from 6.25% in 2003 to 5.75% in 2004 and 5.89% in 2005. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we changed our health care cost trend rate from 10% in 2003 to 10.5% in 2004 and 9.75% in 2005, declining gradually to 5% in 2012.

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 pension plan assets and other postretirement benefit assets to be approximately 60% equity securities and 40% fixed income securities. The expected long-term rate of return of plan assets was 8.5% in 2003, 2004 and 2005, and will be maintained at 8.5% in 2006. Based on a fairly stagnant inflation trend, our age-related assumed rate of increase in future compensation levels was 3.97% in 2003 and 2004, but increased to 4.05% in 2005 due to a change in the demographics of the participants.

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


In thousands	Change in			Impact on 2005		Impact on Projected
Actuarial Assumption	Assumption			Pension Cost		Benefit Obligation
	Increase (Decrease)

Discount rate		(.25	%)	$	518	$	6,253
Rate of return on plan assets		(.25	%)		488		N/A
Rate of increase in compensation		.25	%		868		3,951

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
				Impact on		Accumulated
In thousands	Change in			2005 Postretirement		Postretirement
Actuarial Assumption	Assumption			Benefit Cost		Benefit Obligation
	Increase (Decrease)

Health care cost trend rate		.25	%	$	26	$	256
Rate of return on plan assets		(.25	%)		67		N/A
Discount rate		(.25	%)		72		711

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

Gas Supply and Regulatory Proceedings We continue to pursue the diversification of our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have a firm transportation contract pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. The anticipated in-service date is November 2006. We have also executed an agreement with Hardy Storage Company for market-area storage capacity with an anticipated in-service date in 2007. We have a 50% equity interest in this project which is more fully discussed in Note 10 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 wholesale margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. In North Carolina and South Carolina, a sharing mechanism is in effect where 75% of any margin earned is refunded to customers. Secondary market transactions in Tennessee are included in the performance incentive plan discussed in Note 3 to the consolidated financial statements.

Rate proceedings in North Carolina and South Carolina were completed during 2005 that will impact 2006 earnings. Proceedings in both states adopted new approaches to ratemaking design. For further information about these regulatory proceedings and other regulatory information, see Note 3 to the consolidated financial statements.

Equity Method Investments For information about our equity method investments, see Note 10 to the consolidated financial statements.

Environmental Matters We have developed an environmental self-assessment plan to assess our facilities and program areas for compliance with federal, state and local environmental regulations and to correct any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For additional information on environmental matters, see Note 12 to the consolidated financial statements.

Accounting Pronouncements In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We will adopt Statement 123R on November 1, 2005, and amend our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R will not have a material effect on our financial position or results of operations.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), to clarify the term “conditional asset retirement” as used in SFAS 143, “Accounting for Asset Retirement Obligations.” FIN 47 requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly, we will adopt FIN 47 no later than our fourth fiscal quarter in 2006. We are currently assessing the impact FIN 47 may have on our consolidated balance sheet; however, we believe the adoption of FIN 47 will not have a material impact on our financial position, results of operations or cash flows.

Forward-Looking Statements 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. Forward-looking statements concern, among others, plans, objectives, proposed capital expenditures and future events or performance. These statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include:

•

Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our effectiveness in achieving the allowed rates of return and initiate rate proceedings or operating changes as needed. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated.

	•		Residential, commercial and industrial growth in our service areas. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.

	•		Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies and we expect this highly competitive environment to continue.

	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts at lower per-unit margins.

	•		Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.

	•		The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our internally generated cash flows are not adequate to finance the full cost of this construction. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations.

	•		Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.

	•		Impact of the Energy Policy Act of 2005. Key components of the bill include provisions that encourage fuel diversity in the generation of electricity, provide incentives promoting energy efficiency and innovative technology, allow an inventory of energy reserves in the Outer Continental Shelf and support Liquified Natural Gas (LNG) imports and improved leasing and permitting processes in the development of existing supply fields. The effect of this legislation on our future operations is unknown.

	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.

	•		Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.

	•		Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

	•		Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.

	•		Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses and we assume such risks as an equity investor.

All of these factors are difficult to predict and many are beyond our control. Accordingly, while we believe the assumptions underlying our forward-looking statements to be reasonable, there can be no assurance that these statements will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “seek,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.

Factors relating to regulation and management also may be described or incorporated by reference in future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in this report. There may also be other factors besides those described above that could cause actual conditions, events or results to differ from those in the forward-looking statements.

Forward-looking statements reflect our current expectations only as of the date they are made. We assume no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. Please reference our web site at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our web site as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We hold all financial instruments discussed below for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Our exposure to interest rate changes relates primarily to short-term debt. We are exposed to interest rate changes to long-term debt when we are in the market to issue long-term debt. As of October 31, 2005, all of our long-term debt was at fixed rates. Exposure to gas cost variations relates to the wholesale supply, demand and price of natural gas.

Interest Rate Risk

We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period depending upon many factors, including our investments in capital projects. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

As of October 31, 2005, we had $158.5 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 4.28%. The carrying amount of our short-term debt approximates fair value. During 2005, such short-term debt outstanding ranged from zero to $229.5 million, with interest rates from 2.11% to 4.34%.

Information as of October 31, 2005, about our long-term debt that, for holders of our long-term debt, is sensitive to changes in interest rates is presented below.


	Expected Maturity Date																			Fair Value as
														There-						of October 31,
In millions	2006			2007		2008		2009			2010			after			Total			2005

Fixed Rate Long-term Debt	$	35		$	—	$	—	$	30		$	60		$	535		$	660			$753
Average Interest Rate		9.44	%		—		—		7.35	%		7.80	%		6.77	%		7.03	%

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various duration for the forward sale and purchase of a portion of our natural gas requirements. We also manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. Due to cost-based rate regulation in our utility operations, we have limited financial exposure to changes in commodity prices as substantially all changes in purchased gas costs and the costs of hedging our gas supplies are passed on to customers through PGA mechanisms.

Materials Risk

Our supply of plastic pipe was affected by the August and September 2005 hurricanes in the Gulf Coast region as the pipe is a petroleum product. One of our suppliers evoked force majeure and placed all of its customers on an allocation program. Our allocation was increased in November and December 2005 and is expected to be at a normal level by early 2006. We have avoided any stock outages by relocating inventory within our service areas and by receiving additional allotments from vendors.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 7 of this Form 10-K.

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 on page 74.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (“Piedmont”) as of October 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended October 31, 2005. These financial statements are the responsibility of Piedmont’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended October 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 13, the accompanying 2004 and 2003 financial statements have been restated.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Piedmont’s internal control over financial reporting as of October 31, 2005, 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 January 17, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of Piedmont’s internal control over financial reporting and an unqualified opinion on the effectiveness of Piedmont’s internal control over financial reporting.

/s/ Deloitte & Touche LLP
Charlotte, North Carolina
January 17, 2006

Consolidated Balance Sheets
October 31, 2005 and 2004

Assets


In thousands	2005		2004
			(As Restated -
			See Note 13)

Utility Plant:
Utility plant in service	$	2,532,263	$	2,395,588
Less accumulated depreciation		672,502		624,973

Utility plant in service, net		1,859,761		1,770,615
Construction work in progress		79,314		79,302

Total utility plant, net		1,939,075		1,849,917


Other Physical Property, at cost (net of accumulated depreciation of $1,888 in 2005 and $1,782 in 2004)		731		973


Current Assets:
Cash and cash equivalents		7,065		5,676
Restricted cash		13,108		12,732
Marketable securities, at market value		—		1,857
Trade accounts receivable (less allowance for doubtful accounts of $1,188 in 2005 and $1,086 in 2004)		107,535		86,486
Income taxes receivable		21,570		28,282
Other receivables		12,102		4,223
Unbilled utility revenues		48,414		25,711
Inventories:
Gas in storage		151,865		128,465
Materials, supplies and merchandise		5,331		4,727
Gas purchase options, at fair value		22,843		13,182
Amounts due from customers		52,161		28,832
Prepayments		62,821		50,473
Other		96		96

Total current assets		504,911		390,742


Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities		71,520		65,322
Goodwill		47,383		48,151
Unamortized debt expense		4,822		5,261
Other		34,048		31,798

Total investments, deferred charges and other assets		157,773		150,532


Total	$	2,602,490	$	2,392,164

See notes to consolidated financial statements.

Capitalization and Liabilities


In thousands	2005			2004
				(As Restated -
				See Note 13)

Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized	$	—		$	—
Common stock — no par value — 100,000 shares authorized; outstanding, 76,698 shares in 2005 and 76,670 shares in 2004		562,880			563,667
Retained earnings		323,565			291,397
Accumulated other comprehensive income (loss)		(2,253	)		(166	)

Total stockholders’ equity		884,192			854,898
Long-term debt		625,000			660,000

Total capitalization		1,509,192			1,514,898


Current Liabilities:
Current maturities of long-term debt		35,000			—
Notes payable		158,500			109,500
Trade accounts payable		182,847			83,895
Other accounts payable		45,325			47,712
Income taxes accrued		6,201			5,259
Customers’ deposits		20,162			18,018
Deferred income taxes		23,128			6,416
General taxes accrued		16,450			17,097
Amounts due to customers		17,124			26,379
Other		23,827			21,879

Total current liabilities		528,564			336,155


Deferred Credits and Other Liabilities:
Deferred income taxes		213,050			212,925
Unamortized federal investment tax credits		3,951			4,492
Regulatory cost of removal obligations		288,989			266,700
Other		58,744			56,994

Total deferred credits and other liabilities		564,734			541,111


Total	$	2,602,490		$	2,392,164

See notes to consolidated financial statements.

