Piedmont Natural Gas

10-K/A 1 g89085e10vkza.htm PIEDMONT NATURAL GAS Piedmont Natural Gas

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A
AMENDMENT NO. 1

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the fiscal year ended October 31, 2003

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

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.)

1915 Rexford Road, Charlotte, North Carolina		28211

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). Yes x No o

State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of April 30, 2003.

Common Stock, no par value - $1,233,063,624

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 15, 2004

Common Stock, no par value		33,780,260

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on February 27, 2004, are incorporated by reference into Part III.

EXPLANATORY NOTE

This Amendment No. 1 to the Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc., for the fiscal year ended October 31, 2003, is being filed for the purpose of amending and revising segment information on Page 3 of Item 1, Business, Item 6, Selected Financial Data, and Item 8, Financial Statements and Supplementary Data. In accordance with accounting guidance issued subsequent to the original filing of the Annual Report on Form 10-K on January 27, 2004, the original Annual Report on Form 10-K is being amended to reflect the reclassification of amounts recorded for the cost of removal of utility plant, previously recognized in accumulated depreciation, as a separate liability for the periods ended October 31, 2002, 2001, 2000 and 1999. This amendment does not reflect events occurring after the original filing of the Form 10-K or substantively modify or update those disclosures except as stated in the preceding sentence.

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 940,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee, including 60,000 customers served by municipalities who are our wholesale customers. Our subsidiaries are invested in joint venture, energy-related businesses, including unregulated retail natural gas and propane marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. We also sell residential and commercial gas appliances in Tennessee.

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 for $417.5 million in cash 100% of the common stock of North Carolina Natural Gas Corporation (NCNG) from Progress Energy, Inc. (Progress). NCNG, a natural gas distributor, served approximately 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. The purchase price for the NCNG common stock was increased by the amount of NCNG’s working capital on the closing date. Based on a preliminary working capital schedule, the closing date working capital was $32.4 million. The preliminary working capital amount will be adjusted in 2004 to actual under the terms of the purchase agreement. NCNG was merged into Piedmont immediately following the closing. We also purchased for $7.5 million in cash Progress’ equity interest in Eastern North Carolina Natural Gas Company (EasternNC). Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. EasternNC is a regulated utility that has 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.

We have two reportable business segments, regulated utility and non-utility activities. Operations of our regulated utility segment are conducted by Piedmont, the parent company, and by EasternNC and are conducted within the United States of America. Operations of our non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company (Piedmont Intrastate), Piedmont Interstate Pipeline Company (Piedmont Interstate), Piedmont Energy Company (Piedmont Energy), Piedmont Propane Company (Piedmont Propane) and Piedmont Greenbrier Pipeline Company,

LLC (Piedmont Greenbrier), through their investments in ventures accounted for under the equity method. All of these companies, except for Piedmont Greenbrier, are wholly owned subsidiaries of Piedmont Energy Partners, a holding company which is a wholly owned subsidiary of the parent company. Piedmont Greenbrier is a wholly owned subsidiary of the parent company.

Piedmont Intrastate owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina. Piedmont Interstate owns 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina. Piedmont Greenbrier owns 33% of the membership interest in Greenbrier Pipeline Company, LLC (Greenbrier). Greenbrier proposed to build a 280-mile interstate gas pipeline. Piedmont Energy owns 30% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. 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. Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P., which owns all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage). Heritage is a marketer of propane through a nationwide retail distribution network.

On November 6, 2003, Piedmont Greenbrier sold its interest in Greenbrier to Dominion Resources Inc., the other member in the venture, for its book value of $9.2 million. On November 7, 2003, we, along with the other members of US Propane, entered into an agreement to sell the general and limited partnership interests in Heritage to a third party for $130 million. Our share of the sale proceeds is expected to be $26.9 million. In connection with the sale, US Propane retained approximately 180,000 common units of Heritage for ultimate distribution to US Propane’s members. This transaction closed on January 20, 2004.

Operations by segment for the years ended October 31, 2003, 2002 and 2001, are presented below.


		Regulated		Non-Utility
		Utility		Activities			Total

		(in thousands)
2003
	Revenues from external customers	$	1,220,822	$	—		$	1,220,822
	Income before income taxes and minority interest		106,150		17,649			123,799
	Income from non-utility activities, at equity		—		17,972			17,972
	Total assets		2,214,566		112,690			2,327,256
	Long-lived assets (Utility Plant in Service and Other Physical Property)		2,333,383		—			2,333,383
	Deferred tax assets		12,587		(563	)		12,024
2002
	Revenues from external customers	$	832,028	$	—		$	832,028
	Income before income taxes and minority interest		83,525		18,486			102,011
	Income from non-utility activities, at equity		—		19,207			19,207
	Total assets*		1,577,858		95,302			1,673,160
	Long-lived assets (Utility Plant in Service and Other Physical Property)		1,692,352		—			1,692,352
	Deferred tax assets		11,080		(821	)		10,259
2001
	Revenues from external customers	$	1,107,856	$	—		$	1,107,856
	Income before income taxes and minority interest		92,038		15,322			107,360
	Income from non-utility activities, at equity		—		16,271			16,271
	Total assets*		1,514,337		83,567			1,597,904
	Long-lived assets (Utility Plant in Service and Other Physical Property)		1,572,278		—			1,572,278
	Deferred tax assets		6,190		3,205			9,395

* Reflects reclassification of estimated cost of removal of utility plant previously recognized in accumulated depreciation to a separate liability.

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, 2003, 43% of our operating revenues were from residential customers, 25% from commercial customers, 9% from industrial and power generation customers, 22% from secondary market activity and 1% from various other sources. Revenues, less related costs, from the non-utility activities segment and earnings from equity investments are shown in “Other Income (Expense)” in the consolidated statements of income in “Non-operating income” or “Non-utility activities, at equity,” respectively. For further information on equity investments and segments, see Notes 10 and 11 to the consolidated financial statements in Item 8 of this Form 10-K.

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 subject to regulation by the NCUC as to the issuance of securities. The utility operations of EasternNC are subject to regulation by the NCUC. 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 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 and maintenance 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, that are generally applicable to companies doing business in the United States.

We hold non-exclusive franchises for natural gas service in the communities we serve, with expiration dates from 2004 to 2053. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. As of October 31, 2003, three franchises have expired; however, we continue to operate in those areas with no significant impact on our business as we have operated normally within the provisions of the expired franchise. 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, 2003, the amount of natural gas in storage varied from 3.1 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 22.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $14.1 million to $113.4 million.

During the year ended October 31, 2003, 62.4 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 60.1 million dekatherms in 2002. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 86 million dekatherms in 2003, compared with 65.9 million dekatherms in 2002. Weather, as measured by degree days, was 3% colder than normal in 2003 and 15% warmer than normal in 2002.

The following is a five-year comparison of operating statistics for the years ended October 31, 1999 through 2003:


				2003			2002			2001			2000			1999

OPERATING REVENUES (in thousands):
	Sales and Transportation:
		Residential		$	524,916		$	358,027		$	525,650		$	343,476		$	295,108
		Commercial			299,240			191,988			299,672			207,087			168,731
		Industrial			112,936			102,127			128,831			183,685			122,597
		For Power Generation			3,071			2,368			1,316			18,849			20,911
		For Resale			1,948			374			371			249			254
		EasternNC			108			—			—			—			—

			Total		942,219			654,884			955,840			753,346			607,601
	Secondary Market Sales				273,369			173,592			145,712			73,505			75,734
	Miscellaneous				5,234			3,552			6,304			3,526			3,135

			Total	$	1,220,822		$	832,028		$	1,107,856		$	830,377		$	686,470

GAS VOLUMES - DEKATHERMS (in thousands):
	System Throughput:
		Residential			52,534			40,047			47,869			40,520			38,111
		Commercial			33,440			25,892			31,002			29,315			26,668
		Industrial			60,048			58,414			54,285			61,144			64,171
		For Power Generation			2,396			1,734			1,169			4,081			6,991
		For Resale			623			41			29			20			29
		EasternNC			11			—			—			—			—

			Total		149,052			126,128			134,354			135,080			135,970

	Secondary Market Sales				45,937			55,679			29,545			21,072			34,792

NUMBER OF RETAIL CUSTOMERS BILLED (12 month average):
	Residential				657,939			620,642			601,682			577,314			549,610
	Commercial				75,917			72,323			71,069			68,879			66,409
	Industrial				2,626			2,589			2,764			2,696			2,758
	For Power Generation				5			3			3			3			3
	For Resale				4			3			3			3			3
	EasternNC				N/A			—			—			—			—

