PIEDMONT NATURAL GAS CO INC - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended January 31, 2003

or

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

For the Transition period from _________________ to _________________

Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [ ]

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


Class		Outstanding at March 4, 2003

Common Stock, no par value		33,310,490

Page 1 of 36 pages

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands)


					January 31,			October 31,
					2003			2002

					Unaudited			Audited
				ASSETS
Utility Plant, at original cost					$	1,747,772		$	1,730,968
	Less accumulated depreciation					586,823			572,445

			Utility plant, net			1,160,949			1,158,523

Other Physical Property (net of accumulated depreciation of $1,589 in 2003 and $1,531 in 2002)						1,065			1,078

Current Assets:
	Cash and cash equivalents					14,406			5,100
	Restricted cash					5,907			8,028
	Receivables (less allowance for doubtful accounts of $4,318 in 2003 and $810 in 2002)					154,505			37,504
	Unbilled utility revenues					90,697			—
	Gas in storage					33,822			65,688
	Deferred cost of gas					—			13,592
	Deferred income taxes					3,736			—
	Refundable income taxes					—			10,329
	Prepayments and other					18,566			35,545

			Total current assets			321,639			175,786

Investments, Deferred Charges and Other Assets:
		Investments in non-utility activities, at equity				84,606			80,342
		Unamortized debt expense				3,749			3,841
		Other				24,934			25,518

			Total investments, deferred charges and other assets			113,289			109,701

				Total	$	1,596,942		$	1,445,088

				CAPITALIZATION AND LIABILITIES
Capitalization:
	Common stock equity:
			Common stock		$	359,576		$	352,553
			Retained earnings			284,753			240,026
			Accumulated other comprehensive income			(2,000	)		(2,983	)

				Total common stock equity		642,329			589,596
	Long-term debt					462,000			462,000

				Total capitalization		1,104,329			1,051,596

Current Liabilities:
	Current maturities of long-term debt and sinking fund requirements					47,000			47,000
	Notes payable					44,000			46,500
	Accounts payable					108,193			51,093
	Deferred income taxes					—			1,384
	Income taxes accrued					20,616			—
	General taxes accrued					8,700			15,094
	Refunds due customers					27,406			15,635
	Other					33,574			28,425

			Total current liabilities			289,489			205,131

Deferred Credits and Other Liabilities:
		Accumulated deferred income taxes				157,680			158,275
		Unamortized federal investment tax credits				5,455			5,593
		Other				39,989			24,493

			Total deferred credits and other liabilities			203,124			188,361

				Total	$	1,596,942		$	1,445,088

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Statements of Consolidated Income (Unaudited)
(In thousands)


			Three Months						Twelve Months
			Ended						Ended
			January 31						January 31

			2003			2002			2003			2002

Operating Revenues			$	493,491		$	288,757		$	1,036,761		$	929,040
Cost of Gas				331,797			165,555			662,476			596,462

Margin				161,694			123,202			374,285			332,578

Other Operating Expenses:
	Operations			33,603			28,950			117,075			113,064
	Maintenance			4,892			4,759			21,139			19,503
	Depreciation			15,250			14,096			58,746			53,407
	General taxes			6,380			5,255			24,988			23,601
	Income taxes			35,914			23,537			43,276			32,312

		Total other operating expenses		96,039			76,597			265,224			241,887

Operating Income				65,655			46,605			109,061			90,691

Other Income (Expense):
	Non-utility activities, at equity			3,774			8,048			14,930			7,374
	Allowance for equity funds used during construction			282			244			1,734			1,410
	Other			373			46			840			8
	Income taxes			(1,752	)		(3,569	)		(7,077	)		(3,839	)

		Total other income (expense), net of tax		2,677			4,769			10,427			4,953

Utility Interest Charges				10,336			10,204			40,445			39,291

Net Income			$	57,996		$	41,170		$	79,043		$	56,353

Average Shares of Common Stock:
		Basic		33,186			32,560			32,921			32,327
		Diluted		33,300			32,729			33,079			32,543
Earnings Per Share of Common Stock:
		Basic	$	1.75		$	1.26		$	2.40		$	1.74
		Diluted	$	1.74		$	1.26		$	2.39		$	1.73
Cash Dividends Per Share of Common Stock			$	0.40		$	0.385		$	1.60		$	1.54

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Statements of Consolidated Cash Flows (Unaudited)
(In thousands)


				Three Months						Twelve Months
				Ended						Ended
				January 31						January 31

				2003			2002			2003			2002

Cash Flows from Operating Activities:
	Net income			$	57,996		$	41,170		$	79,043		$	56,353
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		15,480			14,290			59,583			54,277
			Undistributed earnings from equity investments		(3,774	)		(8,048	)		(14,930	)		(7,374	)
			Change in operating assets and liabilities		(33,698	)		(21,779	)		(15,475	)		(30,903	)
			Other, net		(1,219	)		1,260			8,605			22,123

	Net cash provided by operating activities				34,785			26,893			116,826			94,476

Cash Flows from Investing Activities:
	Utility construction expenditures				(17,079	)		(17,312	)		(79,889	)		(74,361	)
	Capital contributions to equity investments				(846	)		(575	)		(4,762	)		(3,704	)
	Capital distributions from equity investments				1,250			1,715			21,678			16,360
	Purchase of gas distribution system				2,153			—			(23,847	)		—
	Other				(38	)		(38	)		(111	)		(392	)

		Net cash used in investing activities			(14,560	)		(16,210	)		(86,931	)		(62,097	)

Cash Flows from Financing Activities:
	Increase (decrease) in bank loans, net				(2,500	)		1,000			11,000			(32,000	)
	Issuance of long-term debt				—			—			—			60,000
	Retirement of long-term debt				—			—			(2,000	)		(32,000	)
	Issuance of common stock through dividend reinvestment and employee stock plans				4,850			4,130			19,266			15,972
	Dividends paid				(13,269	)		(12,531	)		(52,647	)		(49,759	)

		Net cash used in financing activities			(10,919	)		(7,401	)		(24,381	)		(37,787	)

Net Increase (Decrease) in Cash and Cash Equivalents					9,306			3,282			5,514			(5,408	)
Cash and Cash Equivalents at Beginning of Period					5,100			5,610			8,892			14,300

Cash and Cash Equivalents at End of Period				$	14,406		$	8,892		$	14,406		$	8,892

Cash Paid During the Period for:
	Interest			$	16,069		$	16,167		$	39,599		$	39,236
	Income taxes			$	182		$	667		$	33,693		$	52,037

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Statement of Consolidated Comprehensive Income (Unaudited)
(In thousands)


		Three Months
		Ended January 31

		2003			2002

Net Income		$	57,996		$	41,170
Other Comprehensive Income:
	Unrealized income (loss) on equity investments hedging activities, net of tax of $71 and $(274) in 2003 and 2002, respectively		(109	)		493
	Reclassification adjustment for (income) loss included in net income, net of tax of $(714) and $48 in 2003 and 2002, respectively		1,092			(101	)

Total Comprehensive Income		$	58,979		$	41,562

Reconciliation of Accumulated Other Comprehensive Income:
	Balance, beginning of period	$	(2,983	)	$	(1,377	)
	Current period reclassification to earnings		1,092			(101	)
	Current period change		(109	)		493

	Balance, end of period	$	(2,000	)	$	(985	)

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Independent auditors have not audited the condensed consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2002 Annual Report.