Consolidated Statements of Income
For the Years Ended October 31, 2005, 2004 and 2003


In thousands except per share amounts	2005			2004			2003

Operating Revenues	$	1,761,091		$	1,529,739		$	1,220,822
Cost of Gas		1,261,952			1,041,370			837,942


Margin		499,139			488,369			382,880


Operating Expenses:
Operations and maintenance		206,983			200,282			152,107
Depreciation		85,169			82,276			63,164
General taxes		29,807			27,011			24,410
Income taxes		51,880			51,485			40,093


Total operating expenses		373,839			361,054			279,774


Operating Income		125,300			127,315			103,106


Other Income (Expense):
Income from equity method investments		27,664			27,381			17,972
Gain on sale of equity method investments		—			4,683			—
Gain on sale of marketable securities		1,525			—			—
Allowance for equity funds used during construction		—			946			1,128
Non-operating income		3,830			2,285			2,560
Charitable contributions		(1,717	)		(9,124	)		(692	)
Non-operating expense		(28	)		(324	)		(171	)
Income taxes		(10,446	)		(10,562	)		(8,524	)


Total other income (expense), net of tax		20,828			15,285			12,273


Utility Interest Charges:
Interest on long-term debt		46,173			44,957			37,740
Allowance for borrowed funds used during construction		(3,137	)		(1,669	)		(1,135	)
Other		1,220			4,076			3,592


Total utility interest charges		44,256			47,364			40,197


Income before Minority Interest in Income of Consolidated Subsidiary		101,872			95,236			75,182

Less Minority Interest in Income of Consolidated Subsidiary		602			48			820


Net Income	$	101,270		$	95,188		$	74,362


Average Shares of Common Stock:
Basic		76,680			74,359			66,782
Diluted		76,992			74,797			67,007

Earnings Per Share of Common Stock:
Basic	$	1.32		$	1.28		$	1.11
Diluted	$	1.32		$	1.27		$	1.11

See notes to consolidated financial statements.

Consolidated Statements of Cash Flows
For the Years Ended October 31, 2005, 2004 and 2003


In thousands	2005			2004			2003
				(As Restated - See Note 13)

Cash Flows from Operating Activities:
Net income	$	101,270		$	95,188		$	74,362

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		91,677			87,336			66,782
Amortization of investment tax credits		(541	)		(550	)		(550	)
Allowance for doubtful accounts		102			(1,658	)		536
Allowance for funds used during construction		(3,137	)		(2,615	)		(2,263	)
Gain on sale of corporate office land		(1,659	)		—			—
Earnings from equity method investments		(27,664	)		(27,381	)		(17,972	)
Distributions of earnings from equity method investments		23,649			26,078			9,946
Gain on sale of equity method investments		—			(4,683	)		—
Gain on sale of marketable securities		(1,525	)		—			—
Deferred income taxes		18,278			17,835			46,865
Changes in assets and liabilities:
Receivables		(43,214	)		(6,683	)		(37,570	)
Inventories		(24,004	)		(6,695	)		(34,547	)
Amounts due from customers		(23,329	)		(13,750	)		(8,905	)
Other assets		(20,164	)		(18,221	)		(24,087	)
Accounts payable		94,530			8,941			10,591
Amounts due to customers		(9,255	)		5,163			11,177
Other liabilities		8,362			25,434			9,425


Total adjustments		82,106			88,551			29,428


Net cash provided by operating activities		183,376			183,739			103,790


Cash Flows from Investing Activities:
Utility construction expenditures		(191,407	)		(139,146	)		(78,163	)
Reimbursements from bond fund		29,841			41,497			3,762
Contributions to equity method investments		(6,162	)		(113	)		(2,224	)
Distributions of capital from equity method investments		695			213			242
Proceeds from sale of corporate office building and land		6,660			—			—
Proceeds from sale of marketable securities		2,394			—			—
Proceeds from sale of equity method investments		—			36,096			—
Purchase of gas distribution system		—			—			2,153
Purchase of NCNG and EasternNC, net in 2003 of cash received of $7,185		—			(271	)		(450,168	)
Decrease (increase) in restricted cash		(376	)		(5,983	)		1,936
Other		(683	)		1,958			172


Net cash used in investing activities		(159,038	)		(65,749	)		(522,290	)


Cash Flows from Financing Activities:
Increase in notes payable		49,000			—			63,000
Increase (decrease) in commercial paper		—			(445,559	)		445,559
Proceeds from issuance of long-term debt, net of expenses		—			197,981			—
Retirement of long-term debt		—			(2,000	)		(47,000	)
Proceeds from sale of common stock, net of expenses		—			173,828			—
Issuance of common stock through dividend reinvestment and employee stock plans		23,536			20,018			17,925
Repurchases of common stock		(26,119	)		(4,487	)		—
Dividends paid		(69,366	)		(63,267	)		(54,912	)


Net cash provided by (used in) financing activities		(22,949	)		(123,486	)		424,572


Net Increase (Decrease) in Cash and Cash Equivalents		1,389			(5,496	)		6,072
Cash and Cash Equivalents at Beginning of Year		5,676			11,172			5,100


Cash and Cash Equivalents at End of Year	$	7,065		$	5,676		$	11,172


Cash Paid During the Year for:
Interest	$	48,888		$	43,868		$	40,268
Income taxes		35,888			44,396			30,554

Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2005, 2004 and 2003


							Accumulated
							Other
	Common			Retained			Comprehensive
In thousands except per share amounts	Stock			Earnings			Income (Loss)			Total

Balance, October 31, 2002	$	352,553		$	240,026		$	(2,983	)	$	589,596


Comprehensive Income:
Net income					74,362						74,362
Other comprehensive income:
Unrealized loss from hedging activities of equity method investments, net of tax of ($869)								(1,326	)
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $1,553								2,377			1,051

Total comprehensive income											75,413
Common Stock Issued		20,098									20,098
Dividends Declared ($.8225 per share)					(54,912	)					(54,912	)


Balance, October 31, 2003		372,651			259,476			(1,932	)		630,195


Comprehensive Income:
Net income					95,188						95,188
Other comprehensive income:
Unrealized gain on marketable securities, net of tax of $391								597
Unrealized gain from hedging activities of equity method investments, net of tax of $292								381
Reclassification adjustment of realized loss from hedging activities of equity method investments included in net income, net of tax of $512								788			1,766

Total comprehensive income											96,954
Common Stock Issued		195,503									195,503
Common Stock Repurchased		(4,487	)								(4,487	)
Dividends Declared ($.8525 per share)					(63,267	)					(63,267	)


Balance, October 31, 2004		563,667			291,397			(166	)		854,898


Comprehensive Income:
Net income					101,270						101,270
Other comprehensive income:
Reclassification adjustment of realized gain on marketable securities included in net income, net of tax of ($391)								(597	)
Unrealized gain from hedging activities of equity method investments, net of tax of $287								436
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of ($1,280)								(1,926	)		(2,087	)

Total comprehensive income											99,183
Common Stock Issued		25,332									25,332
Common Stock Repurchased		(26,119	)								(26,119	)
Tax benefit from dividends paid on ESOP shares					264						264
Dividends Declared ($.905 per share)					(69,366	)					(69,366	)


Balance, October 31, 2005	$	562,880		$	323,565		$	(2,253	)	$	884,192

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

A. Operations and Principles of Consolidation.

Piedmont Natural Gas Company, Inc. (Piedmont) is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial 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, interstate natural gas storage and intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. For further information on regulatory matters, see Note 3 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and, through October 25, 2005, its 50% equity interest in Eastern North Carolina Natural Gas Company (EasternNC). On October 25, 2005, we purchased the remaining 50% interest in EasternNC and merged it into Piedmont. See Note 2 to the consolidated financial statements for further information on acquisitions.

Investments in non-utility activities are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in the consolidated statements of income. For further information on equity method investments, see Note 10 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in the consolidated statements of income. Significant inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation” (Statement 71).

B. 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. Statement 71 provides 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 Statement 71, 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.

We monitor the regulatory and competitive environment in which we operate to determine that our regulatory assets continue to be probable of recovery. If we were to determine that all or a portion of these regulatory assets no longer met the criteria for continued application of Statement 71, we would write off that portion which we could not recover, net of any regulatory liabilities which would be deemed no longer necessary. Our reviews have not resulted in any write offs of any regulatory assets or liabilities.

Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 2005 and 2004, are as follows.


In thousands	2005		2004

Regulatory Assets:
Unamortized debt expense	$	4,822	$	5,261
Amounts due from customers		52,161		28,832
Environmental costs *		4,085		4,658
Demand-side management costs *		4,387		5,089
Deferred operations and maintenance expenses *		9,219		5,579
Deferred integration costs of acquisition *		1,021		2,042
Deferred pension and other retirement benefits costs *		6,480		5,119
Other *		3,671		2,672

Total	$	85,846	$	59,252


Regulatory Liabilities:
Regulatory cost of removal obligations	$	288,989	$	266,700
Amounts due to customers		17,124		26,379
Deferred income taxes		25,992		24,840
Environmental liability due customers *		1,157		2,314

Total	$	333,262	$	320,233


*		Regulatory assets are included in “Other” in “Investments, Deferred Charges and Other Assets” and regulatory liabilities are included in “Other” in “Deferred Credits and Other Liabilities” in the consolidated balance sheets.

As of October 31, 2005, we had regulatory assets totaling $3.7 million on which we do not earn a return during the recovery period. The original amortization periods for these assets range from three to 15 years and, accordingly, $2.5 million will be fully amortized by 2008, $.2 million will be fully amortized by 2010 and the remaining $1 million will be fully amortized by 2018.

C. Utility Plant and Depreciation.

Utility plant is stated at original cost, including direct labor and materials, allocable overhead charges and an allowance for borrowed and equity funds used during construction (AFUDC). For the years ended October 31, 2005, 2004 and 2003, AFUDC totaled $3.1 million, $2.6 million and $2.3 million, respectively. The portion of AFUDC attributable to equity funds is included in “Other Income (Expense)” and the portion attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the consolidated statements of income. The costs of property retired are removed from utility plant and charged to accumulated depreciation.