			Total		736,491			695,554			675,521			648,895			618,783

AVERAGE PER RESIDENTIAL CUSTOMER:
	Gas Used - Dekatherms				79.81			64.53			79.56			70.19			69.34
	Revenue			$	797.47		$	576.87		$	873.63		$	594.95		$	536.94
	Revenue Per Dekatherm			$	9.99		$	8.94		$	10.98		$	8.48		$	7.74
COST OF GAS (in thousands):
	Natural Gas Purchased			$	789,918		$	408,564		$	670,380		$	426,329		$	290,501
	Transportation Gas Received (Not Delivered)				200			(157	)		214			(868	)		(1,236	)
	Natural Gas Withdrawn from (Injected into) Storage, net				(38,137	)		9,693			115			(20,144	)		(3,111	)
	Other Storage				(5,932	)		1,927			(983	)		(4,937	)		(4,937	)
	Capacity Demand Charges				89,514			89,103			80,622			94,095			91,661
	Other Adjustments				2,379			(12,896	)		19,530			17,571			(6,916	)

			Total	$	837,942		$	496,234		$	769,878		$	512,046		$	365,962

SUPPLY AVAILABLE FOR DISTRIBUTION - DEKATHERMS (in thousands):
	Natural Gas Purchased				143,716			136,206			121,465			126,228			130,633
	Transportation Gas				52,895			48,179			44,285			31,896			44,322
	Natural Gas Withdrawn from (Injected into) Storage, net				(2,438	)		(1,416	)		1,598			(712	)		(373	)
	Other Storage				(52	)		(45	)		50			(259	)		(2,132	)
	Company Use				(147	)		(139	)		(167	)		(161	)		(154	)

			Total		193,974			182,785			167,231			156,992			172,296

As of October 31, 2003, 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)		645,500
El Paso-Tennessee Pipeline		74,100
Duke-Texas Eastern		1,700
NiSource-Columbia Gas (through arrangements with Transco and Columbia Gulf)		42,800
NiSource-Columbia Gulf		10,000

	Total	774,100

In addition, we had the following 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)		317,200
Piedmont Liquefied Propane Gas		10,500
Williams-Transco Storage		86,100
NiSource-Columbia Gas Storage		96,400
El Paso-Tennessee Pipeline Storage		55,900
Pine Needle LNG		263,400

	Total	829,500

We own or have under contract 30 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.

The gas delivered to meet our design day requirements for firm customers is purchased under firm contractual commitments. 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 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 from the on-shore and off-shore Gulf Coast production region and is purchased primarily from major producers and marketers. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K.

During the year ended October 31, 2003, 36% of our gas deliveries were made 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. The 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 existing regulations of the Federal Energy Regulatory Commission (FERC), 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. To date, 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 faces competition in the residential and commercial customer markets based on the customers’ preferences for natural gas compared with other energy products and the relative prices of those products. The most significant product competition occurs between natural gas and electricity. There are four major electric company competitors within our service areas. We continue to attract the majority of the new residential construction market, and we believe that the consumers’ preference is for natural gas based on such factors as reliability, comfort and convenience compared with electricity in space heating, hot water and cooking. In addition to its many advantages, natural gas has generally maintained a price advantage over electricity in our service areas; however, with the rising demand for natural gas, flat to declining production levels and other public policy issues primarily associated with access to public lands for drilling, upward pressure on the price of natural gas could be more of an issue in the future. Rising prices can impact our competitive position by decreasing the price benefits of natural gas to the end user.

In the interruptible industrial market, the regulated utility’s customers are capable of burning a fuel other than natural gas. Fuel oil is the most significant competing energy alternative. Our ability to maintain our industrial market share is largely dependent on price. The relationship between natural gas supply and demand has the greatest impact on the price of our product. With the reduction in natural gas production occurring from domestic sources, the cost of natural gas from non-domestic sources may play a greater role in our competitive position in the future. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and policies of foreign and domestic governments.

During the year ended October 31, 2003, our largest customer contributed $1.8 million, or .2%, to total operating revenues.

We spend an immaterial amount for research and development costs. We contribute to gas industry-sponsored research projects; however, the amounts contributed to such projects are not material.

Compliance with federal, state and local environmental protection laws has 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, 2003, we had 2,155 employees, compared with 1,715 as of October 31, 2002. The increase is primarily due to the acquisitions of NCNG and an equity interest in EasternNC.

Our filings on Form 10-K, Form 10-Q and Form 8-K are available at no cost on our web site at www.piedmontng.com on the same day the report is filed with the Securities and Exchange Commission.

Item 6. Selected Financial Data

Selected financial data for the years ended October 31, 1999 through 2003, is as follows:


In thousands except per share amounts		2003			2002			2001			2000			1999

Margin (Operating Revenues less Cost of Gas)		$	382,880		$	335,794		$	337,978		$	318,331		$	320,508
Operating Revenues		$	1,220,822		$	832,028		$	1,107,856		$	830,377		$	686,470
Net Income		$	74,362		$	62,217		$	65,485		$	64,031		$	58,207
Earnings per Share of Common Stock:
	Basic	$	2.23		$	1.90		$	2.03		$	2.03		$	1.88
	Diluted	$	2.22		$	1.89		$	2.02		$	2.01		$	1.86
Cash Dividends Per Share of Common Stock		$	1.645		$	1.585		$	1.52		$	1.44		$	1.36
Average Shares of Common Stock:
	Basic		33,391			32,763			32,183			31,600			31,013
	Diluted		33,503			32,937			32,420			31,779			31,242
Total Assets		$	2,296,406		$	1,625,046	*	$	1,554,843	*	$	1,590,287	*	$	1,420,404	*
Long-Term Debt (less current maturities)		$	460,000		$	462,000		$	509,000		$	451,000		$	423,000
Rate of Return on Average Common Equity			12.19	%		10.82	%		12.04	%		12.57	%		12.25	%
Long-Term Debt to Total Capitalization Ratio			42.19	%		43.93	%		47.60	%		46.10	%		46.24	%

* Reflects reclassification of estimated cost of removal of utility plant previously recognized in accumulated depreciation to a separate liability.

Item 8. Financial Statements and Supplementary Data

Consolidated financial statements and schedules required by this item are listed in Item 15 (a) 1 and 2 in Part IV of this Form 10-K on page 69.

Consolidated Balance Sheets
October 31, 2003 and 2002

Assets


In thousands				2003		2002

Utility Plant:
	Utility plant in service			$	2,330,528	$	1,689,743
		Less accumulated depreciation			576,823		392,487

			Utility plant in service, net		1,753,705		1,297,256
	Construction work in progress				58,594		41,225

			Total utility plant, net		1,812,299		1,338,481

Other Physical Property, at cost (net of accumulated depreciation of $1,740 in 2003 and $1,531 in 2002)					1,115		1,078

Current Assets:
	Cash and cash equivalents				11,172		5,100
	Restricted cash				6,749		8,028
	Receivables (less allowance for doubtful accounts of $2,743 in 2003 and $810 in 2002)				58,662		37,504
	Unbilled utility revenues				34,630		—
	Inventories:
		Gas in storage			121,723		65,688
		Materials, supplies and merchandise			4,774		2,860
	Deferred cost of gas				—		13,592
	Refundable income taxes				23,758		10,329
	Prepayments				31,085		19,215
	Other				15,091		13,470

			Total current assets		307,644		175,786

Investments, Deferred Charges and Other Assets:
	Investments in non-utility activities, at equity				96,191		80,342
	Goodwill				50,924		7,109
	Unamortized debt expense (amortized over life of related debt on a straight-line basis)				3,748		3,841
	Other				24,485		18,409

			Total investments, deferred charges and other assets		175,348		109,701

			Total	$	2,296,406	$	1,625,046

See notes to consolidated financial statements.

Capitalization and Liabilities


In thousands				2003			2002

Capitalization:
	Stockholders’ equity:
	Cumulative preferred stock – no par value – 175 shares authorized			$	—		$	—
		Common stock – no par value – 100,000 shares authorized; outstanding, 33,655 in 2003 and 33,090 in 2002			372,651			352,553
		Retained earnings			259,476			240,026
		Accumulated other comprehensive income			(1,932	)		(2,983	)

			Total stockholders’ equity		630,195			589,596
	Long-term debt				460,000			462,000

			Total capitalization		1,090,195			1,051,596

Current Liabilities:
	Current maturities of long-term debt and sinking fund requirements				2,000			47,000
	Notes payable				109,500			46,500
	Commercial paper				445,559			—
	Accounts payable				90,901			51,093
	Income taxes accrued				612			—
	Customers’ deposits				16,408			11,611
	Deferred income taxes				16,949			1,384
	General taxes accrued				19,594			15,094
	Refunds due customers				5,382			15,635
	Other				18,257			16,814

			Total current liabilities		725,162			205,131

Deferred Credits and Other Liabilities:
	Deferred income taxes				188,503			158,275
	Unamortized federal investment tax credits				5,042			5,593
	Asset retirement obligations				245,879			179,958
	Other				41,625			24,493

			Total deferred credits and other liabilities		481,049			368,319

			Total	$	2,296,406		$	1,625,046

See notes to consolidated financial statements.