2. In our opinion, the unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at January 31, 2003, and October 31, 2002, and the results of operations and cash flows for the three months and twelve months ended January 31, 2003 and 2002.

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

3. We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). 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 have capitalized 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 of or refunds 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 determine that all or a portion of these regulatory assets no longer meet 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 review has not resulted in any write offs of any regulatory assets or liabilities.

4. Effective November 1, 2002, we adopted SFAS No. 141, “Business Combinations” (Statement 141). Statement 141 requires that business combinations be accounted for using the purchase method. Statement 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination. The adoption of Statement 141 did not have a material effect on financial position or results of operations.

Effective November 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Statement 142 provides new guidance for accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be accounted for subsequent to their initial recognition. The adoption of Statement 142 did not have a material effect on financial position or results of operations.

Effective November 1, 2002, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 addresses financial accounting and reporting for

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asset retirement obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. 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. We accrue estimated costs of removal of long-lived assets through depreciation expense, with a corresponding credit to accumulated depreciation, as allowed by our three state regulatory commissions. Because these estimated removal costs meet the requirements of Statement 71, these accumulated costs are not classified as liabilities. As of January 31, 2003, we had $184.2 million of estimated costs of removal in excess of actual costs incurred included in accumulated depreciation in the consolidated balance sheets.

Effective November 1, 2002, we adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Statement 144 provides one accounting model to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. The adoption of Statement 144 did not have a material effect on financial position or results of operations.

5. In the quarter ended January 31, 2003, we performed an analysis of our revenue recognition practices and, after discussions with our independent accountants, we changed the way we record revenues and cost of gas related to volumes delivered but not yet billed. Recording unbilled revenues implements the practice in use by most gas utilities. The effect on earnings for the quarter and for the twelve months ended January 31, 2003, was an increase in margin of $29.1 million, or $.53 per share. Recording unbilled revenues changes the timing of revenue recognition from the cycle-billing method to the accrual method based on when the service is provided, and will result in increased earnings in the first and fourth quarters and lower earnings in the second and third quarters of fiscal year 2003. We estimate that the net effect in 2003 will be to increase earnings per share on a one-time, non-recurring basis by $.17.

6. Our business is seasonal in nature. The results of operations for the three-month period ended January 31, 2003, do not necessarily reflect the results to be expected for the full year.

7. Basic earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur when common stock equivalents are added to common shares outstanding. Shares that may be issued under the long-term incentive plan are our only common stock equivalents. A reconciliation of basic and diluted earnings per share is shown below:

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		Three Months				Twelve Months
		Ended				Ended
		January 31				January 31

In thousands except per share amounts		2003		2002		2003		2002

Net Income		$	57,996	$	41,170	$	79,043	$	56,353

Average shares of common stock outstanding for basic earnings per share			33,186		32,560		32,921		32,327
Contingently issuable shares under the long-term incentive plan			114		169		158		216

Average shares of dilutive stock			33,300		32,729		33,079		32,543

Earnings Per Share:
	Basic	$	1.75	$	1.26	$	2.40	$	1.74
	Diluted	$	1.74	$	1.26	$	2.39	$	1.73

8. Business Segments

We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Based on products and services and regulatory environments, operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Greenbrier Pipeline Company through their investments in ventures accounted for under the equity method. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company through its investment in a venture accounted for under the equity method.

Activities included in “Other” in the segment table consist primarily of propane operations conducted by Piedmont Propane Company. All of our activities other than the utility operations of the parent are included in “Other Income (Expense)” in the statements of consolidated income.

We evaluate performance based on margin, operations and maintenance expenses, operating income and income before taxes. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in our audited financial statements for the year ended October 31, 2002.

Continuing operations by segment for the three months ended January 31, 2003 and 2002, are presented below:


	Domestic				Retail Energy
	Natural Gas				Marketing
	Distribution				Services						Other						Total

In thousands	2003		2002		2003			2002			2003			2002			2003		2002

Revenues from external customers*	$	493,491	$	288,757	$	—		$	—		$	—		$	—		$	493,491	$	288,757
Margin		161,694		123,202		—			—			—			—			161,694		123,202
Operations and maintenance expenses		38,495		33,709		18			46			6			16			38,519		33,771
Operating income*		101,569		46,556		(18	)		(53	)		(8	)		(33	)		101,543		46,470
Other income		2,004		1,853		1,142			6,217			1,269			489			4,415		8,559
Income before income taxes		93,240		61,745		1,111			6,074			1,311			458			95,662		68,277
Construction expenditures		17,625		18,283		—			—			—			—			17,625		18,283
Income from non-utility activities, at equity		1,274		1,345		1,231			6,216			1,269			487			3,774		8,048
Investments in non-utility activities, at equity		35,672		32,248		25,779			31,026			23,155			25,265			84,606		88,539

*Operating revenues and operating income shown in the consolidated financial statements represent utility operations only.

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A reconciliation of net income in the condensed consolidated financial statements for the three months ended January 31, 2003 and 2002, is presented below:


		Three months
		Ended January 31

In thousands		2003		2002

Income before income taxes for reportable segments		$	94,351	$	67,819
Income before income taxes for other non-utility activities			1,311		458
Income taxes			37,666		27,107

	Net income	$	57,996	$	41,170

A reconciliation of consolidated assets in the condensed consolidated financial statements as of January 31, 2003 and October 31, 2002, is presented below:


In thousands		January 31, 2003			October 31, 2002

Total assets for reportable segments		$	1,607,908		$	1,457,069
Other assets			37,450			36,133
Eliminations/Adjustments			(48,416	)		(48,114	)

	Consolidated assets	$	1,596,942		$	1,445,088

9. Equity Investments

Risks of Equity Investments

Piedmont Intrastate Pipeline Company is a 16.45% member of Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the North Carolina Utilities Commission (NCUC). Cardinal has firm service agreements with local distribution companies, including Piedmont Natural Gas Company, for 100% of the 270 million cubic feet per day of 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.

Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation, and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under firm service agreements with customers. We subscribe to slightly more than one-half 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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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.

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Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P., a marketer of propane through a nationwide retail distribution network. Heritage Propane competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage Propane’s profitability is also sensitive to changes in the wholesale prices of propane. Heritage Propane utilizes hedging transactions to provide price 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. Heritage Propane has marketable securities that are classified as available-for-sale securities and recorded at fair value. Unrealized losses have been recorded through “Accumulated other comprehensive income” based on the market value of the securities. Heritage Propane’s management does not consider the decline in market value of the available-for-sale securities to be other than temporary. 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.

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 million. As of January 31, 2003, our capital account was positive.