We compute depreciation expense using the straight-line method over periods ranging from 5 to 65 years. The composite weighted-average depreciation rates were 3.46% for 2005, 3.51% for 2004 and 3.64% for 2003.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and propose new depreciation rates for approval. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. The approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. Accordingly, we accrue estimated costs of removal of long-lived assets through depreciation expense. The related cost of removal accrual is reflected in “Regulatory cost of removal obligations” in the consolidated balance sheets.

SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143), requires that we record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred if a reasonable estimate of fair value can be made. We have determined that we have asset retirement obligations for our underground mains and services; however, the fair value of the obligations cannot be determined because the end of the system life is indeterminable. For further discussion of asset retirement obligations, see Note 1.N to the consolidated financial statements.

D. Trade Accounts Receivable and Allowance for Doubtful Accounts.

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. Merchandise receivables due beyond one year are included in “Other” in “Investments, Deferred Charges and Other Assets” in the consolidated balance sheets.

A reconciliation of changes in the allowance for doubtful accounts for the years ended October 31, 2005, 2004 and 2003, is as follows.


In thousands	2005			2004			2003

Balance at beginning of year	$	1,086		$	2,743		$	810
Additions charged to uncollectibles expense		6,224			6,098			6,427
Additions from acquisitions		—			—			1,385
Accounts written off, net of recoveries		(6,122	)		(7,755	)		(5,879	)

Balance at end of year	$	1,188		$	1,086		$	2,743

E. Goodwill, Equity Method Investments and Long-Lived Assets.

All of our goodwill is attributable to the regulated utility segment. We evaluate goodwill for impairment annually, or more frequently if impairment indicators surface during the year. We did not recompute the fair value of goodwill in 2005 since our last fair value determination exceeded the carrying amount by a substantial margin. The assets and liabilities that comprise the reporting unit have not changed significantly. Based on an analysis of events that have occurred and circumstances that have changed since the most recent fair value determination, we believe the likelihood that the current carrying amounts would be less than the fair value is remote.

In our 2004 appraisal, we used a weighted average of the guideline company method of the market approach and the discounted cash flow method of the income approach on the premise of continued use. This method assumes that a buyer and seller contemplate the continued use of the reporting unit at its present location as part of current and future operations. The guideline company method of the market approach is based on market multiples of companies that are representative of our peers in the natural gas distribution industry. The discounted cash flow method of the income approach consists of estimating annual future cash flows and individually discounting them back to the present value. These calculations are dependent on several subjective factors, including the timing of future cash flows, future growth rates and the discount rate. The calculations also define the reporting unit as the domestic natural gas distribution business. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. No impairment has been recognized during the years ended October 31, 2005, 2004 and 2003.

Changes in goodwill for the years ended October 31, 2005 and 2004, are as follows. For further information on acquisitions, see Note 2 to the consolidated financial statements.


In thousands

Balance, October 31, 2003			$	50,924
Purchase price allocation adjustments for NCNG:
Deferred income taxes from book and tax basis differences of the purchase price	(5,000	)
Unrecorded liabilities and true-up of working capital	2,275			(2,725	)

Minority interest income in EasternNC for the year				(48	)

Balance, October 31, 2004				48,151
Minority interest income in EasternNC for the year				(602	)
Acquisition of remaining 50% interest in EasternNC				(166	)

Balance, October 31, 2005			$	47,383

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. There were no events or circumstances during the years ended October 31, 2005, 2004 and 2003, that resulted in any impairment charges. For further information on equity method investments, see Note 10 to the consolidated financial statements.

F. Unamortized Debt Expense.

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, registration fees and rating agency fees, related to issuing long-term debt. We amortize debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt which has lives ranging from 10 to 30 years.

G. Inventories.

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

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

H. Deferred Purchased Gas Adjustments.

Rate schedules for utility sales and transportation customers include purchased gas adjustment (PGA) provisions that provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the cost of gas. Under PGA provisions, charges to cost of gas are based on the gas cost amounts recoverable under approved rate schedules. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. We review gas costs and deferral activity periodically and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

I. Taxes.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. Deferred taxes are primarily attributable to utility plant, equity method investments and revenues and cost of gas. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred pursuant to Statement 71, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders. We amortize deferred investment tax credits to income over the estimated useful lives of the property to which the credits relate.

General taxes consist primarily of property taxes and payroll taxes. These taxes are not included in revenues.

J. 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 provisions. A weather normalization adjustment (WNA) factor is included in rates charged to residential and commercial customers during the winter period November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact that unusually cold or warm weather has on customer billings during the winter season.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, changes in weather during the period and the impact of the WNA.

Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on contract or market prices.

K. Earnings Per Share.

We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2005, 2004 and 2003, is presented below.


In thousands except per share amounts	2005		2004		2003

Net Income	$	101,270	$	95,188	$	74,362


Average shares of Common Stock outstanding for basic earnings per share		76,680		74,359		66,782
Contingently issuable shares under the Executive Long-Term Incentive Plan		312		438		225

Average shares of dilutive stock		76,992		74,797		67,007


Earnings Per Share:
Basic	$	1.32	$	1.28	$	1.11
Diluted	$	1.32	$	1.27	$	1.11

L. Statements of Cash Flows.

For purposes of reporting cash flows, we consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents.

M. Use of Estimates.

We make estimates and assumptions when preparing the consolidated financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

N. Recently Issued Accounting Standards.

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We will adopt Statement 123R on November 1, 2005, and amend our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R will not have a material effect on our financial position or results of operations.

2. Acquisitions

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of NCNG from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million for estimated working capital. We paid an additional $.3 million for actual working capital in our second quarter ended April 30, 2004. At the time of the acquisition, NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing.

We also purchased for $7.5 million in cash Progress’ equity interest in EasternNC. At that time, EasternNC was a regulated utility with a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock.

We recorded the assets purchased on September 30, 2003, at fair value, except for utility plant, franchises and consents and miscellaneous intangible property that were recorded at book value in accordance with Statement 71. We recorded estimated goodwill at closing of $42.2 million for NCNG and $1.1 million for EasternNC. We finalized the purchase price allocation during our third quarter ended July 31, 2004, resulting in a decrease in goodwill of $2.7 million attributable to NCNG. This adjustment was primarily due to recording $5 million in deferred income taxes from book and tax basis differences of the purchase price, partially offset by unrecorded liabilities and the true-up of estimated working capital to actual. The goodwill attributable to EasternNC as of September 30, 2003, was not adjusted. We believe that approximately $31.4 million of the goodwill will be deductible for tax purposes.

On October 25, 2005, we purchased the remaining 50% interest in EasternNC for $1. EasternNC was merged into Piedmont immediately following the closing. The primary reason for the purchase of the remaining 50% interest was to integrate the rate structure of EasternNC into Piedmont’s rate structure.

3. Regulatory Matters

In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of North Carolina. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. In accordance with a 2002 NCUC order, we no longer deposit supplier refunds in the expansion fund for our pre-NCNG acquisition operations; however, we continue to deposit supplier refunds attributable to NCNG operations in the expansion fund. As of October 31, 2005, the balance of $13.1 million in our expansion fund held by the North Carolina State Treasurer is included in the consolidated balance sheet in “Restricted cash,” with an offsetting liability included in “Amounts due to customers.” In accordance with the order in the general rate case proceeding in 2005 discussed below, the expansion funds held by the State Treasurer will be returned to us in early 2006.

The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South Carolina customers. The plan is limited to 60% of annual normalized sales volumes for South Carolina and operates using historical pricing indices that are tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan are deemed to be prudently incurred and are recovered in rates as a gas cost. Any benefits recognized are deemed to be reductions in gas cost and are refunded to South Carolina customers in rates.

We have a similar hedging plan in North Carolina. Recovery of costs associated with the hedging plan is not pre-approved by the NCUC and the costs are treated as gas costs subject to the annual gas cost prudence review. Any benefits or gain recognition are deemed to be reductions in gas costs and are refunded to North Carolina customers in rates. Through October 31, 2005, we have recovered 100% of the costs incurred under the North Carolina plan that have been reviewed for prudence.

In Tennessee, costs and benefits associated with hedging activities are recovered through the Actual Cost Adjustment (ACA) mechanism. The costs and benefits of financial instruments and all other gas costs incurred are components of the Tennessee Incentive Plan (TIP) mechanism approved by the TRA. The TIP mechanism replaced annual prudence reviews by benchmarking gas costs and secondary market activity performance against amounts determined by published market indices.

Due to the seasonal nature of our business and weather conditions during the winter period, we contract with customers in the secondary market to sell supply and capacity assets when available. In North Carolina and South Carolina, we operate under benefit-sharing mechanisms approved by the NCUC and the PSCSC for secondary market transactions (capacity release and off-system sales) whereby 75% of the benefit is refunded to jurisdictional customers in rates and 25% of the benefit is retained by us. In Tennessee, we operate under the TIP whereby gas purchase benchmarking benefits or losses are combined with secondary market transaction benefits or losses and shared by customers and us under a pre-approved formula. Our share of net gains or losses in Tennessee is subject to an overall annual cap of $1.6 million.

Effective November 1, 2003, the NCUC issued an order approving an increase in NCNG’s regulatory margin of $29.4 million annually. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

Effective November 1, 2003, the TRA approved an increase in revenues of $10.3 million annually. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

In March 2003, we, along with two other natural gas companies in Tennessee, filed a petition with the TRA requesting a declaratory order that the gas cost portion of uncollectible accounts be recovered through PGA procedures. The petition stated that to the extent that the gas cost portion of net write-offs for a fiscal year exceeds the gas cost portion of uncollectible accounts allowed in base rates, the unrecovered portion would be included in ACA filings for future recovery from customers. Conversely, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings. In February 2004, the TRA approved the petition by modifying the formula in the PGA rules to allow for the recovery of uncollected gas cost on an experimental basis for one year, effective March 10, 2004. On April 4, 2005, the authority extended the experimental period for one more year.