Consolidated Statements of Income
For the Years Ended October 31, 2003, 2002 and 2001


In thousands except per share amounts			2003			2002			2001

Operating Revenues			$	1,220,822		$	832,028		$	1,107,856
Cost of Gas				837,942			496,234			769,878

Margin				382,880			335,794			337,978

Operating Expenses:
	Operations			131,439			112,421			114,358
	Maintenance			20,668			21,006			19,064
	Depreciation			63,164			57,593			52,060
	General taxes			24,410			23,863			23,952
	Income taxes			40,093			30,784			34,575

		Total operating expenses		279,774			245,667			244,009

Operating Income				103,106			90,127			93,969

Other Income (Expense):
	Non-utility activities, at equity			17,972			19,207			16,271
	Allowance for equity funds used during construction			1,128			1,986			1,767
	Non-operating income			2,560			1,238			1,119
	Non-operating expense			(863	)		(727	)		(927	)
	Income taxes			(8,524	)		(9,010	)		(7,300	)

		Total other income (expense), net of tax		12,273			12,694			10,930

Utility Interest Charges:
	Interest on long-term debt			37,740			39,056			37,789
	Allowance for borrowed funds used during construction			(1,135	)		(1,438	)		(4,910	)
	Other			3,592			2,986			6,535

		Total utility interest charges		40,197			40,604			39,414

Income before Minority Interest in Income of Consolidated Subsidiary				75,182			62,217			65,485
Less Minority Interest in Income of Consolidated Subsidiary				820			—			—

Net Income			$	74,362		$	62,217		$	65,485

Average Shares of Common Stock:
	Basic			33,391			32,763			32,183
	Diluted			33,503			32,937			32,420
Earnings Per Share of Common Stock:
	Basic		$	2.23		$	1.90		$	2.03
	Diluted		$	2.22		$	1.89		$	2.02

See notes to consolidated financial statements.

Consolidated Statements of Cash Flows
For the Years Ended October 31, 2003, 2002 and 2001


In thousands					2003			2002			2001

Cash Flows from Operating Activities:
	Net income				$	74,362		$	62,217		$	65,485

	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization				64,161			58,393			53,069
		Amortization of investment tax credits				(550	)		(556	)		(558	)
		Allowance for funds used during construction				(2,263	)		(3,424	)		(6,677	)
		Undistributed earnings from equity investments				(17,972	)		(19,207	)		(16,271	)
		Changes in assets and liabilities:
			Restricted cash			1,934			(964	)		32,732
			Receivables			(32,151	)		(11,606	)		29,247
			Inventories			(34,547	)		4,614			588
			Other assets			(21,251	)		8,054			47,484
			Accounts payable			10,597			9,949			(47,169	)
			Refunds due customers			2,577			(16,050	)		(1,204	)
			Deferred income taxes			45,792			14,104			(8,193	)
			Other liabilities			8,915			3,402			12,916

				Total adjustments		25,242			46,709			95,964

Net cash provided by operating activities						99,604			108,926			161,449

Cash Flows from Investing Activities:
	Utility construction expenditures					(77,935	)		(80,112	)		(83,536	)
	Capital contributions to equity investments					(2,224	)		(4,492	)		(16,929	)
	Capital distributions from equity investments					10,188			22,143			15,885
	Purchase of gas distribution systems					2,153			(26,000	)		(6,625	)
	Purchase of NCNG and EasternNC, net of cash received of $7,185					(450,168	)		—			—
	Other					(118	)		(112	)		(361	)

Net cash used in investing activities						(518,104	)		(88,573	)		(91,566	)

Cash Flows from Financing Activities:
	Increase (Decrease) in notes payable					63,000			14,500			(67,500	)
	Increase in commercial paper					445,559			—			—
	Proceeds from issuance of long-term debt					—			—			60,000
	Retirement of long-term debt					(47,000	)		(2,000	)		(32,000	)
	Issuance of common stock through dividend reinvestment and employee stock plans					17,925			18,546			15,389
	Dividends paid					(54,912	)		(51,909	)		(48,909	)

Net cash provided by (used in) financing activities						424,572			(20,863	)		(73,020	)

Net Increase (Decrease) in Cash and Cash Equivalents						6,072			(510	)		(3,137	)
Cash and Cash Equivalents at Beginning of Year						5,100			5,610			8,747

Cash and Cash Equivalents at End of Year					$	11,172		$	5,100		$	5,610

Cash Paid During the Year for:
	Interest				$	40,268		$	39,696		$	39,977
	Income taxes				$	30,554		$	34,166		$	51,430
Noncash Investing and Financing Activities Related to Acquisitions of NCNG and EasternNC:
	Fair value/book value of assets acquired				$	511,135
	Cash paid					(457,353	)
	Adjustment of estimated working capital to actual					2,010

	Liabilities assumed				$	55,792

See notes to consolidated financial statements.

Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2003, 2002 and 2001


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

Balance, October 31, 2000			$	314,230	$	213,142		$	—		$	527,372

Comprehensive Income:
	Net Income					65,485						65,485
	Other comprehensive income:
		Cumulative effect of adoption of Statement 133							209
		Unrealized loss of equity investments hedging activities, net of tax of ($777)							(1,438	)
		Reclassification of equity investments hedging activities included in net income, net of tax of ($79)							(148	)		(1,377	)

		Total comprehensive income										64,108
Common Stock Issued				17,808								17,808
Dividends Declared ($1.52 per share)						(48,909	)					(48,909	)

Balance, October 31, 2001				332,038		229,718			(1,377	)		560,379

Comprehensive Income:
	Net income					62,217						62,217
	Other comprehensive income:
		Unrealized loss of equity investments hedging activities, net of tax of ($1,699)							(2,571	)
		Reclassification of equity investments hedging activities included in net income, net of tax of $620							965			(1,606	)

		Total comprehensive income										60,611
Common Stock Issued				20,515								20,515
Dividends Declared ($1.585 per share)						(51,909	)					(51,909	)

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 of equity investments hedging activities, net of tax of ($869)							(1,326	)
		Reclassification of equity investments hedging activities 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 ($1.645 per share)						(54,912	)					(54,912	)

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


In thousands		2003			2002			2001

Reconciliation of Accumulated Other Comprehensive Income:
	Balance, beginning of year	$	(2,983	)	$	(1,377	)	$	—
	Cumulative effect of adoption of Statement 133		—			—			209
	Current year reclassification to net income		2,377			965			(148	)
	Current year change		(1,326	)		(2,571	)		(1,438	)

	Balance, end of year	$	(1,932	)	$	(2,983	)	$	(1,377	)

See notes to consolidated financial statements.

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 the Piedmont and eastern regions of North Carolina, the Piedmont region of South Carolina and the metropolitan Nashville, Tennessee, area. Our subsidiaries are invested in joint venture, energy-related businesses, including unregulated retail natural gas and propane marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. 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 its 50% equity investment in Eastern North Carolina Natural Gas Company (EasternNC). Our equity interest in EasternNC is considered to be a controlling interest and we have consolidated EasternNC for presentation in the accompanying consolidated financial statements. EasternNC is a regulated utility that is engaged in the distribution of natural gas to residential, commercial and industrial customers in eastern North Carolina. For further information on EasternNC, see Note 2 to the consolidated financial statements.

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 “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in “Non-utility activities, at equity” in “Other Income (Expense)” in the consolidated statements of income. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” 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).

Effective at the close of business on September 30, 2003, we purchased North Carolina Natural Gas Corporation (NCNG) and an equity interest in EasternNC. For further information on the acquisitions, see Note 2 to the consolidated financial statements. The transactions were accounted for using the purchase method of accounting for business combinations and considering Statement 71. Accordingly, the accompanying consolidated financial statements include the results of NCNG and EasternNC since September 30, 2003.

B. Rate-Regulated Basis of Accounting.

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, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, 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.

The amounts recorded as regulatory assets and liabilities in the consolidated balance sheets as of October 31, 2003 and 2002, are summarized as follows:


In thousands		2003		2002

Regulatory Assets:
Unamortized debt expense		$	3,748	$	3,841
Environmental costs			5,442		6,153
Demand-side management costs			5,711		6,211
Deferred EasternNC operations and maintenance costs			2,913		—
Deferred NCNG integration costs			3,064		—
Deferred pension and other retirement benefits costs			3,094		542
Other			2,492		2,987

	Total	$	26,464	$	19,734

Regulatory Liabilities:
Asset retirement obligations		$	245,879	$	—
Refunds due customers			5,382		15,635
Deferred taxes			12,601		13,013
Environmental liability due customers			3,471		—

	Total	$	267,333	$	28,648

C. Utility Plant and Depreciation.

Utility plant is stated at original cost, including direct labor and materials, allocable overheads and an allowance for borrowed and equity funds used during construction (AFUDC). For the years ended October 31, 2003, 2002 and 2001, AFUDC totaled $2,263,000, $3,424,000 and $6,677,000, 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 a period of 5 to 72 years. The composite weighted-average depreciation rates were 3.61% for 2003, 3.55% for 2002 and 3.45% for 2001.

Effective November 1, 2002, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143), which addresses accounting and reporting for legal asset retirement obligations associated with the retirement of long-lived assets. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that asset retirement obligations exist for our underground mains and services; however, the fair value of the obligation cannot be determined because the end of the system life is indeterminable.