Piedmont Energy Company has a 30% interest in SouthStar Energy Services LLC, a Delaware limited liability company. The other members are subsidiaries of AGL Resources, Inc. (AGLR), and Dynegy Holdings, Inc. On January 23, 2003, AGLR reached an agreement to purchase Dynegy’s 20% interest in SouthStar subject to a number of closing conditions, including withdrawal of the lawsuits between AGLR and Dynegy and approval of the transaction by the Georgia Public Service Commission (GPSC). In an order dated February 24, the GPSC approved the transaction. Upon closing on March 11, AGLR now owns a non-controlling 70% interest and we maintained our 30% ownership interest. The key goverance provisions requiring unanimous approval in the LLC Agreement did not change. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. SouthStar conducts most of its business in Georgia, and the unregulated retail gas market in that state is highly competitive.

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 service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of January 31, 2003, we estimated that a portion of SouthStar’s earnings for calendar year 2002 will be above the threshold, and that disproportionate sharing will occur for the first time. We reduced our portion of the equity earnings from SouthStar for the three months and twelve months ended January 31, 2003, by $1.6 million and $2.3 million, pre-tax, respectively, to reflect our estimate that our

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earnings from SouthStar were at a level of approximately 24% of total earnings, rather than our equity ownership percentage of 30% of total earnings. Based on various calculation methodologies and interpretations of the Operating Policy, our actual pre-tax earnings reduction due to disproportionate sharing could differ from our estimate.

SouthStar utilizes financial contracts to hedge the price volatility of natural gas. These financial contracts (futures, options and swaps) are considered to be derivatives, with prices 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.” Those derivative transactions that are not designated as hedges are reflected in the 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 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 Tasks Force Issue No. 99-2, “Accounting for Weather Derivatives.”

As part of the change in membership interest noted above, the members agreed to permit Dynegy to exit its contract to provide asset management and gas procurement and supply services for SouthStar. Effective January 31, 2003, SouthStar is performing in-house those activities previously provided by Dynegy. During 2002, SouthStar significantly expanded its portfolio of suppliers due to its exposure to Dynegy’s financial condition and Dynegy’s announcement that it intended to exit the gas supply and capacity management businesses.

Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the GPSC, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s bills for local delivery service. In August 2002, Piedmont Energy Company, through its parent Piedmont Energy Partners, guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $13.4 million that expires on August 5, 2003.

Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary with a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier). The other member is a subsidiary of Dominion Resources, Inc. Greenbrier proposes to build a 280-mile interstate gas pipeline linking multiple gas supply basins and storage to markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day to commence service in 2005. The pipeline would originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. The pipeline is expected to cost $497 million, with $150 million of the cost expected to be contributed as equity by the owners and the remainder expected to be provided by project-financed debt. As of January 31, 2003, we have made capital contributions to Greenbrier totaling $7.6 million.

We have signed a precedent agreement for firm transportation service with Greenbrier. On October 30, 2002, the FERC gave preliminary approval to the project regarding non-environmental issues. On February 28, 2003, the FERC issued its Final Environmental Impact Statement. Construction of the pipeline is subject to a number of conditions, including final certificate approval by the FERC.

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Related Party Transactions

We have related party transactions with Pine Needle as a customer. We record in cost of gas the storage costs charged by Pine Needle. These gas costs were $2.7 million and $2.8 million for the three months ended January 31, 2003 and 2002, respectively, and $10.8 million and $11.2 million for the twelve months ended January 31, 2003 and 2002, respectively. As of January 31, 2003 and 2002, we owed Pine Needle $.9 million.

We have related party transactions with Cardinal as a transportation customer. We record in cost of gas the transportation costs charged by Cardinal. These gas costs were $.4 million for the three months ended January 31, 2003 and 2002, and $1.5 million for the twelve months ended January 31, 2003 and 2002. As of January 31, 2003 and 2002, we owed Cardinal $.1 million.

We have related party transactions with SouthStar which purchases wholesale gas supplies from us. We record this activity in operating revenues at negotiated market prices. Such operating revenues totaled $.5 million and $1.7 million for the three months ended January 31, 2003 and 2002, respectively, and $9.6 million and $12.3 million for the twelve months ended January 31, 2003 and 2002, respectively. As of January 31, 2003 and 2002, SouthStar owed us $.3 million and $.4 million, respectively.

Summarized Financial Information

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for its fiscal quarters ended December 31, 2002 and 2001, is presented below.


In thousands	2002		2001

Revenues	$	4,281	$	4,281
Gross profit		—		—
Income before income taxes		2,281		2,369
Total assets		104,130		105,676

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for its fiscal quarters ended December 31, 2002 and 2001, is presented below.


In thousands	2002		2001

Revenues	$	4,988	$	5,072
Gross profit		—		—
Income before income taxes		2,440		2,727
Total assets		112,602		110,762

Summarized unaudited financial information for Heritage Propane for 100% of Heritage Propane for its fiscal quarters ended November 30, 2002 and 2001, as filed in its Form 10-Q with the Securities and Exchange Commission, is presented below.


In thousands	2002		2001

Revenues	$	173,483	$	162,103
Gross profit		116,463		101,868
Income (loss) before income taxes		1,139		(4,779	)
Total assets		751,320		792,536

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Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for its fiscal quarters ended December 31, 2002 and 2001, is provided below.


In thousands	2002		2001

Revenues	$	189,683	$	163,958
Gross profit		26,013		35,229
Income before income taxes		7,928		20,717
Total assets		165,940		156,513

Summarized unaudited finanacial information provided to us by Greenbrier for 100% of Greenbrier for its fiscal quarters ended December 31, 2002 and 2001, is presented below.


In thousands	2002			2001

Revenues	$	(1	)	$	—
Gross profit		(1	)		—
Income before income taxes		65			2
Total assets		23,581			8,510

10. Derivatives and Hedging Activities

We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service territory where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas adjustment 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 twelve months ended January 31, 2003, we purchased financial call options for natural gas for our Tennessee gas purchase portfolio. As of January 31, 2003, none of these options were open. 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 $1.6 million for shareholder gains or losses. The net gains or losses on gas procurement 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 procurement costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders. This amount is subject to the overall annual cap and is placed in a regulatory asset to be collected from or refunded to customers.

As of January 31, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for delivery in March 2003 through October 2003. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers. This plan operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange and is limited to 60% of the annual

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normalized sales volumes for South Carolina. 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 supply cost 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). Purchases are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis. The plan is designed with limited subjective discretion in making purchases with little or no risk of speculation in the market.

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 of January 31, 2003, we have purchased financial call options for natural gas for our North Carolina gas purchase portfolio for delivery in March 2003 through October 2003. Prudently incurred gas costs of these options associated with the hedging program are not pre-approved by the NCUC but will be treated as gas costs subject to the annual gas cost prudency review based on the information available at the time of the hedge, not at the time of the prudency review. The operation of the hedging program is identical to that of the South Carolina hedging program and is limited to 60% of the annual normalized sales volumes for North Carolina.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Documents we file with the Securities and Exchange Commission (SEC) may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. Forward-looking statements concern, among others, plans, objectives, proposed capital expenditures and future events or performance. Such statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include:

• Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated by the FERC and the NCUC, respectively.

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

• Deregulation, unanticipated impacts of regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies. As a result of deregulation, we expect this highly competitive environment to continue.