The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998 which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding EasternNC an exclusive franchise to provide natural gas service to 14 counties in the eastern-most part of North Carolina that had not been able to obtain gas service because of the relatively small population of those counties and the resulting uneconomic feasibility of providing service. The order also granted $38.7 million in state bond funding. In 2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of $188.3 million. As of October 31, 2005, the remaining balance of the bond funds allocated to EasternNC was $16 million.

We establish a state bond receivable when we determine that construction costs are reimbursable by the state. As of October 31, 2005 and 2004, we had receivables of $12 million and $3.5 million, respectively, related to the bond fund included in “Other receivables” in the consolidated balance sheets. In accordance with NCUC orders, we must also contribute funding to the project that is not subject to bond reimbursement. During the twelve months ended October 31, 2005, we made capital expenditures totaling $9.5 million for which we did not seek reimbursement from the bond fund.

The NCUC has allowed EasternNC to defer its operations and maintenance expenses during the first eight years of operation or until the first rate case order, whichever occurs first, with a maximum deferral of $15 million. The deferred amounts accrue interest at a rate of 8.69% per annum. On December 1, 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. As of October 31, 2005 and 2004, deferred operations and maintenance expenses of $9.2 million and $5.6 million, respectively, including accrued interest, were deferred as a regulatory asset in the consolidated balance sheets. As a part of the general rate case proceeding discussed below, deferral will cease on October 31, 2005, and the balance in the deferred account as of June 30, 2005, will be amortized over 15 years beginning November 1, 2005. Amortization of amounts totaling $1.3 million that were deferred between July 1 and October 31, 2005, will be addressed in the next general rate case.

On October 22, 2004, we filed a petition with the NCUC seeking deferred accounting treatment for certain pipeline integrity management costs to be incurred by us in compliance with the Pipeline Safety Improvement Act of 1992 and regulations of the United States Department of Transportation. The NCUC approved deferral treatment of these costs applicable to all incremental expenditures beginning November 1, 2004. As a part of the general rate case discussed below, the balance of $.4 million in the deferred account as of June 30, 2005, will be amortized over three years beginning November 1, 2005, and subsequent expenditures will continue to be deferred. Any unamortized balance at the end of the three years will be addressed in a future rate case.

On February 16, 2005, the Natural Gas Rate Stabilization Act of 2005 became effective in South Carolina. The law provides electing natural gas utilities, including Piedmont, with a mechanism for the regular, periodic and more frequent (annual) adjustment of rates which is intended to: (1) encourage investment by natural gas utilities, (2) enhance economic development efforts, (3) reduce the cost of rate adjustment proceedings and (4) result in smaller but more frequent rate changes for customers. If the utility elects to operate under the Act, the annual filing will provide that the utility’s rate of return on equity will remain within a 50-basis points band above or below the current allowed rate of return on equity. On April 26, 2005, we filed an election with the PSCSC to adopt this new mechanism.

On June 15, 2005, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2005, along with revenue deficiency calculations and proposed changes in our tariff rates. In the filing, we requested an increase in annual margin of $3.2 million. On October 21, 2005, the PSCSC issued an order approving an increase in annual margin of $2.6 million, effective November 1, 2005.

On April 1, 2005, we filed a general rate case application with the NCUC requesting a consolidation of the respective rate bases, revenues and expenses of Piedmont, NCNG and EasternNC. In addition to a unified and uniform rate structure for all customers served by us in North Carolina, the application requested a general restructuring and increase in rates and charges for customers to produce an overall annual increase in margin of $36.7 million, a

consolidation and/or amortization of certain deferred accounts, changes to cost allocations and rate design including an innovative “conservation tariff” mechanism that decouples margin recovery from residential and commercial customer consumption, changes and unification of existing service regulations and tariffs, common depreciation rates for plant and recovery of uncollectible gas costs through the gas cost deferred account.

On August 31, 2005, a stipulation was filed in this proceeding resolving all issues and providing a margin increase of $20.2 million. On November 3, 2005, the NCUC issued an order approving the margin increase and authorizing new rates effective November 1, 2005. The Stipulation provided for the elimination of the WNA and the establishment of a Customer Utilization Tracker (CUT). The CUT is a tracker which is experimental and can be effective for no more than three years, subject to review and approval in a future general rate case proceeding. The CUT provides for the recovery of our approved margin per customer independent of weather or other usage and consumption patterns of residential and commercial customers. The CUT will track our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. During the life of the CUT, the NCUC ordered us to contribute $500,000 per year toward conservation programs to assist residential and commercial customers. The conservation programs are subject to review and approval by the NCUC. On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal in this rate proceeding challenging the lawfulness of the NCUC’s authorization and approval of the CUT. We believe the CUT is lawful, just and reasonable and reflects good public policy, and we intend to vigorously defend the NCUC’s action authorizing and approving the Stipulation and the CUT. We are unable to predict the outcome of an appeal being granted or the potential impact to our rates, charges or terms and conditions of service should the NCUC order be reversed or remanded.

4. Long-Term Debt

All of our long-term debt is unsecured. Long-term debt as of October 31, 2005 and 2004, is as follows.


In thousands	2005		2004

Senior Notes:
9.44%, due 2006	$	35,000	$	35,000
8.51%, due 2017		35,000		35,000
Medium-Term Notes:
7.35%, due 2009		30,000		30,000
7.80%, due 2010		60,000		60,000
6.55%, due 2011		60,000		60,000
5.00%, due 2013		100,000		100,000
6.87%, due 2023		45,000		45,000
8.45%, due 2024		40,000		40,000
7.40%, due 2025		55,000		55,000
7.50%, due 2026		40,000		40,000
7.95%, due 2029		60,000		60,000
6.00%, due 2033		100,000		100,000

Total		660,000		660,000
Less current maturities		35,000		—

Total	$	625,000	$	660,000

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


In thousands

2006	$	35,000
2007		—
2008		—
2009		30,000
2010		60,000
Thereafter		535,000

Total	$	660,000

We have a shelf registration statement that can be used for either debt or equity securities filed with the Securities and Exchange Commission for $690 million. In December 2003, we sold $200 million of medium-term notes and in January 2004, we sold $180.6 million of Common Stock under this shelf registration statement. The remaining balance of unused long-term financing available under this shelf registration statement is $309.4 million.

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, 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, 2005, we could make restricted payments totaling $576.6 million. Retained earnings as of this date were $323.6 million; therefore, none of our retained earnings were restricted.

We are subject to default provisions related to our long-term debt. Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of October 31, 2005, we are in compliance with all default provisions.

5. Capital Stock

Changes in Common Stock for the years ended October 31, 2003, 2004 and 2005, are as follows.


In thousands	Shares			Amount

Balance, October 31, 2002		66,180		$	352,553
Issued to participants in the Employee Stock Purchase Plan (ESPP)		33			550
Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		968			17,375
Issued to participants in the Executive Long-Term Incentive Plan (LTIP)		128			2,173

Balance, October 31, 2003		67,309			372,651
Issued to ESPP		45			853
Issued to DRIP		940			19,164
Issued to LTIP		79			1,658
Sale of common stock, net of expenses		8,500			173,828
Shares repurchased		(203	)		(4,487	)

Balance, October 31, 2004		76,670			563,667
Issued to ESPP		43			904
Issued to DRIP		1,013			22,632
Issued to LTIP		77			1,796
Shares repurchased		(1,105	)		(26,119	)

Balance, October 31, 2005		76,698		$	562,880

Under the LTIP, the Board of Directors has awarded units to eligible officers and other participants. Depending upon the levels of performance targets achieved by Piedmont during multi-year performance periods, distribution of those awards may be made in the form of shares of Common Stock and cash withheld for payment of applicable taxes on the compensation. The LTIP requires that a minimum threshold performance be achieved in order for any award to be distributed. For the years ended October 31, 2005, 2004 and 2003, we recorded compensation expense for the LTIP of $4 million, $3.1 million and $3.9 million, respectively.

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

As of October 31, 2005, 3.6 million shares of Common Stock were reserved for issuance as follows.


In thousands

ESPP			177
DRIP			2,225
LTIP			1,222

Total			3,624

6. Financial Instruments and Related Fair Value

As of October 31, 2005, we had committed bank lines of credit totaling $250 million, for which we pay a maximum annual fee of $.3 million, and additional uncommitted lines of credit totaling $113 million on a no fee and as needed, if available, basis. The fee for the committed lines is based on the portion of the credit facility that is unused. As of January 17, 2006, we have increased the amount of uncommitted lines to $225 million.

Short-term borrowings under the lines, with maturity dates of less than 90 days, include LIBOR cost-plus loans, transactional borrowings and overnight cost-plus loans based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. As of October 31, 2005 and 2004, outstanding borrowings under the lines are included in “Notes payable” in the consolidated balance sheets, and consisted of $158.5 million and $109.5 million, respectively, in LIBOR cost-plus loans at a weighted average interest rate of 4.28% and 2.18%, respectively. As of October 31, 2005, the unused committed lines of credit totaled $91.5 million.

As of October 31, 2005, we had a line of credit for letters of credit of $1.5 million, of which $1.2 million were issued and outstanding. These letters of credit are used to guarantee self-insured claims under our general liability policies.

Our principal business activity is the distribution of natural gas. As of October 31, 2005, our trade accounts receivable consisted of gas receivables of $103.1 million and merchandise and jobbing receivables of $4.4 million, net of an allowance for doubtful accounts of $1.2 million. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected.