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. Therefore, we accrue estimated costs of

removal of long-lived assets through depreciation expense. In connection with the adoption of Statement 143, the cost of removal component of accumulated depreciation, that is, the “non-legal” asset retirement obligations, which totaled $245,879,000 as of October 31, 2003, was reclassified to a regulatory liability, and which totaled $179,958, 000 as of October 31, 2002, was reclassified to a separate liability.

D. Goodwill, Equity 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 arise using the present value and invested capital techniques. The present value technique is based on discounted cash flows to estimate fair value. The invested capital technique is based on market multiples of companies that are representative of our peers in the natural gas distribution industry. These calculations are dependent on several subjective factors, including the timing of future cash flows, future growth rates and the discount rate. An impairment charge would be recognized if the carrying value of the reporting unit’s goodwill exceeded its fair value. Through October 31, 2003, no impairment has been recognized.

The following presents the balance in goodwill as of October 31, 2002 and 2003, and the changes for the year ended October 31, 2003. For further information on acquisitions, see Note 2 to the consolidated financial statements.


In thousands

Balance as of October 31, 2001		$	—
Acquisition of NCGS			7,109

Balance as of October 31, 2002			7,109
Acquisition adjustment for NCGS			(2	)
Acquisition of NCNG			42,150
Acquisition of EasternNC			1,139
Minority interest in EasternNC:
	At acquisition		1,348
	Income for the year		(820	)

Balance as of October 31, 2003		$	50,924

We review for impairment our investments in non-utility activities accounted for under the equity method and our long-lived assets whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Our reviews conducted during 2003 did not result in any impairment charges; however, we did write down our investment in propane marketing activities during 2002. For further information on our equity investments, see Note 10 to the consolidated financial statements.

E. Inventories.

We maintain inventories on the basis of average cost. Cost for gas in storage is defined as the amount recoverable under rate schedules approved by the state regulatory commissions.

F. Deferred Purchased Gas Adjustment.

Rate schedules include purchased gas adjustment provisions that permit the recovery of gas costs. We periodically revise rates without formal rate proceedings to reflect changes in the cost of gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are added to or deducted from cost of gas and included in “Refunds due customers” in the consolidated balance sheets.

G. Taxes.

We provide deferred income taxes for differences between the book and tax basis of assets and liabilities, principally attributable to accelerated tax depreciation, equity investments and the timing of the recording of revenues and cost of gas. We amortize deferred investment tax credits to income over the estimated useful life of the related property.

General taxes consist primarily of property taxes, payroll taxes and franchise taxes. Also included to a lesser degree are gross receipts taxes, excise tax on natural gas used by us and a state regulatory fee. Such taxes are not included in revenues and expenses.

H. Operating Revenues.

In the quarter ended January 31, 2003, we performed an analysis of our revenue recognition practices and began recording revenues and cost of gas related to volumes delivered but not yet billed. Recording unbilled revenues changes the timing of revenue recognition from the cycle-billing method to the accrual method which is based on when the service is provided. The effect of the change was to increase net income $5,823,000 and earnings per share $.17 for the year ended October 31, 2003. Prior to 2003, we recognized revenues from meters read on a monthly cycle basis and deferred the cost of gas for volumes delivered but not yet billed.

I. 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, 2003, 2002 and 2001, is presented below:


In thousands except per share amounts		2003		2002		2001

Net Income		$	74,362	$	62,217	$	65,485

Average shares of Common Stock outstanding for basic earnings per share			33,391		32,763		32,183
Contingently issuable shares under the Long-Term Incentive Plan			112		174		237

Average shares of dilutive stock			33,503		32,937		32,420

Earnings Per Share:
	Basic	$	2.23	$	1.90	$	2.03
	Diluted	$	2.22	$	1.89	$	2.02

J. Statement 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.

K. Recently Issued Accounting Standards.

We will adopt FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), in our second quarter ending April 30, 2004. We believe that FIN 46 applies to our equity investments, all of which were acquired prior to February 1, 2003. We have evaluated the impact of FIN 46 on our equity method investments and concluded that we are not the primary beneficiary as we do not absorb a majority of the expected losses nor are we entitled to a majority of the residual returns. Accordingly, we believe the adoption of FIN 46 will not have a material effect on financial position or results of operations.

In December 2003, the FASB issued SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits (Revised)” (Statement 132). Statement 132 requires additional disclosures about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. We will adopt Statement 132 in our second quarter beginning February 1, 2004. We believe the adoption of Statement 132 will not have a material effect on financial position or results of operations.

L. 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 at 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.

M. Reclassifications.

We have reclassified certain financial statement items for 2002 and 2001 to conform with the 2003 presentation.

2. Acquisitions

Effective at the close of business on September 30, 2003, we purchased for $417,500,000 in cash 100% of the common stock of NCNG from Progress Energy, Inc. (Progress). NCNG, a natural gas distributor, served approximately 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. The purchase price for the NCNG common stock was increased by the amount of NCNG’s working capital on the closing date. Based on a preliminary working capital schedule, the closing date working capital was $32,353,000. The preliminary working capital amount will be adjusted to actual under the terms of the purchase agreement in 2004. NCNG was merged into Piedmont immediately following the closing.

We also purchased for $7,500,000 in cash Progress’ equity interest in EasternNC. EasternNC is a regulated utility that has 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 are obligated to purchase additional authorized but unissued shares of such preferred stock for $14,400,000.

We funded the purchases with short-term debt of $445,266,000 under a commercial paper program which is discussed in Note 6. On December 19, 2003, we sold $200,000,000 of medium-term notes and redeemed a portion of the outstanding commercial paper with the net proceeds.

We recorded the assets purchased 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. Goodwill of $42,150,000 for NCNG and $1,139,000 for EasternNC was recorded in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement 142), and will be subject to impairment analysis in future periods. Substantially all of the goodwill is expected to be deductible for tax purposes. All goodwill was assigned to the utility segment.

The following table summarizes the preliminary purchase price allocation of assets acquired and liabilities assumed as of September 30, 2003.


In thousands		NCNG			EasternNC			Total

Utility plant, net		$	381,567		$	8,952		$	390,519
Investments, at equity			5,450			—			5,450
Current assets			60,203			7,723			67,926
Goodwill			42,150			1,139			43,289
Minority interest			—			1,348			1,348
Non-current assets			2,603			—			2,603

	Total assets acquired		491,973			19,162			511,135
Current liabilities			(32,879	)		(11,646	)		(44,525	)
Non-current liabilities			(11,251	)		(16	)		(11,267	)

	Net assets acquired	$	447,843		$	7,500		$	455,343

We are in the process of evaluating and measuring certain assets acquired and liabilities assumed in the acquisition, primarily working capital. The allocation of the purchase price is subject to refinement according to terms specified in the stock purchase agreement and will be completed in 2004.

The primary reasons for these acquisitions are consistent with our strategy of pursuing profitable growth in our core natural gas distribution business in the Southeast. The reasons for the acquisitions and the factors that contributed to the goodwill include:

• A reasonable purchase price slightly above book value,

• The prospect of entering a market contiguous to our existing North Carolina service areas where, as a combined company, we could realize on-going system benefits,

• The prospect of acquiring an operation that could be integrated into our existing business systems and processes, and

• The opportunity to grow within a regulatory environment with which we are familiar.

Our consolidated results of operations for 2003 include the operations of NCNG and EasternNC since September 30, 2003. The following information for the years ended October 31, 2003 and 2002, is provided on an unaudited pro forma basis, assuming the acquisitions and the related permanent financing had occurred as of November 1, 2001:


In thousands, except per share amounts	2003		2002

Operating revenues	$	1,581,849	$	1,145,958
Income from continuing operations		76,808		67,967
Net income		76,808		67,967
Earnings per share	$	2.03	$	1.82

This unaudited pro forma information is not necessarily indicative of the results of operations had the acquisitions actually occurred at the beginning of our fiscal year 2002, nor is it indicative of future results.

Effective September 30, 2002, we purchased for $26,000,000 in cash substantially all of the natural gas distribution assets and certain of the liabilities of North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc. The initial purchase price was reduced by $2,153,000 in 2003 due to adjusting estimated working capital to actual. Final determination of the purchase

price allocation resulted in goodwill of $7,107,000. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina.

Effective January 1, 2001, we purchased for cash the natural gas distribution assets of Atmos Energy Corporation located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition was at book value of $6,625,000 and added 5,400 customers to our operations.

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 the state. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. In accordance with an NCUC order in 2002, we no longer deposit such refunds in the expansion fund. As of October 31, 2003, the balance of $6,094,000 in our expansion fund held by the state is included in “Restricted cash” with an offsetting liability included in “Refunds due customers” in the consolidated balance sheets.

In 2002, the PSCSC approved a gas cost hedging plan for the purpose of cost stabilization for customers. This plan is limited to 60% of our annual normalized sales volumes for South Carolina and operates off of 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, except for certain personnel and administrative costs that are recovered in rates as operations and maintenance expenses, are deemed to be prudently incurred and are recovered in rates as a gas cost. We began hedging activities in April 2002 under the approved program.