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

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

• The capital-intensive nature of our business, including government approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project.

• Changes in the availability and price of natural gas. To meet customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts will allow us to remain competitive. Natural gas is an unregulated commodity subject to market supply and demand and price volatility. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers, marketers and

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pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging activity to minimize price volatility for our customers.

• Changes in weather conditions. Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild or severe weather, either during the winter period or the summer period, can have a significant impact on the demand for and the cost of natural gas.

• Changes in environmental regulations and cost of compliance.

• Earnings from our equity investments. We have investments in unregulated retail energy marketing services, interstate liquefied natural gas (LNG) storage operations, intrastate and interstate pipeline operations and unregulated retail propane operations. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks.

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

Factors relating to regulation and management are also described or incorporated in our Annual Report on Form 10-K, as well as information included in, or incorporated by reference from, future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in this report. There also may be other factors besides those described above or incorporated in this report or in the Form 10-K that could cause actual conditions, events or results to differ from those in the forward-looking statements.

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

Our Business

Piedmont Natural Gas Company, Inc., began operations in 1951, and is an energy services company primarily engaged in the distribution of natural gas to 740,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. Piedmont is also invested in a number of non-utility, energy-related businesses, including companies involved in unregulated retail natural gas and propane marketing and interstate and intrastate natural gas storage and transportation. We also sell residential and commercial gas appliances in Tennessee.

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Our utility operations are subject to regulation by the NCUC, the 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. We are also subject to or affected by various federal and state regulations.

We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us.

In the Carolinas, our service area is comprised of numerous cities, towns and communities including Anderson, Greenville, Spartanburg and Gaffney in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine and Reidsville in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville.

On October 16, 2002, we entered into an agreement to purchase for $417.5 million in cash 100% of the common stock of North Carolina Natural Gas Corporation (NCNG). NCNG, a natural gas distribution subsidiary of Progress Energy, Inc., serves approximately 176,000 customers in eastern North Carolina, including 56,000 customers served by four municipalities who are wholesale customers of NCNG. The purchase price for the NCNG common stock will be increased or decreased by the amount of NCNG’s working capital on the closing date, which is expected to occur in mid-2003. We expect to merge NCNG into Piedmont immediately following the closing. We also agreed to purchase for $7.5 million in cash, Progress’ equity interest in Eastern North Carolina Natural Gas Company (EasternNC). EasternNC is a regulated utility that was issued a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina. Progress’ equity interest in EasternNC consists of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. The purchase agreement obligates us to purchase additional authorized but unissued shares of such preferred stock for $14.4 million. Each of the proposed transactions is subject to a number of conditions, including approval of the NCUC.

We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. For further information on segments, see Note 8 to the consolidated financial statements.

Financial Condition and Liquidity

We finance current cash requirements primarily from operating cash flows and short-term borrowings. During the quarter ended January 31, 2003, outstanding short-term borrowings under committed bank lines of credit totaling $150 million ranged from $30 million to $73 million, and interest rates ranged from 1.69% to 2.04%. We have additional uncommitted lines of credit totaling $73 million on a no fee and as needed, if available, basis.

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Our utility operations are weather sensitive. The primary factor that impacts our cash flows from operations is weather. Warmer weather can lead to lower total margin from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but extremely cold weather may lead to conservation by our customers in order to reduce their consumption. Weather outside the normal range of temperatures can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements. During the twelve months ended January 31, 2003, 59% of our sales and transportation revenues were from residential customers and 28% were from commercial customers, both of which are weather-sensitive customer classes. We have a weather normalization adjustment (WNA) mechanism in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for these weather-sensitive customers. The mechanism is most effective in a reasonable temperature range relative to normal weather using 30 years of history.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas that are charged by suppliers and to increased gas supplies required to meet our customers’ needs during cold weather and to meet our storage needs. Short-term debt generally increases when wholesale prices for natural gas increase because we must pay suppliers for the gas before we recover our costs from customers through their monthly bills. We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. During the twelve months ended January 31, 2003, we issued $19.3 million of equity through dividend reinvestment and stock purchase plans but none on the open market. We did not sell any long-term debt during the twelve months ended January 31, 2003. We anticipate selling $70 million of long-term debt in the fourth quarter of 2003 to finance our ongoing capital requirements. In addition, as stated in the following paragraph, we expect to sell additional debt and equity securities to fund our proposed acquisition of NCNG and EasternNC. Unless otherwise specified at the time such securities are offered for sale, the net proceeds will be used for general corporate purposes, including construction of additional facilities, repayment of short-term debt and working capital needs. Pending such use, we may temporarily invest the net proceeds in investment grade securities.

Our debt ratings are “A2” from Moody’s and “A” from Standard & Poor’s (S&P). We are well within the debt default provisions established for our senior notes, medium-term notes, short-term bank lines of credit and accounts receivable financings. Following the announcement of our proposed acquisition of NCNG and EasternNC discussed above, Moody’s and S&P placed our debt ratings under review for possible downgrade. The purchase price of $425 million will initially be funded with short-term debt that will be refinanced within six months through the issuance of long-term debt and equity securities. While this acquisition will be positive in the long run as we expand our customer base in North Carolina, it would have an initial short-term effect of increased debt levels and reduced fixed charge coverages.

The financial condition of the pipelines and marketers that supply and deliver natural gas to our system can increase our exposure to supply and price fluctuations. The Williams Companies, Inc., whose subsidiary Transcontinental Gas Pipe Line Corporation (Transco) is the major pipeline serving our North Carolina and South Carolina service areas and whose subsidiary Williams Energy Services Company (Wesco) is a wholesale supplier of commodity natural gas

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service, has experienced financial difficulties. Wesco currently provides natural gas to us under several supply contracts. In all cases with Transco and Wesco, and with other suppliers with whom we have smaller contracts, the products and services are received by us prior to payment or are subject to payment netting agreements. We believe our risk exposure to the financial condition of these companies is minimal based on receipt of the products and other services prior to payment and the availability of other marketers of natural gas to meet our supply needs if necessary.

The natural gas business is seasonal in nature resulting in fluctuations primarily in balances in accounts receivable from customers, inventories of stored natural gas and accounts payable to suppliers in addition to short-term borrowings discussed above. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. From April 1 to October 31, we build up natural gas inventories by injecting gas into storage for sale in the colder months. Inventory of stored gas decreased from October 31, 2002, to January 31, 2003. Accounts payable and accounts receivable increased from October 31, 2002, to January 31, 2003, due to this seasonality, the demand for gas during the winter season, the purchase of the North Carolina Gas Service gas distribution system from NUI Utilities, Inc., effective September 30, 2002, and the change in the way that we record revenues and cost of gas related to volumes delivered but not yet billed. This change resulted in estimated unbilled utility receivables of $90.7 million.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our approximately 4% current annual growth in customer base. Utility construction expenditures for the three months ended January 31, 2003, were $17.6 million, compared with $18.2 million for the same period in 2002. Utility construction expenditures for the twelve-month period ended January 31, 2003, were $83.1 million, compared with $79.7 million for the same period in 2002. Due to growth in our service area, significant utility construction expenditures are expected to continue. Short-term debt may be used to finance construction pending the issuance of long-term debt or equity.