In connection with the sale in January 2004 of our propane interests, we received 37,244 common units of Energy Transfer Partners, LP. The market value of these units as of October 31, 2004, was included in “Marketable securities” in the consolidated balance sheet. In February 2005, we sold all of the common units with proceeds of $2.4 million, resulting in a pre-tax gain of $1.5 million. For further information on this transaction, see Note 10 to the consolidated financial statements.

The carrying amounts in the consolidated balance sheets of cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values due to the short-term nature of these financial instruments. Based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings, the estimated fair value amounts of long-term debt as of October 31, 2005 and 2004, including current portion, were as follows.


	2005				2004
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt	$	660,000	$	753,267	$	660,000	$	775,269

The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair value amounts. The fair value amounts do not reflect principal amounts that we will ultimately be required to pay.

We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service area where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. Our risk management policies allow us to use financial instruments for limited trading purposes and to hedge risks. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

We have purchased and sold financial options for natural gas in all three states for our gas purchase portfolios. The gains or losses on financial derivatives utilized in the regulated utility segment ultimately will be included in our rates to customers. Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due customers in accordance with Statement 71. Accordingly, there is no earnings impact on the regulated utility segment as a result of the use of these financial derivatives. As of October 31, 2005 and 2004, the total fair value of gas purchase options included in the consolidated balance sheets was $22.8 million and $13.2 million, respectively.

7. Leases and Unconditional Purchase Obligations

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. For the years ended October 31, 2005, 2004 and 2003, operating lease payments were $6.9 million, $5.7 million and $4.5 million, respectively. During 2005, we sold our corporate office building and entered into a ten-year lease on new office space beginning November 1, 2005.

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


In thousands

2006	$	7,143
2007		6,046
2008		5,146
2009		4,600
2010		3,883
Thereafter		22,615

Total	$	49,433

We routinely enter into long-term commodity purchase commitments and agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to 15 years. The time periods for gas supply contracts range from one to three years. The time periods for the telecommunications and technology contracts providing maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, cell usage fees and contract labor and consulting fees range from one to four years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

As of October 31, 2005, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.


					Telecommunications
	Pipeline and				and Information
In thousands	Storage Capacity		Gas Supply		Technology		Other		Total

2006	$	121,169	$	13,351	$	14,447	$	19,811	$	168,778
2007		117,335		191		15,126		—		132,652
2008		116,351		180		15,837		—		132,368
2009		112,282		113		16,582		—		128,977
2010		112,282		—		17,361		—		129,643
Thereafter		462,140		—		—		—		462,140

Total	$	1,041,559	$	13,835	$	79,353	$	19,811	$	1,154,558

8. Employee Benefit Plans

We have a defined-benefit pension plan for the benefit of eligible full-time employees. An employee becomes eligible on the January 1 or July 1 following either the date on which he or she attains age 30 or attains age 21 and completes 1,000 hours of service during the 12-month period commencing on the employment date. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years

prior to retirement during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes.

We provide certain postretirement health care and life insurance benefits (OPEB) to eligible full-time employees. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Employees who met this requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the full cost of the retiree’s coverage and the retiree pays the full cost of dependent coverage. Employees not in the grandfathered group have 80% of the cost of retiree coverage paid by us, subject to certain annual contribution limits. Retirees not in the grandfathered group pay 20% of the cost of their coverage plus the full cost of dependent coverage.

In connection with the acquisition of NCNG, we acquired certain pension and OPEB obligations of former employees of NCNG. In February 2004, Progress transferred $34 million attributable to the accrued pension benefits for this group as of September 30, 2003, to the trust fund for this separate “frozen” plan. Progress transferred an additional $.2 million on November 19, 2004, as a result of updated employee information. The transferred active pension plan participants began accruing benefits under the Piedmont pension plan as of October 1, 2003. The OPEB obligation of $9.7 million as of September 30, 2003, for former employees of NCNG was recorded as a liability at closing. No assets attributable to this liability were transferred from Progress.

In January 2005, we determined that the accumulated benefit obligation of the NCNG pension plan exceeded the fair value of plan assets. We recognized an additional minimum pension liability of $4.5 million with a corresponding entry to accumulated other comprehensive income of $2.7 million, net of deferred income taxes. As of October 31, 2005, the plan assets exceeded the accumulated benefit obligation and this plan is disclosed on a consolidated basis with our other pension plan.

As a result of the Medicare Prescription Drug Improvement and Modernization Act of 2003, we amended our postretirement benefit plan on August 1, 2005, to eliminate prescription drug coverage beginning January 1, 2006, for retirees who are Medicare eligible. This prescription drug benefit will be replaced by a defined dollar benefit intended to pay the premiums for Medicare Part D.

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2005 and 2004, and a statement of the funded status as recorded in the consolidated balance sheets as of October 31, 2005 and 2004, are presented below.


	2005			2004			2005			2004
In thousands	Pension Benefits						Other Benefits

Change in benefit obligation:
Obligation at beginning of year	$	226,315		$	199,732		$	38,874		$	43,680
Service cost		11,278			9,698			1,391			1,338
Interest cost		12,816			12,084			2,151			2,547
Plan amendments		—			—			(5,934	)		1,517
Actuarial (gain) loss		(1,792	)		16,888			(3,260	)		(8,194	)
Benefit payments		(12,009	)		(12,087	)		(2,490	)		(2,014	)

Obligation at end of year	$	236,608		$	226,315		$	30,732		$	38,874


	2005			2004			2005			2004
In thousands	Pension Benefits						Other Benefits

Change in fair value of plan assets:
Fair value at beginning of year	$	181,244		$	163,831		$	14,045		$	12,439
Actual return on plan assets		13,121			15,668			964			527
Employer contributions		17,300			14,232			2,721			3,152
Administrative expenses		(497	)		(400	)		—			—
Benefit payments		(12,009	)		(12,087	)		(2,455	)		(2,073	)

Fair value at end of year	$	199,159		$	181,244		$	15,275		$	14,045


Funded status:
Funded status at end of year	$	(37,449	)	$	(45,071	)	$	(15,459	)	$	(24,830	)
Unrecognized transition obligation		—			—			5,336			7,912
Unrecognized prior-service cost		5,327			6,229			—			5,522
Unrecognized actuarial gain (loss)		40,462			38,694			(4,996	)		(1,803	)

Accrued benefit asset (liability)	$	8,340		$	(148	)	$	(15,119	)	$	(13,199	)

The NCNG pension plan was underfunded as of October 31, 2004, as the accumulated benefit obligation exceeded the fair value of plan assets. The status of this plan as of October 31, 2005 and 2004, is presented below.


In thousands	2005		2004

Projected benefit obligation	$	35,981	$	36,858
Accumulated benefit obligation		35,981		36,858
Fair value of plan assets		37,741		33,005
Minimum pension liability		—		4,526

Net periodic benefit cost for the years ended October 31, 2005, 2004 and 2003, includes the following components.


	2005			2004			2003			2005			2004			2003
In thousands	Pension Benefits									Other Benefits

Service cost	$	11,278		$	9,698		$	6,060		$	1,391		$	1,338		$	808
Interest cost		12,816			12,084			10,114			2,151			2,547			2,128
Expected return on plan assets		(16,593	)		(16,220	)		(13,375	)		(1,030	)		(922	)		(817	)
Amortization of transition obligation		—			—			14			879			879			879
Amortization of prior-service cost		933			931			931			1,285			1,030			859
Amortization of actuarial (gain) loss		378			—			(840	)		—			280			198

Total	$	8,812		$	6,493		$	2,904		$	4,676		$	5,152		$	4,055

In determining the market-related value of plan assets, we use the following methodology. The asset gain or loss is determined each year by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Such asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of year end is determined by adjusting the market value of assets by the portion of the prior five years’ gains or losses that has not yet been recognized. This method has been applied consistently in all years presented in the consolidated financial statements. The discount rate can vary from plan year to plan year. October 31 is the measurement date for the plans.

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 that produces similar results to a hypothetical bond portfolio. As of October 31, 2005, the benchmark was 6.03% for the Piedmont pension plan, 5.84% for the NCNG pension plan and 5.89% for OPEB.

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

The weighted average assumptions used in the measurement of the benefit obligation as of October 31, 2005, 2004 and 2003, are presented below.


	2005			2004			2003			2005			2004			2003
	Pension Benefits									Other Benefits

Discount rate		6.00	%		5.75	%		6.25	%		5.89	%		5.75	%		6.25	%
Rate of compensation increase		4.05	%		3.97	%		3.97	%		4.05	%		3.97	%		3.97	%

The weighted average assumptions used to determine the net periodic benefit cost as of October 31, 2005, 2004 and 2003, are presented below.


	2005			2004			2003			2005			2004			2003
	Pension Benefits									Other Benefits

Discount rate		6.00	%		5.75	%		6.25	%		5.89	%		5.75	%		6.25	%
Expected long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%		8.50	%
Rate of compensation increase		4.05	%		3.97	%		3.97	%		N/A			N/A			N/A

The weighted-average asset allocations by asset category for the two pension plans and the OPEB plan as of October 31, 2005 and 2004, are presented below.


	2005			2004			2005			2004
	Pension Benefits						Other Benefits

Equity securities		63	%		62	%		45	%		47	%
Debt securities		37	%		38	%		55	%		53	%

Total		100	%		100	%		100	%		100	%

We have long-term target allocations for the pension and OPEB plans by asset category of 60% for equity securities and 40% for debt securities. Our primary investment objective is to generate sufficient assets to meet plan liabilities. The plans’ assets will therefore be invested to maximize long-term returns consistent with the plans’ liabilities, cash flow requirements and risk tolerance. The plans’ liabilities are primarily defined in terms of participant salaries. Given the nature of these liabilities, and recognizing the long-term benefits of investing in equity securities, we invest in a diversified portfolio which includes a significant exposure to equity securities. Specific financial targets include:

	•		Achieve full funding over the longer term,

	•		Control fluctuation in pension expense from year to year,

	•		Achieve satisfactory performance relative to other similar pension plans, and

	•		Achieve positive returns in excess of inflation over short to intermediate time frames.