Effective November 1, 2002, we implemented a hedging program in North Carolina under the terms of a generic order issued by the NCUC on February 26, 2002, as later clarified by a Piedmont-specific order dated October 18. This plan is limited to 60% of the annual normalized sales volumes for North Carolina and operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange. We believe the plan is designed with limited subjective discretion in making purchases with little or no risk of speculation in the market. Prudently incurred gas costs associated with the hedging program are not pre-approved by the NCUC but are treated as gas costs subject to the annual gas cost prudency review based on information available at the time of the hedge, not at the time of the prudency review. Through October 31, 2003, we have recovered 100% of gas costs subject to prudency review.

On October 28, 2002, the NCUC issued an order approving an annual revenue increase of $13,889,000, effective November 1, 2002. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

On October 29, 2002, the PSCSC issued an order approving an annual revenue increase of $8,381,000, effective November 1, 2002. This order also approved new depreciation rates and changes in cost allocations and rate design and changes in tariffs and service regulations.

On March 31, 2003, NCNG filed an application with the NCUC requesting an increase in rates and charges along with changes in cost allocations and rate design and changes in tariffs and service regulations. On September 2, a settlement agreement supported by all parties in the proceeding was filed with the NCUC. The agreement provided for, among other things, an annual increase in NCNG’s regulatory margin of $29,444,000. The NCUC issued an order in accordance with the agreement on October 30, effective November 1, 2003.

On April 29, 2003, we filed an application with the TRA requesting an annual increase in revenues along with changes in cost allocations and rate design and changes in tariffs and service regulations. On September 9, a settlement agreement with the Tennessee Consumer Advocate was filed with the TRA that, among other things, increased revenues by $10,300,000 annually. On September 22, the TRA approved the settlement agreement and authorized increased rates, effective November 1, 2003.

On October 27, 2003, we filed a joint motion for clarification of the right of EasternNC to defer and collect its operations and maintenance expenses under prior NCUC orders. As part of EasternNC’s certificate authorization, the NCUC recognized that EasternNC would not have a sufficient customer base from which to immediately collect its operations and maintenance expenses. The NCUC allowed EasternNC to defer its operations and maintenance expenses for up to eight years or until the first rate case order. The NCUC set the cap on deferred expenses at $15,000,000. 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. Operations and maintenance costs totaling $2,913,000, including those expensed prior to September 30, 2003, have been deferred as a regulatory asset.

4. Long-Term Debt

All of our long-term debt is unsecured. Long-term debt as of October 31, 2003 and 2002, is summarized as follows:


In thousands			2003		2002

Senior Notes:
	10.06%, due 2004		$	2,000	$	4,000
	9.44%, due 2006			35,000		35,000
	8.51%, due 2017			35,000		35,000
Medium-Term Notes:
	6.23%, due 2003			—		45,000
	7.35%, due 2009			30,000		30,000
	7.80%, due 2010			60,000		60,000
	6.55%, due 2011			60,000		60,000
	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

		Total		462,000		509,000
Less current maturities				2,000		47,000

		Total	$	460,000	$	462,000

Annual sinking fund requirements and maturities over the next five years are $2,000,000 in 2004, zero in 2005, $35,000,000 in 2006 and zero in 2007 and 2008.

On December 19, 2003, we sold $100,000,000 of 5% and $100,000,000 of 6% medium-term notes available under a shelf registration filed with the Securities and Exchange Commission. The 5% note due 2013 and the 6% note due 2033 are each to be redeemed in a single payment at maturity.

The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in our 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, 2003, net earnings available for restricted payments were $352,389,000. Retained earnings as of this date were $259,476,000; therefore, none of our retained earnings were restricted.

We are subject to default provisions related to our long-term debt. 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 on the part of Piedmont 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 results in total outstanding issues of debt becoming due. There are cross default provisions in all debt agreements. Based upon our calculations, we met the default provisions as of October 31, 2003.

5. Capital Stock

Changes in Common Stock for the years ended October 31, 2001, 2002 and 2003, are summarized as follows:


In thousands		Shares		Amount

Balance, October 31, 2000			31,914	$	314,230
	Issued to participants in the Employee Stock Purchase Plan (ESPP)		16		476
	Issued to the Dividend Reinvestment and Stock Purchase Plan (DRIP)		461		14,913
	Issued to participants in the Long-Term Incentive Plan (LTIP)		72		2,419

Balance, October 31, 2001			32,463		332,038
	Issued to ESPP		16		507
	Issued to DRIP		546		18,039
	Issued to LTIP		65		1,969

Balance, October 31, 2002			33,090		352,553
	Issued to ESPP		17		550
	Issued to DRIP		484		17,375
	Issued to LTIP		64		2,173

Balance, October 31, 2003			33,655	$	372,651

As of October 31, 2003, 2,910,000 shares of Common Stock were reserved for issuance as follows:


ESPP		132,000
DRIP		2,089,000
LTIP		689,000

	Total	2,910,000

6. Financial Instruments and Related Fair Value

Various banks provide lines of credit totaling $200,000,000 on a fee basis to finance current cash requirements. We have additional uncommitted lines of credit totaling $68,000,000 on a no fee and as needed, if available, basis. 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.

In addition to these bank lines of credit, we also have a commercial paper program. This program was put in place to provide for the temporary financing of our acquisitions of NCNG and the equity interest in EasternNC. We can issue up to $450,000,000 in unsecured promissory notes that are backed by a $450,000,000 credit agreement expiring June 22, 2004. The notes issued under this program on September 29, 2003, were sold at a discount from face values at LIBOR cost-plus rates with maturities ranging from 1 to 30 days. On December 19, 2003, we sold $200,000,000 of long-term debt. The net proceeds of $198,334,000 were used to redeem commercial paper. For further information on long-term debt, see Note 4 to the consolidated financial statements.

As of October 31, 2003, outstanding borrowings under the lines of credit are included in “Notes payable” in the consolidated balance sheets and consisted of $109,500,000 in LIBOR cost-plus loans at a weighted average interest rate of 1.58%. As of October 31, 2003, outstanding borrowings under the commercial paper program were $445,559,000 at a weighted average interest rate of 1.16%.

Our principal business activity is the distribution of natural gas. As of October 31, 2003, gas receivables were $51,227,000 and other receivables were $7,435,000, net of an allowance for doubtful accounts of $2,743,000. We believe that we have provided an adequate allowance for

any receivables which may not be ultimately collected.

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, 2003 and 2002, including current portion, were as follows:


	2003				2002

In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Long-term debt	$	462,000	$	506,882	$	509,000	$	589,503

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. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

During the year ended October 31, 2003, we purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of October 31, 2003, we had forward positions for December 2003 through March 2004. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing transportation and capacity in the secondary market and margin from secondary market sales of gas, are subject to an overall annual cap of $1,600,000 for shareholder gains or losses. The net gains or losses on gas costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders, subject to the annual cap. The net overall annual performance results are collected from or refunded to customers, subject to the cap.

During the year ended October 31, 2003, we purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of October 31, 2003, we had forward positions for December 2003 through March 2004. The costs of these options are pre-approved by the PSCSC for recovery from customers subject to our following the provisions of the gas cost hedging plan. The hedging program uses a matrix of historic, inflation-adjusted gas prices over the past four years plus the current season, with a heavier weighting on current data, as the basis for determining the purchase of financial instruments. The hedging portfolio is diversified over a rolling 24 months with a short-term focus (one to 12 months) and a long-term focus (13 to 24 months). Hedges are executed within the parameters of the matrix compared

with NYMEX monthly prices as reviewed on a daily basis. We believe the plan is very structured in composition and designed to limit subjective discretion in making hedging decisions.

During the year ended October 31, 2003, we purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of October 31, 2003, we had forward positions for December 2003 through March 2004. The operation of the hedging program is identical to that of the South Carolina hedging program.

There is no income statement impact of the North Carolina and South Carolina programs as all costs and related gain or loss amounts are passed through to customers under regulatory gas cost recovery mechanisms and are recorded in “Refunds due customers,” a regulatory liability. We mark the derivative instruments to market under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), with a corresponding entry to “Refunds due customers.” As of October 31, 2003, the amount in “Refunds due customers” is net of $6,300,000 due from customers for the costs of the North Carolina and South Carolina hedging programs and the related mark-to-market adjustments.

7. Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable capital and operating leases. EasternNC leases one of its primary real properties under a noncancelable operating lease that expires in July 2007, and EasternNC has capital leases for equipment.

For the years ended October 31, 2003, 2002 and 2001, operating lease rentals totaled $4,543,000, $4,520,000 and $4,400,000, respectively.

Future minimum lease obligations, excluding taxes and other expenses, for leases in effect as of October 31, 2003, are payable as follows:


	Capital		Operating
In thousands	Leases		Leases

2004	$	14	$	4,786
2005		—		4,024
2006		—		2,775
2007		—		1,797
2008		—		1,122
Thereafter		—		2,519

Total minimum obligations		14	$	17,023

Less amount representing interest		—

Present value of net minimum obligations		14
Less current portion		14

Long-term portion	$	—

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. Plan assets consist primarily of marketable securities and cash equivalents. We amend the plan from time to time in accordance with changes in tax law.