For the twelve months ended January 31, 2003, cash provided from operations, from bank lines of credit and from the issuance of common stock through dividend reinvestment and stock purchase plans was sufficient to fund construction expenditures, pay debt principal and interest of $41.6 million and pay dividends to shareholders of $52.6 million.

Our expected future contractual obligations as of January 31, 2003, for long-term debt, pipeline and storage capacity and gas supply and operating leases are as follows:


			Payments Due by Period

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

Long-term debt	$	509,000	$	47,000	$	37,000	$	—	$	425,000
Pipeline and storage capacity and gas supply		830,477		96,698		241,764		140,472		351,543
Operating leases		13,752		3,917		5,887		2,066		1,882

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As of January 31, 2003, our capitalization consisted of 42% in long-term debt and 58% in common equity. Our long-term targeted capitalization ratio is 45% in long-term debt and 55% in common equity.

Critical Accounting Policies and Estimates

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

Our regulated utility segment is subject to regulation by certain state and federal authorities. We have accounting policies that conform to Statement 71, and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to these portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.

We believe the following represents the more significant judgments and estimates used in preparing our consolidated financial statements.

Unbilled Utility Revenues. We record estimated revenues to be billed for volumes delivered but not yet billed at month end due to reading meters and billing on a cycle basis. The estimated revenues are calculated based on estimated volumes delivered but unbilled at each month end and the billing rates applicable to those volumes, adjusted for any potential billing impacts of the WNA.

Allowance for Uncollectible Accounts. We evaluate the collectibility of our trade accounts receivable based on our recent loss history and an overall assessment of past-due trade accounts receivable amounts outstanding.

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Employee Benefits. We have a defined-benefit pension plan for the benefit of eligible full-time employees. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to the plan. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases, within certain guidelines. In addition, our actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense recorded in future periods.

Self Insurance. We are self-insured for certain losses related to general liability, group medical benefits and workers’ compensation. We maintain stop loss coverage with third-party insurers to limit our total exposure. Our liabilities represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are not discounted and are established based upon analyses of historical data and actuarial estimates. We, along with independent actuaries, review the liabilities at least annually to ensure that they are appropriate. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from our estimates.

Long-Term Incentive Plan. We have a Long-Term Incentive Plan (LTIP) covering five-year performance periods under which units are awarded to participants. Each unit is equivalent in value to one share of common stock. Following the end of the performance period, awards are distributed in the form of shares of common stock and cash withheld to pay taxes if performance measures are met. During the performance period, we calculate the expense and liability for the LTIP based on performance levels achieved or expected to be achieved and the estimated market value of common stock as of the distribution date. While we believe these estimates are reasonable based on the information available, actual amounts, which are not known until after the end of the performance period, could differ from our estimates.

Results of Operations

We will discuss the results of operations for the three months and twelve months ended January 31, 2003, compared with similar periods in 2002.

Margin

Margin (operating revenues less cost of gas) for the three months ended January 31, 2003, increased $38.5 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $23.6 million due to an increase in volumes billed of 10.3 million dekatherms due to 41% colder weather and growth in customer base.

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• Increase of $29.1 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. This represents a $90.7 million increase in operating revenues less a $61.6 million increase in cost of gas.

• Increase of $4.8 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2.4 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

These increases were partially offset by the following decreases.

• Margin for the current three-month period includes $5.2 million in billed refunds from the WNA due to weather that was 9% colder than normal, compared with billed surcharges of $12.5 million in the prior period due to weather that was 23% warmer than normal, a net decrease in margin of $17.7 million. The WNA is designed to offset the impact of unusually cold or warm weather on customer billings and margin.

• Decrease of $1.2 million in margin from power generation customers.

• Decrease of $2.2 million from the allocation and capitalization of demand costs.

• Decrease in other revenues of $1 million, largely due to a decrease in revenues from miscellaneous service work.

Margin for the twelve months ended January 31, 2003, increased $41.7 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $22.7 million from increased volumes due to colder weather and growth in customer base. Billed volumes increased 13.8 million dekatherms over the same period in 2002 primarily due to 19% colder weather.

• Increase of $29.1 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. This represents a $90.7 million increase in operating revenues less a $61.6 million increase in cost of gas.

• Increase of $5.8 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $1.8 million from the allocation and capitalization of demand costs.

• Increase of $2.6 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

These increases were partially offset by the following decreases.

• Margin for the current twelve-month period includes $2.2 million in billed surcharges from the WNA, compared with billed surcharges of $18.4 million in the prior period, a net decrease in margin of $16.2 million.

• Decrease in other revenues of $3.6 million, primarily due to decreases in revenues from late payment fees and miscellaneous service work.

Under gas cost recovery mechanisms in all three states, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or

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under-recoveries of gas costs are added to or deducted from cost of gas and included in refunds due customers in the condensed consolidated financial statements. In North Carolina and South Carolina, recovery of gas costs is subject to findings made in annual gas cost recovery proceedings to determine the prudency of our gas purchases. We have been found prudent in all such past proceedings; however, there can be no guarantee that we will be found prudent in future proceedings.

Operations and Maintenance Expenses

Operations and maintenance expenses for the three months ended January 31, 2003, increased $4.8 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $1.6 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, accrual of the short-term incentive program and merit increases, including the impact of moving to a common review date for all non-bargaining unit employees.

• Increase of $1.8 million in the provision for uncollectibles primarily due to higher gas bills due to higher costs and colder weather.

• Increase of $1.3 million in employee benefits primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of changes in actuarial assumptions.

Operations and maintenance expenses for the twelve months ended January 31, 2003, increased $5.6 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $6.7 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, accrual of the short-term incentive program and merit increases, including the impact of moving to a common review date for all non-bargaining unit employees.

• Increase of $2.6 million in employee benefits primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of changes in actuarial assumptions.

These increases were partially offset by the following decreases.

• Decrease of $2.3 million in outside labor primarily due to fewer projects and vacancies in the information services area and decreases in amounts paid for outsourced meter reading, collection agency fees and pre-disconnect contact fees.

• Decrease of $1.6 million in the provision for uncollectibles primarily due to lower write-offs of accounts receivable compared with the similar prior period when bills were impacted by much higher gas prices and colder weather.

Depreciation

Depreciation expense for the three months and twelve months ended January 31, 2003, increased over similar prior periods due to the growth of plant in service. Due to the continued growth in

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our service areas and our commitment to capital expansion, we anticipate that depreciation expense will continue to increase.

General Taxes

General taxes for the three months ended January 31, 2003, increased $1.1 million compared with the same period in 2002 primarily due to increases of $.8 million in property taxes and $.2 million in Tennessee gross receipts taxes.

General taxes for the twelve months ended January 31, 2003, increased $1.4 million compared with the same period in 2002 primarily due to increases of $.4 million in franchise taxes, $.4 million in Tennessee gross receipts taxes and $.3 million in payroll taxes.