To develop the expected long-term rate of return on assets assumption, we considered historical returns and future expectations for returns for each asset class, as well as target asset allocation of the pension and OPEB portfolios. We believe the expected long-term rate of return on the pension and OPEB plans should remain at 8.50% for 2006.

We estimate that we will contribute $15.3 million to the pension plans and $2.6 million to the OPEB plan in 2006.

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


	Pension		Other
In thousands	Benefits		Benefits

2006	$	13,231	$	2,154
2007		12,877		2,251
2008		14,393		2,177
2009		17,347		2,209
2010		15,701		2,304
2011-2015		95,211		13,145

The assumed health care cost trend rates used in measuring the accumulated OPEB obligation for the medical plans for all participants as of October 31, 2005 and 2004, are presented below.


	2005			2004

Health care cost trend rate assumed for next year		9.75	%		10.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2012			2012

In the past, information for participants aged less than 65 and those aged greater than 65 was maintained separately for calculating the heath care cost trend rate; however, actual experience and trend guidelines were indicating that post-age 65 medical trends were lower than pre-65 medical trends and prescription drug trends for both groups were at about the same level. Since post-age 65 participants have more prescription claims as a group, the trends are nearly equal. The change in trend rates did not have a material effect on the accumulated OPEB obligation.

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


In thousands	1% Increase		1% Decrease

Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2005		$ 103		$ (111	)

Effect on the health care cost component of the accumulated postretirement benefit obligation as of October 31, 2005		1,024		(1,037	)

We maintain salary investment plans which are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). The salary investment plans are subject to the provisions of the Employee Retirement Income Security Act. Full-time employees who have completed six months of continuous service and have attained age 18 are eligible to participate. Participants may defer a portion of their base salary to the plans and we match a portion of their contributions. All contributions vest immediately. For the years ended October 31, 2005, 2004 and 2003, our matching contributions totaled $3.2 million, $2.9 million and $2.3 million, respectively. There are several investment options available to enable participants to diversify their accounts. Participants may invest in Piedmont stock up to a maximum of 20% of their account.

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

9. Income Taxes

The components of income tax expense for the years ended October 31, 2005, 2004 and 2003, are as follows.


	2005						2004						2003
In thousands	Federal			State			Federal			State			Federal			State

Charged to operating income:
Current	$	19,073		$	3,880		$	18,414		$	9,298		$	(4,581	)	$	(959	)
Deferred		24,006			5,462			24,880			(557	)		38,252			7,931
Amortization of investment tax credits		(541	)		—			(550	)		—			(550	)		—

Total		42,538			9,342			42,744			8,741			33,121			6,972


Charged to other income (expense):
Current		15,588			2,966			11,293			2,236			7,685			1,561
Deferred		(6,407	)		(1,701	)		(2,582	)		(385	)		(623	)		(99	)

Total		9,181			1,265			8,711			1,851			7,062			1,462

Total	$	51,719		$	10,607		$	51,455		$	10,592		$	40,183		$	8,434

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2005, 2004 and 2003, is as follows.


In thousands	2005			2004			2003

Federal taxes at 35%	$	57,258		$	55,032		$	43,043
State income taxes, net of federal benefit		6,894			6,885			5,482
Amortization of investment tax credits		(541	)		(550	)		(550	)
Sale of propane interests		(1,624	)		—			—
Other, net		339			680			642

Total	$	62,326		$	62,047		$	48,617

As of October 31, 2005 and 2004, deferred income taxes consisted of the following temporary differences.


In thousands	2005			2004

Utility plant	$	208,947		$	198,110
Equity method investments		12,114			22,148
Revenues and cost of gas		25,273			10,946
Other, net		(10,156	)		(11,863	)

Net deferred income tax liabilities	$	236,178		$	219,341

As of October 31, 2005 and 2004, total deferred income tax liabilities were $261.6 million and $239.4 million and total net deferred income tax assets were $25.4 million and $20.1 million, respectively. Total net deferred income tax assets as of October 31, 2005 and 2004, were net of a valuation allowance of $.5 million and $1.2 million, respectively, for net operating loss carryforwards that we believed were more likely than not to expire before we could use them. Piedmont and its wholly owned subsidiaries file a consolidated federal income tax return. Prior to October 25, 2005, EasternNC filed a separate federal income tax return as we did not own the prerequisite 80% share of EasternNC to allow EasternNC to participate in our consolidated federal return. With Piedmont’s acquisition of the remaining 50% interest in EasternNC, EasternNC became a member of Piedmont’s consolidated group on October 25, 2005, and was immediately merged into Piedmont. As of the acquisition date, EasternNC had federal and state net operating loss carryforwards of $7.5 million that expire from 2017 through 2025. Piedmont may use the EasternNC federal loss carryforwards to offset taxable income, subject to an annual limitation of $.3 million.

A reconciliation of changes in the deferred tax valuation allowance for the years ended October 31, 2005, 2004 and 2003, is as follows.


In thousands	2005			2004		2003

Balance at beginning of year	$	1,200		$	1,000	$	—
Charged (credited) to income tax expense		(700	)		200		1,000

Balance at end of year	$	500		$	1,200	$	1,000

During the year ended October 31, 2004, the Internal Revenue Service finalized its audit of our returns for the tax year ended October 31, 2001. The audit results, which did not have a material effect on our financial position or results of operations, have been reflected in the consolidated financial statements. The Internal Revenue Service is auditing our tax return for the tax year ended October 31, 2002. We believe the results of the audit will not have a material effect on our financial position or results of operations.

10. Equity Method Investments

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

As of October 31, 2005, the amount of our retained earnings that represented undistributed earnings of 50% or less owned equity method investments was $6.2 million.

Cardinal Pipeline Company, L.L.C.

We own 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies for 100% of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately 37%. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is secured by Cardinal’s assets and by each member’s equity investment in Cardinal.

We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For the years ended October 31, 2005, 2004 and 2003, these gas costs were $4.7 million, $4.7 million and $1.7 million, respectively. As of October 31, 2005 and 2004, we owed Cardinal $.4 million.

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2005 and 2004, and for the twelve months ended September 30, 2005, 2004 and 2003, is presented below.


In thousands	2005		2004		2003

Current assets	$	7,270	$	8,142
Non-current assets		88,250		91,049
Current liabilities		3,238		3,612
Non-current liabilities		37,496		39,360
Revenues		15,525		15,567	$	16,880
Gross profit		15,525		15,567		16,880
Income before income taxes		8,368		8,102		9,211

Pine Needle LNG Company, L.L.C.

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

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

We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2005, 2004 and 2003, these gas costs were $12.4 million, $12.3 million and $10.6 million, respectively. As of October 31, 2005 and 2004, we owed Pine Needle $1.1 million and $1 million, respectively.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2005 and 2004, and for the twelve months ended September 30, 2005, 2004 and 2003, is presented below.


In thousands	2005		2004		2003

Current assets	$	8,653	$	10,573
Non-current assets		92,255		94,745
Current liabilities		6,752		8,161
Non-current liabilities		40,251		45,933
Revenues		19,870		19,357	$	20,013
Gross profit		19,870		19,357		20,013
Income before income taxes		9,480		9,372		9,320

US Propane, L.P.

Prior to January 20, 2004, we owned 20.69% of the membership interests in US Propane, L.P. The other members were subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. In January 2004, we, along with the other members, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane for $130 million.

In connection with the sale, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units. The market value of these units as of October 31, 2004, was included in “Marketable securities” in the consolidated balance sheet. On February 1, 2005, we sold 18,622 of the units and on February 2, 2005, we sold the remaining 18,622 units for total cash proceeds of $2.4 million. We recorded a pre-tax gain of $1.5 million in the consolidated statement of income for the year ended October 31, 2005.

SouthStar Energy Services LLC

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. The other member is AGL Resources, Inc. (AGLR). Under the terms of an amended and restated limited liability company operating agreement with AGLR effective January 1, 2004, earnings and losses are allocated 25% to us and 75% to AGLR. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

SouthStar utilizes financial contracts to hedge the variable cash flows associated with changes in the price of natural gas. These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. SouthStar does not enter into or hold derivatives for trading or speculative purposes. SouthStar also enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. Movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive income (loss)” in the consolidated balance sheets.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the years ended October 31, 2005, 2004 and 2003, these operating revenues were $10.3 million, $2.7 million and $.9 million, respectively. As of October 31, 2005 and 2004, SouthStar owed us $.9 million and $.6 million, respectively.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2005 and 2004, and for the twelve months ended September 30, 2005, 2004 and 2003, is presented below.


In thousands	2005		2004		2003

Current assets	$	218,562	$	157,656
Non-current assets		5,472		4,066
Current liabilities		109,111		50,045
Revenues		861,091		790,288	$	727,871
Gross profit		148,885		122,811		99,618
Income before income taxes		91,200		72,056		55,805

Hardy Storage Company LLC

We own 50% of the membership interests in Hardy Storage Company LLC (Hardy Storage). The other owner is a subsidiary of Columbia Gas Transmission Corporation (Columbia Gas), a subsidiary of NiSource Inc. Hardy Storage intends to construct, own and operate an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia. The facility will have the capacity to store approximately 12 billion cubic feet of natural gas and deliver up to 176,000 dekatherms per day by November 2009. Construction is expected to begin in early 2006 with storage service commencing with initial injections in April 2007. The project is fully subscribed under long-term contracts. Total project capital expenditures are estimated at $135 to $145 million.