We provide certain postretirement health care and life insurance benefits to eligible full-time employees. 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. The liability associated with such benefits is funded in irrevocable trust funds that can only be used to pay the benefits.

In connection with the acquisition of NCNG discussed in Note 2 to the consolidated financial statements, we acquired pension and other postretirement benefit obligations (OPEB) related to former employees of NCNG. Cash equal to the liability for the pension benefits, estimated to be $34,481,000 as of October 31, 2003, will be transferred from Progress in 2004 and is expected to be maintained in a separate “frozen” plan for the next several years. The transferred active pension plan participants began accruing benefits under the Piedmont pension plan as of October 1, 2003. As of October 31, 2003, the estimated OPEB obligation of $9,718,000 for former employees of NCNG is included in “Other” in “Deferred Credits and Other Liabilities” in the consolidated balance sheets. There are no assets attributable to this liability to be transferred from Progress.

A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended October 31, 2003 and 2002, and a statement of the funded status as recorded in the consolidated balance sheets as of October 31, 2003 and 2002, are presented below:


		2003			2002			2003			2002

In thousands		Pension Benefits						Other Benefits

Change in benefit obligation:
Obligation at beginning of year		$	149,693		$	148,011		$	25,632		$	24,987
Obligation of NCNG at date of acquisition			—			—			9,718			—
Service cost			6,060			5,456			808			542
Interest cost			10,114			9,729			2,128			1,696
Plan amendments			—			2,474			5,894			—
Actuarial (gain) loss			7,544			(9,031	)		1,844			524
Benefit payments			(8,160	)		(6,946	)		(2,344	)		(2,117	)
Recognized liabilities of the NCNG plan			34,481			—			—			—

	Obligation at end of year	$	199,732		$	149,693		$	43,680		$	25,632

Change in fair value of plan assets:
Fair value of plan assets at beginning of year		$	125,056		$	135,981		$	11,311		$	11,210
Actual return (loss) on plan assets			11,765			(3,979	)		379			88
Employer contributions			979			—			2,590			1,721
Administrative expenses			(290	)		—			—			—
Recognized assets of the NCNG Plan			34,481			—			—			—
Benefit payments			(8,160	)		(6,946	)		(1,841	)		(1,708	)

Fair value of plan assets at end of year		$	163,831		$	125,056		$	12,439		$	11,311

Funded status:
Funded status at end of year		$	(35,901	)	$	(24,637	)	$	(31,241	)	$	(14,321	)
Unrecognized transition obligation			—			13			8,791			9,670
Unrecognized prior-service cost			7,160			8,092			5,035			—
Unrecognized actuarial gain (loss)			20,853			10,570			6,275			4,192

	Accrued benefit liability	$	(7,888	)	$	(5,962	)	$	(11,140	)	$	(459	)

Net periodic benefit cost for the years ended October 31, 2003, 2002 and 2001, includes the following components:


	2003			2002			2001			2003			2002			2001

In thousands	Pension Benefits									Other Benefits

Service cost	$	6,060		$	5,456		$	4,890		$	808		$	542		$	573
Interest cost		10,114			9,729			9,278			2,128			1,696			1,636
Expected return On plan assets		(13,375	)		(14,976	)		(14,359	)		(817	)		(913	)		(839	)
Amortization of Transition obligation		14			14			14			879			879			879
Amortization of prior-service cost		931			903			762			859			—			—
Amortization of actuarial (gain) loss		(840	)		(872	)		(1,781	)		198			46			—

Net periodic benefit cost	$	2,904		$	254		$	(1,196	)	$	4,055		$	2,250		$	2,249

In determining the market-related value of plan assets, we use the following methodology. Each year, the asset gain or loss is determined by comparing the fund’s actual return to the expected return, based on the disclosed expected return on investment assumption. Each year’s asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related value of assets as of the balance sheet date 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. The discount rate

can vary from plan year to plan year. October 31 is the measurement date for the plans. The benchmark consistently used in determining the discount rate is Moody’s AA bond index (adjusted to be an equivalent annual rate), plus no more than 25 basis points. As of October 31, 2003, the benchmark was 6.20%.

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 of 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, 2003, 2002 and 2001, are presented below:


	2003			2002			2001			2003			2002			2001

	Pension Benefits									Other Benefits

Discount rate		6.25	%		7.00	%		6.75	%		6.25	%		7.00	%		7.00	%
Expected long-term rate of return on plan assets		8.50	%		9.50	%		9.50	%		8.50	%		9.50	%		9.25	%
Rate of compensation increase		3.97	%		3.97	%		4.75	%		3.97	%		3.97	%		4.50	%

The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation for the medical plans for participants aged less than 65 are 10% for 2003, declining gradually to 5% in 2010 and remaining at that level thereafter. For those participants aged greater than 65, the assumed health care cost trend rates are 13% for 2003, declining gradually to 5% in 2012 and remaining at that level thereafter. The health care cost trend rate assumptions have a significant effect on the amounts reported. A change of 1% in the assumed health care cost trend rates 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, 2003	$	123	$	(114	)
Effect on the health care component of the accumulated postretirement benefit obligation as of October 31, 2003	$	1,985	$	(1,713	)

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). Employees who have completed six months of service are eligible to participate. Participants may defer a portion of their base salary to the plans and we match a portion of their contributions. For the years ended October 31, 2003, 2002 and 2001, our matching contributions totaled $2,315,000, $2,244,000 and $2,189,000, respectively. All contributions vest immediately. There are numerous 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.

9. Income Taxes

The components of income tax expense for the years ended October 31, 2003, 2002 and 2001, are as follows:


				2003						2002					2001

In thousands				Federal			State			Federal			State		Federal			State

Income taxes charged To operations:
	Current			$	(4,581	)	$	(959	)	$	15,482		$	4,410	$	23,959		$	4,558
	Deferred				38,252			7,931			10,711			737		4,933			1,683
	Amortization of investment tax credits				(550	)		—			(556	)		—		(558	)		—

		Total			33,121			6,972			25,637			5,147		28,334			6,241

Income taxes charged To other income:
	Current				7,685			1,561			5,424			952		4,685			1,036
	Deferred				(623	)		(99	)		2,174			460		1,299			280

		Total			7,062			1,462			7,598			1,412		5,984			1,316

			Total income tax expense	$	40,183		$	8,434		$	33,235		$	6,559	$	34,318		$	7,557

A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2003, 2002 and 2001, is as follows:


In thousands		2003			2002			2001

Federal taxes at 35%		$	43,043		$	35,704		$	37,576
State income taxes, net of federal benefit			5,482			4,263			4,912
Amortization of investment tax credits			(550	)		(556	)		(558	)
Other, net			642			383			(55	)

	Total income tax expense	$	48,617		$	39,794		$	41,875

As of October 31, 2003 and 2002, deferred income taxes consisted of the following temporary differences:


In thousands		2003			2002

Utility plant		$	178,133		$	151,584
Equity investments			17,369			16,648
Revenues and cost of gas			25,035			5,172
Other, net			(15,085	)		(13,745	)

	Net deferred income taxes	$	205,452		$	159,659

As of October 31, 2003 and 2002, total deferred income tax liabilities were $217,476,000 and $169,918,000 and total deferred income tax assets were $12,024,000 and $10,259,000, respectively.

We are currently under audit by the Internal Revenue Service for the year ended October 31, 2001. We are not aware of any potential tax issues that would materially affect financial position. Although the ultimate outcome of the audit and the final impact cannot be predicted with certainty, we believe that the resolution of the audit will not have a material adverse effect on financial position.

10. Equity 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. Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary of Piedmont Natural Gas Company. Another wholly owned subsidiary of Piedmont Natural Gas Company, Piedmont Energy Partners, Inc., is a holding company for certain other wholly owned subsidiaries. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Propane Company and Piedmont Energy Company. Our ownership interest in each entity is recorded in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in “Non-utility activities, at equity” in “Other Income (Expense)” in the consolidated statements of income.

As of October 31, 2003, the amount of our retained earnings that represents undistributed earnings of 50% or less owned entities accounted for by the equity method was $23,056,000.

Piedmont Intrastate Pipeline Company

Piedmont Intrastate Pipeline Company owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. With the acquisition of NCNG, we acquired an additional 5.03% interest in Cardinal over our previous interest of 16.45%. 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, including Piedmont, for 100% of the firm transportation capacity on the pipeline. 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 with Cardinal as a transportation customer. We record in cost of gas the transportation costs charged by Cardinal. For the years ended October 31, 2003, 2002 and 2001, these gas costs were $1,713,000, $1,475,000 and $1,475,000, respectively. As of October 31, 2003 and 2002, we owed Cardinal $394,000 and $123,000, respectively.

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal as of and for the twelve months ended September 30, 2003, 2002 and 2001, is presented below.