Other Income (Expense)

Income from equity investee earnings for the three months ended January 31, 2003, decreased $4.3 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $5 million, including the estimated reduction of $1.6 million due to disproportionate sharing of earnings. This decrease was partially offset by an increase of $.8 million in earnings from US Propane.

Income from equity investee earnings for the twelve months ended January 31, 2003, increased $7.6 million compared with the same period in 2002 primarily due to an increase in earnings from SouthStar of $8.3 million, including the estimated reduction of $2.3 million due to disproportionate sharing of earnings.

This increase was partially offset by the following decreases.

• Decrease of $.5 million in earnings from Pine Needle.

• Decrease of $.3 million in earnings from US Propane primarily attributable to a pre-tax loss of $1.4 million on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane.

The equity portion of the allowance for funds used during construction (AFUDC) for the three months and twelve months ended January 31, 2003, compared with similar periods in 2002 increased slightly and $.3 million, respectively. AFUDC is allocated between equity and debt based on the ratio of construction work in progress to average short-term borrowings.

Other for the three months ended January 31, 2003, increased $.3 million compared with the same period in 2002 primarily due to an increase in interest income and a decrease in charitable contributions due to timing.

Other for the twelve months ended January 31, 2003, increased $.8 million compared with the same period in 2002 primarily due to increases in earnings from merchandise operations and jobbing operations and in interest income and a decrease in charitable contributions due to timing.

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Utility Interest Charges

Utility interest charges for the three months ended January 31, 2003, increased $.1 million compared with the same period in 2002 primarily due to a decrease of $.5 million in the portion of AFUDC attributable to borrowed funds, partially offset by a decrease of $.4 million in interest on refunds due customers due to lower balances outstanding.

Utility interest charges for the twelve months ended January 31, 2003, increased $1.2 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $1.1 million in interest on long-term debt from higher amounts outstanding.

• Decrease of $2.7 million in the portion of AFUDC attributable to borrowed funds.

These changes were partially offset by the following decreases.

• Decrease of $1.6 million in interest on refunds due customers due to lower balances outstanding.

• Decrease of $1 million in interest on short-term debt due to lower interest rates even though higher balances were outstanding.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

All financial instruments discussed below are held by us for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Exposure to interest rate changes relates to both short- and long-term debt. Exposure to gas cost variations relates to the supply of and demand for natural gas.

Interest Rate Risk

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

As of January 31, 2003, we had $44 million of short-term debt outstanding with a weighted average interest rate of 1.77%. We borrow primarily highly liquid debt instruments of a short-term nature and the carrying amount of such debt approximates fair value.

The table below provides information about our long-term debt as of January 31, 2003, that is sensitive to changes in interest rates.


	Expected Maturity Date																			Fair Value at
																				January 31,
In thousands	2003			2004			2005		2006			2007		Thereafter			Total			2003

Fixed Rate Long–term Debt	$	47,000		$	2,000		$	—	$	35,000		$	—	$	425,000		$	509,000		$	564,000
Average Interest Rate		6.39	%		10.06	%		—		9.44	%		—		7.55	%		7.59	%

Credit Rating

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

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

• Ratio of net cash flows to capital expenditures,

• Funds from operations interest coverage,

• Ratio of funds from operations to average total debt and

• Pre-tax interest coverage.

Qualitative factors include, among other things:

• Stability of regulation in each jurisdiction in which we operate,

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

• Predictability of cash flows,

• Business strategy and management,

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• Industry position and

• Contingencies.

As of January 31, 2003, our long-term debt, consisting of medium-term notes and senior notes, was rated “A2” by Moody’s and “A” by S&P. As stated earlier in this report, Moody’s and S&P placed our debt ratings under review for possible downgrade following the announcement of our proposed acquisition of NCNG and EasternNC.

Commodity Price Risk

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

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 2 of this report beginning on page 17.

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Item 4. Controls and Procedures

Within 90 days of the filing of this report, management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. Such disclosure controls and procedures are designed to ensure that all information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on our evaluation process, the Chief Executive Officer and the Chief Financial Officer have concluded that our disclosure controls and procedures are effective. Since the evaluation was completed, there have been no significant changes in internal controls or other factors that could significantly affect those controls.

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Part II. Other Information

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

We held our Annual Meeting of Shareholders on February 28, 2003, to elect three directors and to ratify the selection of independent auditors. The record date for determining the shareholders entitled to receive notice of and to vote at the meeting was January 13, 2003. We solicited proxies for the meeting according to section 14(a) of the Securities and Exchange Act of 1934. There was no solicitation in opposition to management’s solicitations.

Shareholders elected all of management’s nominees for director as listed in the proxy statement by the following votes:


		Shares		Shares		Shares
		Voted		Voted		NOT
		FOR		WITHHELD		VOTED

For terms expiring in 2006:
	C. M. Butler III		27,548,220		315,894		5,313,680
	John W. Harris		27,635,083		229,031		5,313,680
	Aubrey B. Harwell, Jr.		27,623,180		240,934		5,313,680

Directors Jerry W. Amos, D. Hayes Clement and Thomas E. Skains will continue in office until 2004. Directors Malcolm E. Everett III, Muriel W. Helms, Donald S. Russell and John E. Simkins will continue in office until 2005.

Shareholders approved the selection by the Board of Directors of the firm of Deloitte & Touche LLP as independent auditors for the fiscal year ending October 31, 2003, by the following vote:

Shares

Voted

NOT

FOR

AGAINST

ABSTAINING

VOTED

27,445,087

284,305

121,793

5,326,609

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Item 5. Other Information

Regulatory Proceedings

On October 29, 2002, the PSCSC issued an order approving an annual revenue increase of $8.4 million, effective November 1, 2002. The Consumer Advocate of South Carolina requested a rehearing of the order that the PSCSC denied on January 28, 2003.

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Item 6. Exhibits and Reports on Form 8-K


(a)		Exhibits –

		12 Computation of Ratio of Earnings to Fixed Charges.

(b)		Reports on Form 8-K –

		On November 6, 2002, we filed a report on Form 8-K regarding a press release providing earnings guidance for fiscal year 2003 and reaffirming our previous earnings guidance for fiscal year 2002.

		On December 23, 2002, we filed a report on Form 8-K regarding a press release announcing that Ware F. Schiefer, Chief Executive Officer and Vice Chairman of the Board, would be retiring from the Company and the Board at the annual meeting of shareholders on February 28, 2003, and that Thomas E. Skains had been elected to the position of President and Chief Executive Officer effective upon Mr. Schiefer’s retirement. Further, we reported that John H. Maxheim, Chairman of the Board, would retire as Chairman and as a Board member at the February 28 meeting.

		On January 8, 2003, we filed a report on Form 8-K regarding a press release announcing that the Board of Directors had elected Kim R. Cocklin to the position of Senior Vice President and General Counsel, effective February 3, 2003.

		Outside of the period, on February 28, 2003, we filed a report on Form 8-K regarding the issuance of three press releases to report (1) first quarter results, (2) declaration of dividend and (3) corporate leadership changes and adoption of corporate governance guidelines.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		Piedmont Natural Gas Company, Inc.