On November 1, 2005, the FERC issued an order granting a certificate of public convenience and necessity to Hardy Storage authorizing it to construct and operate the proposed project. In December 2005, two intervenors filed for rehearing with the FERC contesting the inclusion of income tax allowances in Hardy Storage’s rates. The project sponsors will continue to pursue the development of the project with the goal of meeting the target in-service date of April 2007.

11. Business Segments

We have two reportable business segments, regulated utility and non-utility activities. These segments were identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. Operations of our regulated utility segment are conducted by the parent company and, through October 25, 2005, by EasternNC. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures.

Operations of the regulated utility segment are reflected in operating income in the consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments.”

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. All of our operations are within the United States. No single customer accounts for more than 10% of our consolidated revenues.

Operations by segment for the years ended October 31, 2005, 2004 and 2003, and as of October 31, 2005 and 2004, are presented below.


	Regulated		Non-Utility
In thousands	Utility		Activities			Total

2005
Revenues from external customers	$	1,761,091	$	—		$	1,761,091
Margin		499,139		—			499,139
Operations and maintenance expenses		206,983		214			207,197
Depreciation		85,169		—			85,169
Income from equity method investments		—		27,664			27,664
Interest expense		44,256		52			44,308
Operating income (loss) before income taxes		177,180		(403	)		176,777
Income before income taxes and minority interest		135,758		28,440			164,198
Total assets		2,527,993		71,520			2,599,513
Equity method investments in non-utility activities		—		71,520			71,520
Construction expenditures		157,883		—			157,883

2004
Revenues from external customers	$	1,529,739	$	—		$	1,529,739
Margin		488,369		—			488,369
Operations and maintenance expenses		200,282		172			200,454
Depreciation		82,276		—			82,276
Income from equity method investments		—		27,381			27,381
Interest expense		47,364		48			47,412
Operating income (loss) before income taxes		178,800		(234	)		178,566
Income before income taxes and minority interest		125,044		32,239			157,283
Total assets		2,325,110		67,179			2,392,289
Equity method investments in non-utility activities		—		65,322			65,322
Construction expenditures		103,187		—			103,187

2003
Revenues from external customers	$	1,220,822	$	—		$	1,220,822
Margin		382,880		—			382,880
Operations and maintenance expenses		152,107		73			152,180
Depreciation		63,164		—			63,164
Income from equity method investments		—		17,972			17,972
Interest expense		40,197		58			40,255
Operating income (loss) before income taxes		143,199		(132	)		143,067
Income before income taxes and minority interest		106,150		17,649			123,799
Construction expenditures		80,315		—			80,315

Reconciliations to the consolidated financial statements for the years ended October 31, 2005, 2004 and 2003, and as of October 31, 2005 and 2004, are as follows.


In thousands	2005			2004			2003

Operating Income:
Segment operating income before income taxes	$	176,777		$	178,566		$	143,067
Utility income taxes		(51,880	)		(51,485	)		(40,093	)
Non-utility activities before income taxes		403			234			132

Total	$	125,300		$	127,315		$	103,106


Net Income:
Income before income taxes and minority interest for reportable segments	$	164,198		$	157,283		$	123,799
Income taxes		(62,326	)		(62,047	)		(48,617	)
Less minority interest		(602	)		(48	)		(820	)

Total	$	101,270		$	95,188		$	74,362


Consolidated Assets:
Total assets for reportable segments	$	2,599,513		$	2,392,289
Eliminations/Adjustments		2,977			(125	)

Total	$	2,602,490		$	2,392,164

12. Environmental Matters

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

Several years ago, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount, charged to the estimated environmental liability, that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. Three other MGP sites that we also have owned, leased or operated were not included in the settlement. In addition to these sites, we acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Gas Services, a division of NUI Utilities, Inc.

As of October 31, 2005, our undiscounted environmental liability totaled $3.2 million, and consisted of $2.8 million for the four MGP sites and $.4 million for underground storage tanks not yet remediated. We increased the liability in 2005 by $.2 million and in 2004 by $.1 million to reflect the impact of inflation based on the consumer price index.

As of October 31, 2005, our regulatory assets for unamortized environmental costs totaled $4.1 million. The portion of the regulatory assets representing actual costs incurred, including the settlement payment to the third party, is being amortized as recovered in rates from customers.

Further evaluations of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, cash flows or results of operations.

In connection with the acquisition in 2003 of NCNG, several MGP sites owned by NCNG were transferred to a wholly owned

subsidiary of Progress prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the cost of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. We know of no such pending or threatened claims.

On October 30, 2003, in connection with the 2003 NCNG general rate case proceeding discussed in Note 3 to the consolidated financial statements, the NCUC ordered an environmental regulatory liability of $3.5 million be established for refund to customers over the three-year period beginning November 1, 2003. This liability resulted from a payment made to NCNG by its insurers prior to our acquisition. As a part of the 2005 NCUC general rate case proceeding also discussed in Note 3, the NCUC ordered a new three-year amortization period for the unamortized balance as of June 30, 2005, beginning November 1, 2005.

On July 26, 2005, we were notified by the North Carolina Department of Environment and Natural Resources that we were named as a potentially responsible party for alleged environmental problems associated with an underground storage tank site. We owned this site for less than two years several years ago in connection with a non-utility venture. There have been at least four owners of the site. We contractually transferred any clean-up costs to the new owner of the site when we sold this venture. Our current estimate of the cost to remediate the site is approximately $120,000. It is unclear how many of the former owners may ultimately be held liable for this site; however, based on the uncertainty of the ultimate liability, we established a non-regulated environmental liability for $30,000, one-fourth of the estimated cost.

13. Restatement of Statements of Cash Flows and Balance Sheet

Subsequent to the issuance of our 2004 financial statements, management identified errors in the consolidated statements of cash flows for the years ended October 31, 2004 and 2003, relating to distributions of earnings received from equity method investees, changes in restricted cash and the amounts reported as construction expenditures. Management also identified errors in the consolidated balance sheet as of October 31, 2004, relating principally to the inappropriate netting of customer credit balances in accounts receivable and prepaid group insurance assets in accounts payable. Additionally, management determined that we should have separately reported gas purchase options at fair value which previously had been included within amounts due to customers and amounts due from customers, and also identified other classification errors affecting balances reported for current and deferred income tax assets and liabilities.

As a result, the accompanying 2004 and 2003 consolidated financial statements have been restated from the amounts previously reported to correct the presentation of these items. The restatement did not affect previously reported operating income, net income, earnings per share or stockholders’ equity.

A summary of the significant effects of the restatement is as follows:


In thousands	As Previously
As of October 31, 2004	Reported		As Restated
Total current assets	$	335,209	$	390,742
Total current liabilities		306,167		336,155
Deferred income taxes (non-current)		202,155		212,925
Other deferred liabilities		41,465		56,994


	2004						2003
	As						As
In thousands	Previously						Previously
For the Years Ended October 31	Reported			As Restated			Reported			As Restated
Cash flows from operating activities:
Distributions of earnings from equity method investments	$	—		$	26,078		$	—		$	9,946
Decrease (increase) in restricted cash		(5,983	)		—			1,936			—
Net cash provided by operating activities		154,293			183,739			96,652			103,790

Cash flows from investing activities:
Distributions of capital from equity method investments		26,291			213			10,188			242
Decrease (increase) in restricted cash		—			(5,983	)		—			1,936
Net cash used in investing activities		(36,303	)		(65,749	)		(515,152	)		(522,290	)

* * * * *

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


										Earnings (Loss)
							Net			Per Share of
	Operating				Operating		Income			Common Stock
	Revenues		Margin		Income		(Loss)			Basic			Diluted


Fiscal Year 2005
January 31	$	680,556	$	202,620	$	78,919	$	71,277		$	.93		$	.93
April 30		508,035		140,657		40,914		39,632			.52			.52
July 31		232,912		76,616		2,984		(4,666	)		(.06	)		(.06	)
October 31		339,588		79,246		2,483		(4,973	)		(.06	)		(.06	)

Fiscal Year 2004
January 31	$	618,785	$	196,480	$	77,349	$	74,622		$	1.09		$	1.09
April 30		482,398		145,855		45,904		41,259			.54			.54
July 31		214,750		69,728		1,465		(8,157	)		(.11	)		(.11	)
October 31		213,806		76,306		2,597		(12,536	)		(.16	)		(.16	)

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

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

None.

Item 9A. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

Management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures. Such disclosure controls and procedures are designed to ensure that all information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on our evaluation process, the Chief Executive Officer and the Chief Financial Officer have concluded that our disclosure controls and procedures are effective as of October 31, 2005. Management’s report on internal control over financial reporting and the attestation report of our independent registered public accounting firm are on Page 68 and Page 69, respectively. There were no changes in our internal control over financial reporting during the fourth quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

January 17, 2006

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

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

We have conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based upon such evaluation, our management concluded that our internal control over financial reporting was effective as of October 31, 2005.

Management’s assessment of the effectiveness of our internal control over financial reporting as of October 31, 2005, has been audited by Deloitte and Touche LLP, an independent registered public accounting firm. Their attestation report is on Page 69.

Piedmont Natural Gas Company, Inc.



	/s/ Thomas E. Skains
	Thomas E. Skains
	Chairman, President and Chief Executive Officer


	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer


	/s/ Barry L. Guy
	Barry L. Guy
	Vice President and Controller

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Piedmont Natural Gas Company Inc. and subsidiaries (“Piedmont”) maintained effective internal control over financial reporting as of October 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Piedmont’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of Piedmont’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

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

In our opinion, management’s assessment that Piedmont maintained effective internal control over financial reporting as of October 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, Piedmont maintained, in all material respects, effective internal control over financial reporting

PART III

Item 10. Directors and Executive Officers of the Registrant

Information concerning our executive officers and directors is set forth in the sections entitled “Election of Directors” and “Executive Officers” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning our Audit Committee and our Audit Committee financial expert is set forth in the section entitled “Committees of the Board” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

We have adopted a Code of Business Conduct and Ethics that is applicable to all our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics was filed as Exhibit 14.1 to our annual report on Form 10-K for the year ended October 31, 2003, and is available on our website at www.piedmontng.com. If we amend the Code of Business Conduct and Ethics or grant a waiver, including an implicit waiver, from the Code of Business Conduct and Ethics, we intend to disclose the information on our website within four business days of such amendment or waiver.