In thousands	2003		2002		2001

Current assets	$	9,218	$	11,339	$	7,988
Non-current assets		93,333		95,256		97,897
Current liabilities		4,054		5,416		3,187
Non-current liabilities		41,280		43,200		45,120
Revenues		16,880		17,124		17,124
Gross profit		16,880		17,124		17,124
Income before income taxes		9,211		9,401		10,005

Piedmont Interstate Pipeline Company

Piedmont Interstate Pipeline Company owns 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. With the acquisition of NCNG, we acquired an additional 5.0587% interest in Pine Needle over our previous interest of 35%. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Amerada Hess Corporation, and the Municipal Gas Authority of Georgia. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Storage capacity of the facility is fully subscribed under firm service agreements with customers. We subscribe to approximately 64% of this capacity to provide gas for peak-use periods when demand is the highest. Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133. 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 with Pine Needle as a customer. We record in cost of gas the storage costs charged by Pine Needle. For the years ended October 31, 2003, 2002 and 2001, these gas costs were $10,649,000, $10,898,000 and $11,266,000, respectively. As of October 31, 2003 and 2002, we owed Pine Needle $1,033,000 and $895,000, respectively.

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle as of and for the twelve months ended September 30, 2003, 2002 and 2001, is presented below.


In thousands	2003		2002		2001

Current assets	$	11,931	$	12,662	$	10,494
Non-current assets		97,425		98,309		101,060
Current liabilities		9,088		6,495		3,375
Non-current liabilities		50,759		55,856		55,908
Revenues		20,013		20,253		20,271
Gross profit		20,013		20,253		20,271
Income before income taxes		9,320		10,357		10,916

Piedmont Propane Company

Piedmont Propane Company owns 20.69% of the membership interests in US Propane, L.P. The other members are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns 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. Heritage Propane utilizes hedging transactions to provide protection against significant fluctuations in prices. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under Statement 133 and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). Heritage Propane also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments utilized in connection with the liquids marketing activity are accounted for using the mark-to-market method of accounting.

In July 2002, we recorded a pre-tax loss in value of $1,366,000 on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane. This other than temporary loss was calculated based on estimated future cash flow projections that reflect actual and projected customer growth assumptions for Heritage Propane.

The limited partnership agreement of US Propane requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $10,000,000. As of October 31, 2003, our capital account was positive.

On November 7, 2003, we, along with the other members of US Propane, entered into an agreement to sell the general and limited partnership interests in Heritage Propane to a third party for $130,000,000. Our share of the sales proceeds is expected to be $26,897,000. In connection with the sale, US Propane will retain approximately 180,000 common units of Heritage Propane for ultimate distribution to US Propane’s members. Subject to regulatory approvals and financing conditions, closing is expected to occur in January 2004. See subsequent events update in Note 13 to the consolidated financial statements in Item 8.

Summarized audited financial information for Heritage Propane for 100% of Heritage Propane as of and for its fiscal years ended August 31, 2003, 2002 and 2001, is presented below.


In thousands	2003		2002		2001

Current assets	$	94,138	$	95,387	$	138,263
Non-current assets		644,701		621,877		619,904
Current liabilities		151,027		122,069		127,655
Non-current liabilities		360,762		420,021		423,748
Minority interest		4,002		3,564		5,350
Revenues		571,476		462,325		543,975
Gross profit		274,320		224,140		237,419
Income before income taxes		32,165		4,902		19,710

Piedmont Energy Company

Piedmont Energy Company owns 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. The remaining non-controlling 70% interest is owned by a subsidiary of AGL Resources, Inc. Key governance provisions in the LLC agreement require unanimous approval of the members. 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.

The Operating Policy of SouthStar contains a provision for the disproportionate sharing of earnings in excess of a threshold per annum, cumulative pre-tax return of 17%. This threshold is not reached until all prior period losses are recovered. Earnings below the 17% return threshold are allocated to members based on their ownership percentages. Earnings above the threshold are allocated at various percentages based on actual margin generated in four defined geographic service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of October 31, 2003 and 2002, we recognized as equity earnings only the amounts that we believe have been earned as the calculation methodologies and interpretations of the Operating Policy that impact the members’ disproportionate earnings sharing percentages had not been

agreed to by the members. Accordingly, we recorded pre-tax earnings from SouthStar for the years ended October 31, 2003 and 2002, at overall percentages of 20% and 24%, respectively.

On December 31, 2003, we entered into an agreement in principle with the other member of SouthStar that addressed a number of matters under the LLC Agreement and the Operating Policy, including the resolution of certain disproportionate sharing issues. Based on this agreement in principle and consistent with the understandings reached by the members that are yet to be documented, we estimate that we will record an increase in pre-tax earnings from SouthStar of $2,491,000 in the first quarter of our fiscal year 2004.

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. Those derivative transactions that qualify as cash flow hedges are reflected in SouthStar’s balance sheet at the fair values of the open positions, with the corresponding unrealized gain or loss included in “Accumulated other comprehensive income” under Statement 133 and Statement 149. Those derivative transactions that are not designated as hedges are reflected in SouthStar’s balance sheet with the corresponding unrealized gain or loss included in cost of sales in SouthStar’s income statement. 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. These contracts are accounted for using the intrinsic value method under the guidelines of Emerging Issues Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”

Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s fees for local delivery service. Piedmont Energy Company, through its parent Piedmont Energy Partners, has guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $15,000,000 that expires on July 30, 2004. On November 25, 2003, Piedmont Energy Company increased its guarantee with an additional letter of credit of $3,108,000 that expires on August 4, 2004.

We have related party transactions with SouthStar which purchases wholesale gas supplies from us. For the years ended October 31, 2003, 2002 and 2001, such operating revenues totaled $898,000, $10,744,000 and $12,192,000, respectively. As of October 31, 2003 and 2002, SouthStar owed us $1,000 and $1,162,000, respectively.

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar as of and for the twelve months ended September 30, 2003, 2002 and 2001, is presented below.


In thousands	2003		2002		2001

Current assets	$	168,302	$	134,113	$	140,125
Non-current assets		1,099		1,228		2,688
Current liabilities		48,568		61,990		33,891
Non-current liabilities		—		—		35,464
Revenues		727,871		606,191		817,687
Gross profit		99,618		124,315		117,306
Income before income taxes		55,805		54,308		23,708

Piedmont Greenbrier Pipeline Company

As of October 31, 2003, Piedmont Greenbrier Pipeline Company, LLC, owned 33% of the membership interests in Greenbrier Pipeline Company, LLC (Greenbrier). The other member was a subsidiary of Dominion Resources, Inc. Greenbrier was formed to build an interstate gas pipeline from West Virginia to North Carolina. On November 6, 2003, we sold our interest in Greenbrier to Dominion Resources for our book value of $9,199,000.

Summarized unaudited financial information provided to us by Greenbrier for 100% of Greenbrier as of and for the twelve months ended September 30, 2003, 2002 and 2001, is presented below.


In thousands	2003		2002		2001

Current assets	$	305	$	2,501	$	2,343
Non-current assets		27,702		18,684		—
Current liabilities		130		380		—
Non-current liabilities		—		—		—
Revenues		2		—		—
Gross profit		2		—		—
Income before income taxes		380		317		—

11. Business Segments

Due to organizational changes, largely resulting from the acquisitions of NCNG and the equity interest in EasternNC, we redefined our reportable business segments effective October 1, 2003. Based on products and services, regulatory environments and our current corporate organization and business decision-making activities, we have two reportable business segments, regulated utility and non-utility activities. Operations of our regulated utility segment are conducted by the parent company and by EasternNC. Operations of our non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Energy Company, Piedmont Propane Company and Piedmont Greenbrier Pipeline Company. We have restated all prior periods presented to reflect the change in reportable segments.

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 “Other Income (Expense)” in the consolidated statements of income in either “Non-utility activities, at equity” or “Non-operating income.”

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 income from non-utility activities, at equity, and investment in non-utility activities, at equity. All of our operations are within the United States. No single customer’s revenues to us exceed 10% of our consolidated revenues.