Item 11. Executive Compensation

Information for this item is set forth in the sections entitled “Executive Compensation and Other Information” and “Directors’ Compensation Policy” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference.

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

Information for this item is set forth in the sections entitled “Security Ownership of Management” and “Security Ownership of Certain Beneficial Owners” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which sections are incorporated in this annual report on Form 10-K by reference.

We know of no arrangement, or pledge, which may result in a change in control. Information describing any material changes to the procedures for recommending nominees to the Board is set forth in the section entitled “Questions and Answers About the Annual Meeting

and Voting” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Information concerning securities authorized for issuance under our equity compensation plans is set forth in the section entitled “Long-Term Incentive Plan Awards” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Item 13. Certain Relationships and Related Transactions

Information for this item is set forth in the section entitled “Certain Relationships and Related Transactions” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

Item 14. Principal Accounting Fees and Services

Information for this item is set forth in the section entitled “Selection of Independent Registered Public Accounting Firm” in our Proxy Statement for the 2006 Annual Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules


(a)			1.			Financial Statements

The following consolidated financial statements for the year ended October 31, 2005, are included in Item 8 of this report as follows:


		Page

Consolidated Balance Sheets — October 31, 2005 and 2004 (Restated)		32
Consolidated Statements of Income — Years Ended October 31, 2005, 2004 and 2003		34
Consolidated Statements of Cash Flows — Years Ended October 31, 2005, 2004 (Restated) and 2003 (Restated)		36
Consolidated Statements of Stockholders’ Equity — Years Ended October 31, 2005, 2004 and 2003		38
Notes to Consolidated Financial Statements		40


(a)			2.			Supplemental Consolidated Financial Statement Schedules

None

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


(a)	3.	Exhibits

		Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, we will provide a copy of the exhibit at a nominal charge.

		The exhibits numbered 10.1 through 10.18 are management contracts or compensatory plans or arrangements.

	3.1	Articles of Incorporation as of March 7, 1997, filed in the Department of State of the State of North Carolina (Exhibit 4.6, Form S-3 Registration Statement No. 333-111806).


			3.2			Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed “Piedmont Natural Gas Company, Inc.” (Exhibits 3.2 and 3.1, Registration Statement on Form 8-B, dated March 2, 1994).

			3.3			By-Laws, dated February 27, 2004 (Exhibit 3.1, Form 10-Q for the quarter ended April 30, 2004).

			4.1			Note Agreement, dated as of July 30, 1991, between Piedmont and The Prudential Insurance Company of America (Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 1991).

			4.2			Note Agreement, dated as of September 21, 1992, between Piedmont and Provident Life and Accident Insurance Company (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992).

			4.3			Indenture, dated as of April 1, 1993, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.1, Form S-3 Registration Statement No. 33-59369).

			4.4			Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7, Form 10-K for the fiscal year ended October 31, 1993).

			4.5			Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993).

			4.6			First Supplemental Indenture, dated as of February 25, 1994, between PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and Citibank, N.A., Trustee (Exhibit 4.2, Form S-3 Registration Statement No. 33-59369).

			4.7			Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994).

			4.8			Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995).

			4.9			Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996).

			4.10			Rights Agreement, dated as of February 27, 1998, between Piedmont and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1, Form 8-K dated February 27, 1998).


			4.11			Agreement of Substitution and Amendment of Common Shares Rights Agreement, dated as of December 18, 2003, between Piedmont and American Stock Transfer and Trust Company, Inc. (Exhibit 4.10, Form S-3 Registration Statement No. 333-111806).

			4.12			Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4, Form S-3 Registration Statement No. 333-26161).

			4.13			Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).

			4.14			Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement Nos. 33-59369 and 333-26161).

			4.15			Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement No. 333-26161).

			4.16			Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4, Form S-3 Registration Statement No. 333-62222).

			4.17			Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration Statement No. 333-62222).

			4.18			Second Supplemental Indenture, dated as of June 15, 2003, between Piedmont and Citibank, N.A., Trustee (Exhibit 4.3, Form S-3 Registration Statement No. 333-106268).

			4.19			Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.1, Form 8-K, dated December 23, 2003).

			4.20			Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003 (Exhibit 99.2, Form 8-K, dated December 23, 2003).

						Compensatory Contracts:

			10.1			Form of Director Retirement Benefits Agreement with outside directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999).


			10.2			Executive Long-Term Incentive Plan, dated February 27, 2004 (Exhibit 10.2, Form 10-Q for quarter ended April 30, 2004).

			10.3			Employment Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1999).

			10.4			Employment Agreement with Ray B. Killough, dated December 1, 1999 (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1999).

			10.5			Employment Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999).

			10.6			Employment Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 2002).

			10.7			Employment Agreement with Kim R. Cocklin, dated February 3, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2003).

			10.8			Severance Agreement with David J. Dzuricky, dated December 1, 1999 (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1999).

			10.9			Severance Agreement with Ray B. Killough, dated December 1, 1999 (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1999).

			10.10			Severance Agreement with Thomas E. Skains, dated December 1, 1999 (Exhibit 10.44, Form 10-K for the fiscal year ended October 31, 1999).

			10.11			Severance Agreement with Franklin H. Yoho, dated March 18, 2002 (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 2002).

			10.12			Severance Agreement with Kim R. Cocklin, dated February 3, 2003 (Exhibit 10.2, Form 10-Q for the quarter ended April 30, 2003).

			10.13			Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (Exhibit 10.1, Form 8-K dated December 10, 2004).

			10.14			Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (with supplemental retirement benefit) (Exhibit 10.14, Form 10-K for the fiscal year ended October 31, 2004).


			10.15			Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Supplemental Executive Benefit Plan (Amended and Restated as of November 1, 2004) (without supplemental retirement benefit) (Exhibit 10.15, Form 10-K for the fiscal year ended October 31, 2004).

			10.16			Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (effective November 1, 2003) (Exhibit 10.16, Form 10-K for the fiscal year ended October 31, 2004).

			10.17			Form of Participation Agreement under the Piedmont Natural Gas Company, Inc. Short-Term Incentive Plan (STIP) (Exhibit 10.17, Form 10-K for the fiscal year ended October 31, 2004).

			10.18			Jerry W. Amos Engagement Letter dated January 3, 2005 (Exhibit 10.1, Form 8-K filed January 6, 2005) (Exhibit 10.18, Form 10-K for the fiscal year ended October 31, 2004).

						Other Contracts:

			10.19			Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company (Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2004).

			10.20			Equity Contribution Agreement, dated as of November 12, 2004, between Columbia Gas Transmission Corporation and Piedmont Natural Gas Company (Exhibit 10.1, Form 8-K dated November 16, 2004).

			10.21			Construction, Operation and Maintenance Agreement by and Between Columbia Gas Transmission Corporation and Hardy Storage Company, LLC, dated November 12, 2004 (Exhibit 10.2, Form 8-K dated November 16, 2004).

			10.22			Operating Agreement of Hardy Storage Company, LLC, dated as of November 12, 2004 (Exhibit 10.3, Form 8-K dated November 16, 2004).

			12			Computation of Ratio of Earnings to Fixed Charges.

			21			List of Subsidiaries.

			23.1			Consent of Independent Registered Public Accounting Firm.

			31.1			Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.

SIGNATURES

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


		Piedmont Natural Gas Company, Inc.
		(Registrant)

		By:		/s/ Thomas E. Skains

				Thomas E. Skains Chairman of the Board, President and Chief Executive Officer

		Date: January 17, 2006

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


Signature		Title

/s/ Thomas E. Skains		Chairman of the Board, President and

Thomas E. Skains		Chief Executive Officer
		(Principal Executive Officer)

Date: January 17, 2006

/s/ David J. Dzuricky		Senior Vice President and

David J. Dzuricky		Chief Financial Officer
		(Principal Financial Officer)

Date: January 17, 2006

/s/ Barry L. Guy		Vice President and Controller

Barry L. Guy		(Principal Accounting Officer)

Date: January 17, 2006


In thousands	2005		2004			2003
			(As Restated - See Note 13)
Noncash Investing and Financing Activities:
Accrued construction expenditures	$	2,036	$	2,615		$	872

Acquisitions of NCNG and EasternNC:
Fair value of assets (liabilities) acquired			$	(2,694	)	$	511,135
Cash paid				(271	)		(457,353	)
Adjustment of estimated working capital to actual				271			2,010

Liabilities assumed			$	(2,694	)	$	55,792


Signature		Title

/s/ Jerry W. Amos		Director

Jerry W. Amos

/s/ D. Hayes Clement		Director

D. Hayes Clement

/s/ Malcolm E. Everett III		Director

Malcolm E. Everett III

/s/ John W. Harris		Director

John W. Harris

/s/ Aubrey B. Harwell, Jr.		Director

Aubrey B. Harwell, Jr.

/s/ Muriel W. Helms		Director

Muriel W. Helms

/s/ Frank B. Holding, Jr.		Director

Frank B. Holding, Jr.

/s/ Minor M. Shaw		Director

Minor M. Shaw

/s/ David E. Shi		Director

David E. Shi

12		Computation of Ratio of Earnings to Fixed Charges.

21		List of Subsidiaries

23.1		Consent of Independent Registered Public Accounting Firm.

31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.

31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.