Operations by segment for the years ended October 31, 2003, 2002 and 2001, are presented below:


	Regulated		Non-Utility
In thousands	Utility		Activities			Total

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
Operating income		143,199		(132	)		143,067
Income before income taxes and minority interest		106,150		17,649			123,799
Total assets		2,214,566		112,690			2,327,256
Income from non-utility activities, at equity		—		17,972			17,972
Investments in non-utility activities, at equity		—		96,191			96,191
Construction expenditures		80,405		—			80,405
2002
Revenues from external customers	$	832,028	$	—		$	832,028
Margin		335,794		—			335,794
Operations and maintenance expenses		133,427		348			133,775
Depreciation		57,593		—			57,593
Operating income		120,911		(465	)		120,446
Income before income taxes and minority interest		83,525		18,486			102,011
Total assets		1,577,858		95,302			1,673,160
Income from non-utility activities, at equity		—		19,207			19,207
Investments in non-utility activities, at equity		—		80,342			80,342
Construction expenditures		83,831		—			83,831
2001
Revenues from external customers	$	1,107,856	$	—		$	1,107,856
Margin		337,978		(264	)		337,714
Operations and maintenance expenses		133,422		314			133,736
Depreciation		52,060		5			52,065
Operating income		128,544		(547	)		127,997
Income before income taxes and minority interest		92,038		15,322			107,360
Total assets		1,514,337		83,567			1,597,904
Income from non-utility activities, at equity		—		16,271			16,271
Investments in non-utility activities, at equity		—		82,287			82,287
Construction expenditures		90,573		—			90,573

A reconciliation to the consolidated financial statements for the years ended October 31, 2003, 2002 and 2001, is presented below:


In thousands			2003			2002			2001

Operating Income:
	Segment operating income		$	143,067		$	120,446		$	127,997
	Utility income taxes			(40,093	)		(30,784	)		(34,575	)
	Non-utility activities			132			465			547

		Operating income	$	103,106		$	90,127		$	93,969

Net Income:
	Income before income taxes and minority interest for reportable segments		$	123,799		$	102,011		$	107,360
	Income taxes			48,617			39,794			41,875
	Minority interest			820			—			—

		Net income	$	74,362		$	62,217		$	65,485

Consolidated Assets:
	Total assets for reportable segments		$	2,327,256		$	1,673,160		$	1,597,904
	Eliminations/Adjustments			(30,850	)		(48,114	)		(43,061	)

		Consolidated assets	$	2,296,406		$	1,625,046		$	1,554,843

12. Environmental Matters

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

In 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount 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 2002, in connection with the acquisition of certain assets and liabilities of NCGS discussed in Note 2 to the consolidated financial statements, we acquired the liability for an MGP site located in Reidsville, North Carolina. Based on a limited assessment performed by a third party on this site and its similarity to the three sites not covered by the settlement noted above, we increased our environmental liability in the fourth quarter of 2002 by $1,508,000, with an offsetting increase to a regulatory asset, to reflect a liability of $637,000 for each of the four sites.

As of October 31, 2003, our undiscounted environmental liability totaled $2,868,000, consisting of $2,548,000 for the four MGP sites and $320,000 for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries.

As of October 31, 2003, our regulatory assets for environmental costs totaled $5,442,000, net of recoveries from customers, in connection with the estimated liabilities for the MGP sites and underground storage tanks and for environmental costs incurred, primarily legal fees and engineering assessments. The portion of the regulatory assets representing actual costs incurred is being amortized as recovered in rates from customers in all three states.

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 financial position or results of operations.

In connection with the NCNG general rate case proceeding discussed in Note 3 to the consolidated financial statements, the NCUC ordered an environmental regulatory liability of $3,471,000 be established for refund to customers over the three-year period beginning November 1, 2003. This liability was derived from deducting deferred MGP costs from a prior payment made to NCNG by its insurers.

13. Subsequent Events (Unaudited)

On January 20, 2004, we, along with the other members of US Propane, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane. Our share of the proceeds was $26,897,000.

On January 23,2004, we sold 4,250,000 shares of Common Stock at a public offering price of $42.50 per share. The proceeds of $174,293,000, net of underwriting discount, were used to repay a portion of our outstanding commercial paper.

14. Reclassification of Asset Retirement Obligations

In accordance with guidance that became available in February 2004, we have reclassified the estimated cost of removal of utility plant previously recognized in accumulated depreciation as a separate liability for the year ended October 31, 2002. As a result of the adoption of Statement 143 on November 1, 2002, these liabilities are reported as regulatory liabilities in 2003.

The following table shows how “Total utility plant, net” and “Total deferred credits and other liabilities” in the consolidated balance sheet as of October 31, 2002, have been revised.


In thousands
Total utility plant, net – as reported	$	1,158,523
Total utility plant, net reclassification		179,958

Total utility plant, net – as revised	$	1,338,481

Total deferred credits and other liabilities – as reported	$	188,361
Total deferred credits and other liabilities reclassification		179,958

Total deferred credits and other liabilities – as revised	$	368,319

This reclassification had no impact on our reported financial results of operations.

Management’s Responsibility For Financial Reporting

The management of Piedmont Natural Gas Company is responsible for the preparation and integrity of the accompanying consolidated financial statements and related notes. We prepared the statements in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and included amounts which are necessarily based on our best estimates and judgments made with due consideration to materiality. Financial information presented elsewhere in this report is consistent with that in the consolidated financial statements.

We have established and are responsible for maintaining a comprehensive system of internal accounting controls which we believe provides reasonable assurance that policies and procedures are complied with, assets are safeguarded and transactions are executed according to management’s authorization. We continually review this system for effectiveness and modify it in response to changing business conditions and operations and as a result of recommendations by internal and external auditors.

The Audit Committee of the Board of Directors, consisting solely of independent Directors, meets at least quarterly with Deloitte & Touche LLP, the internal auditors and representatives of management to discuss auditing and financial reporting matters. The Audit Committee reviews audit plans and results and accounting, financial reporting and internal control practices, procedures and results. Both Deloitte & Touche LLP and the internal auditors have full and free access to all levels of management.

/s/ Barry L. Guy

Barry L. Guy
Vice President and Controller

Independent Auditors’ Report

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

We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (“Piedmont”) as of October 31, 2003 and 2002, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended October 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of Piedmont’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Piedmont at October 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP
January 9, 2004
(May 18, 2004 as to Note 14)

Quarterly Financial Data (In thousands except per share amounts)


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

2003
January 31	$	493,491	$	161,694	$	65,655		$	57,996		$	1.75		$	1.74
April 30	$	407,774	$	110,014	$	34,592		$	31,000		$	.93		$	.93
July 31	$	140,132	$	49,300	$	(1,870	)	$	(9,677	)	$	(.29	)	$	(.29	)
October 31	$	179,425	$	61,872	$	4,729		$	(4,957	)	$	(.15	)	$	(.15	)
2002
January 31	$	288,757	$	123,202	$	46,605		$	41,170		$	1.26		$	1.26
April 30	$	293,865	$	118,568	$	43,112		$	41,845		$	1.28		$	1.27
July 31	$	127,928	$	47,862	$	1,628		$	(8,977	)	$	(.27	)	$	(.27	)
October 31	$	121,478	$	46,162	$	(1,218	)	$	(11,821	)	$	(.36	)	$	(.36	)

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.

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, on May 18, 2004.


		Piedmont Natural Gas Company, Inc. (Registrant)

		By:		/s/ Thomas E. Skains

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

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 indicated as of May 18, 2004.


Signature		Title


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

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

/s/ Barry L. Guy Barry L. Guy		Vice President and Controller (Principal Accounting Officer)

Signature Title

/s/ Jerry W. Amos
Jerry W. Amos Director

/s/ C. M. Butler III
C. M. Butler III Director

/s/ D. Hayes Clement
D. Hayes Clement Director

/s/ Malcolm E. Everett III
Malcolm E. Everett III Director

/s/ John W. Harris
John W. Harris Director

/s/ Aubrey B. Harwell, Jr.
Aubrey B. Harwell, Jr. Director

/s/ Muriel W. Helms
Muriel W. Helms Director

/s/ Frank B. Holding, Jr.
Frank B. Holding, Jr. Director

/s/ David E. Shi
David E. Shi Director

Schedule II

Piedmont Natural Gas Company, Inc. and Subsidiaries
Valuation and Qualifying Accounts
For the Years Ended October 31, 2003, 2002 and 2001


			Additions
	Balance at		Charged to				Balance
	Beginning		Costs and				at End
Description	of Period		Expenses		Deductions (1)		of Period

			(in thousands)
Allowance for doubtful accounts:
2003	$	810	$	10,143	$	8,210	$	2,743
2002		592		3,200		2,982		810
2001		482		8,172		8,062		592

(1) Uncollectible accounts written off net of recoveries and adjustments.

Piedmont Natural Gas Company, Inc.
Form 10-K/A
For the Fiscal Year Ended October 31, 2003


		Exhibits


23.1		Independent Auditors’ Consent.

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.

	•		A reasonable purchase price slightly above book value,

	•		The prospect of entering a market contiguous to our existing North Carolina service areas where, as a combined company, we could realize on-going system benefits,

	•		The prospect of acquiring an operation that could be integrated into our existing business systems and processes, and

	•		The opportunity to grow within a regulatory environment with which we are familiar.

•		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.

•		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 on the part of Piedmont in the notes or in the indenture under which the notes were issued, and

•		Bankruptcy, liquidation or insolvency.


Signature		Title


/s/ Jerry W. Amos Jerry W. Amos		Director

/s/ C. M. Butler III C. M. Butler III		Director

/s/ D. Hayes Clement D. Hayes Clement		Director

/s/ Malcolm E. Everett III Malcolm E. Everett III		Director

/s/ John W. Harris John W. Harris		Director

/s/ Aubrey B. Harwell, Jr. Aubrey B. Harwell, Jr.		Director

/s/ Muriel W. Helms Muriel W. Helms		Director

/s/ Frank B. Holding, Jr. Frank B. Holding, Jr.		Director

/s/ David E. Shi David E. Shi		Director