		(Registrant)

Date March 12, 2003		/s/ David J. Dzuricky

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

Date March 12, 2003		/s/ Barry L. Guy

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

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CERTIFICATIONS

I, Thomas E. Skains, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

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6. The registrant’s other certifying officer and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: March 12, 2003		/s/ Thomas E. Skains

		Thomas E. Skains
		President and Chief Executive Officer
		(Chief Executive Officer)

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CERTIFICATIONS

I, David J. Dzuricky, certify that:

-35-


Date: March 12, 2003		/s/ David J. Dzuricky

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

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1.		Independent auditors have not audited the condensed consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2002 Annual Report.

2.		In our opinion, the unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at January 31, 2003, and October 31, 2002, and the results of operations and cash flows for the three months and twelve months ended January 31, 2003 and 2002.

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

3.		We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). 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 have capitalized 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 of or refunds 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 determine that all or a portion of these regulatory assets no longer meet 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 review has not resulted in any write offs of any regulatory assets or liabilities.

4.		Effective November 1, 2002, we adopted SFAS No. 141, “Business Combinations” (Statement 141). Statement 141 requires that business combinations be accounted for using the purchase method. Statement 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination. The adoption of Statement 141 did not have a material effect on financial position or results of operations.

		Effective November 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Statement 142 provides new guidance for accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be accounted for subsequent to their initial recognition. The adoption of Statement 142 did not have a material effect on financial position or results of operations.

		Effective November 1, 2002, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 addresses financial accounting and reporting for

		asset retirement obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. 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. We accrue estimated costs of removal of long-lived assets through depreciation expense, with a corresponding credit to accumulated depreciation, as allowed by our three state regulatory commissions. Because these estimated removal costs meet the requirements of Statement 71, these accumulated costs are not classified as liabilities. As of January 31, 2003, we had $184.2 million of estimated costs of removal in excess of actual costs incurred included in accumulated depreciation in the consolidated balance sheets.

		Effective November 1, 2002, we adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Statement 144 provides one accounting model to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. The adoption of Statement 144 did not have a material effect on financial position or results of operations.

5.		In the quarter ended January 31, 2003, we performed an analysis of our revenue recognition practices and, after discussions with our independent accountants, we changed the way we record revenues and cost of gas related to volumes delivered but not yet billed. Recording unbilled revenues implements the practice in use by most gas utilities. The effect on earnings for the quarter and for the twelve months ended January 31, 2003, was an increase in margin of $29.1 million, or $.53 per share. Recording unbilled revenues changes the timing of revenue recognition from the cycle-billing method to the accrual method based on when the service is provided, and will result in increased earnings in the first and fourth quarters and lower earnings in the second and third quarters of fiscal year 2003. We estimate that the net effect in 2003 will be to increase earnings per share on a one-time, non-recurring basis by $.17.

6.		Our business is seasonal in nature. The results of operations for the three-month period ended January 31, 2003, do not necessarily reflect the results to be expected for the full year.

7.		Basic earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur when common stock equivalents are added to common shares outstanding. Shares that may be issued under the long-term incentive plan are our only common stock equivalents. A reconciliation of basic and diluted earnings per share is shown below:

8.		Business Segments

		We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Based on products and services and regulatory environments, operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Greenbrier Pipeline Company through their investments in ventures accounted for under the equity method. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company through its investment in a venture accounted for under the equity method.

		Activities included in “Other” in the segment table consist primarily of propane operations conducted by Piedmont Propane Company. All of our activities other than the utility operations of the parent are included in “Other Income (Expense)” in the statements of consolidated income.

		We evaluate performance based on margin, operations and maintenance expenses, operating income and income before taxes. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in our audited financial statements for the year ended October 31, 2002.

		Continuing operations by segment for the three months ended January 31, 2003 and 2002, are presented below:

9.		Equity Investments

		Risks of Equity Investments

		Piedmont Intrastate Pipeline Company is a 16.45% member of Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the North Carolina Utilities Commission (NCUC). Cardinal has firm service agreements with local distribution companies, including Piedmont Natural Gas Company, for 100% of the 270 million cubic feet per day of 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.

		Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation, and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under firm service agreements with customers. We subscribe to slightly more than one-half 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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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.

		Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P., a marketer of propane through a nationwide retail distribution network. Heritage Propane competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage Propane’s profitability is also sensitive to changes in the wholesale prices of propane. Heritage Propane utilizes hedging transactions to provide price 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. Heritage Propane has marketable securities that are classified as available-for-sale securities and recorded at fair value. Unrealized losses have been recorded through “Accumulated other comprehensive income” based on the market value of the securities. Heritage Propane’s management does not consider the decline in market value of the available-for-sale securities to be other than temporary. 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.

		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 million. As of January 31, 2003, our capital account was positive.

		Piedmont Energy Company has a 30% interest in SouthStar Energy Services LLC, a Delaware limited liability company. The other members are subsidiaries of AGL Resources, Inc. (AGLR), and Dynegy Holdings, Inc. On January 23, 2003, AGLR reached an agreement to purchase Dynegy’s 20% interest in SouthStar subject to a number of closing conditions, including withdrawal of the lawsuits between AGLR and Dynegy and approval of the transaction by the Georgia Public Service Commission (GPSC). In an order dated February 24, the GPSC approved the transaction. Upon closing on March 11, AGLR now owns a non-controlling 70% interest and we maintained our 30% ownership interest. The key goverance provisions requiring unanimous approval in the LLC Agreement did not change. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. SouthStar conducts most of its business in Georgia, and the unregulated retail gas market in that state is highly competitive.

		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 service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of January 31, 2003, we estimated that a portion of SouthStar’s earnings for calendar year 2002 will be above the threshold, and that disproportionate sharing will occur for the first time. We reduced our portion of the equity earnings from SouthStar for the three months and twelve months ended January 31, 2003, by $1.6 million and $2.3 million, pre-tax, respectively, to reflect our estimate that our

		earnings from SouthStar were at a level of approximately 24% of total earnings, rather than our equity ownership percentage of 30% of total earnings. Based on various calculation methodologies and interpretations of the Operating Policy, our actual pre-tax earnings reduction due to disproportionate sharing could differ from our estimate.

		SouthStar utilizes financial contracts to hedge the price volatility of natural gas. These financial contracts (futures, options and swaps) are considered to be derivatives, with prices 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.” Those derivative transactions that are not designated as hedges are reflected in the 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 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 Tasks Force Issue No. 99-2, “Accounting for Weather Derivatives.”

		As part of the change in membership interest noted above, the members agreed to permit Dynegy to exit its contract to provide asset management and gas procurement and supply services for SouthStar. Effective January 31, 2003, SouthStar is performing in-house those activities previously provided by Dynegy. During 2002, SouthStar significantly expanded its portfolio of suppliers due to its exposure to Dynegy’s financial condition and Dynegy’s announcement that it intended to exit the gas supply and capacity management businesses.

		Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the GPSC, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s bills for local delivery service. In August 2002, Piedmont Energy Company, through its parent Piedmont Energy Partners, guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $13.4 million that expires on August 5, 2003.

		Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary with a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier). The other member is a subsidiary of Dominion Resources, Inc. Greenbrier proposes to build a 280-mile interstate gas pipeline linking multiple gas supply basins and storage to markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day to commence service in 2005. The pipeline would originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. The pipeline is expected to cost $497 million, with $150 million of the cost expected to be contributed as equity by the owners and the remainder expected to be provided by project-financed debt. As of January 31, 2003, we have made capital contributions to Greenbrier totaling $7.6 million.

		We have signed a precedent agreement for firm transportation service with Greenbrier. On October 30, 2002, the FERC gave preliminary approval to the project regarding non-environmental issues. On February 28, 2003, the FERC issued its Final Environmental Impact Statement. Construction of the pipeline is subject to a number of conditions, including final certificate approval by the FERC.

		Related Party Transactions

		We have related party transactions with Pine Needle as a customer. We record in cost of gas the storage costs charged by Pine Needle. These gas costs were $2.7 million and $2.8 million for the three months ended January 31, 2003 and 2002, respectively, and $10.8 million and $11.2 million for the twelve months ended January 31, 2003 and 2002, respectively. As of January 31, 2003 and 2002, we owed Pine Needle $.9 million.

		We have related party transactions with Cardinal as a transportation customer. We record in cost of gas the transportation costs charged by Cardinal. These gas costs were $.4 million for the three months ended January 31, 2003 and 2002, and $1.5 million for the twelve months ended January 31, 2003 and 2002. As of January 31, 2003 and 2002, we owed Cardinal $.1 million.

		We have related party transactions with SouthStar which purchases wholesale gas supplies from us. We record this activity in operating revenues at negotiated market prices. Such operating revenues totaled $.5 million and $1.7 million for the three months ended January 31, 2003 and 2002, respectively, and $9.6 million and $12.3 million for the twelve months ended January 31, 2003 and 2002, respectively. As of January 31, 2003 and 2002, SouthStar owed us $.3 million and $.4 million, respectively.

		Summarized Financial Information

		Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for its fiscal quarters ended December 31, 2002 and 2001, is presented below.

10.		Derivatives and Hedging Activities

		We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service territory where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas adjustment 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 twelve months ended January 31, 2003, we purchased financial call options for natural gas for our Tennessee gas purchase portfolio. As of January 31, 2003, none of these options were open. 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 $1.6 million for shareholder gains or losses. The net gains or losses on gas procurement 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 procurement costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders. This amount is subject to the overall annual cap and is placed in a regulatory asset to be collected from or refunded to customers.

		As of January 31, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for delivery in March 2003 through October 2003. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers. This plan operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange and is limited to 60% of the annual

		normalized sales volumes for South Carolina. 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 supply cost 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). Purchases are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis. The plan is designed with limited subjective discretion in making purchases with little or no risk of speculation in the market.

		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 of January 31, 2003, we have purchased financial call options for natural gas for our North Carolina gas purchase portfolio for delivery in March 2003 through October 2003. Prudently incurred gas costs of these options associated with the hedging program are not pre-approved by the NCUC but will be treated as gas costs subject to the annual gas cost prudency review based on the information available at the time of the hedge, not at the time of the prudency review. The operation of the hedging program is identical to that of the South Carolina hedging program and is limited to 60% of the annual normalized sales volumes for North Carolina.

	•		Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated by the FERC and the NCUC, respectively.

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

	•		Deregulation, unanticipated impacts of regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies. As a result of deregulation, we expect this highly competitive environment to continue.

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

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

	•		The capital-intensive nature of our business, including government approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project.

	•		Changes in the availability and price of natural gas. To meet customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts will allow us to remain competitive. Natural gas is an unregulated commodity subject to market supply and demand and price volatility. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers, marketers and

			pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging activity to minimize price volatility for our customers.

	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild or severe weather, either during the winter period or the summer period, can have a significant impact on the demand for and the cost of natural gas.

	•		Changes in environmental regulations and cost of compliance.

	•		Earnings from our equity investments. We have investments in unregulated retail energy marketing services, interstate liquefied natural gas (LNG) storage operations, intrastate and interstate pipeline operations and unregulated retail propane operations. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks.

	•		Increase of $29.1 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. This represents a $90.7 million increase in operating revenues less a $61.6 million increase in cost of gas.

	•		Increase of $4.8 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2.4 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

	•		Margin for the current three-month period includes $5.2 million in billed refunds from the WNA due to weather that was 9% colder than normal, compared with billed surcharges of $12.5 million in the prior period due to weather that was 23% warmer than normal, a net decrease in margin of $17.7 million. The WNA is designed to offset the impact of unusually cold or warm weather on customer billings and margin.

	•		Decrease of $1.2 million in margin from power generation customers.

	•		Decrease of $2.2 million from the allocation and capitalization of demand costs.

	•		Decrease in other revenues of $1 million, largely due to a decrease in revenues from miscellaneous service work.

	•		Increase of $22.7 million from increased volumes due to colder weather and growth in customer base. Billed volumes increased 13.8 million dekatherms over the same period in 2002 primarily due to 19% colder weather.

	•		Increase of $29.1 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. This represents a $90.7 million increase in operating revenues less a $61.6 million increase in cost of gas.

	•		Increase of $5.8 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $1.8 million from the allocation and capitalization of demand costs.

	•		Increase of $2.6 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

	•		Margin for the current twelve-month period includes $2.2 million in billed surcharges from the WNA, compared with billed surcharges of $18.4 million in the prior period, a net decrease in margin of $16.2 million.

	•		Decrease in other revenues of $3.6 million, primarily due to decreases in revenues from late payment fees and miscellaneous service work.

	•		Increase of $1.6 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, accrual of the short-term incentive program and merit increases, including the impact of moving to a common review date for all non-bargaining unit employees.

	•		Increase of $1.8 million in the provision for uncollectibles primarily due to higher gas bills due to higher costs and colder weather.

	•		Increase of $1.3 million in employee benefits primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of changes in actuarial assumptions.

	•		Increase of $6.7 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, accrual of the short-term incentive program and merit increases, including the impact of moving to a common review date for all non-bargaining unit employees.

	•		Increase of $2.6 million in employee benefits primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of changes in actuarial assumptions.

	•		Decrease of $2.3 million in outside labor primarily due to fewer projects and vacancies in the information services area and decreases in amounts paid for outsourced meter reading, collection agency fees and pre-disconnect contact fees.

	•		Decrease of $1.6 million in the provision for uncollectibles primarily due to lower write-offs of accounts receivable compared with the similar prior period when bills were impacted by much higher gas prices and colder weather.

	•		Decrease of $.5 million in earnings from Pine Needle.

	•		Decrease of $.3 million in earnings from US Propane primarily attributable to a pre-tax loss of $1.4 million on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane.

	•		Increase of $1.1 million in interest on long-term debt from higher amounts outstanding.

	•		Decrease of $2.7 million in the portion of AFUDC attributable to borrowed funds.

	•		Decrease of $1.6 million in interest on refunds due customers due to lower balances outstanding.

	•		Decrease of $1 million in interest on short-term debt due to lower interest rates even though higher balances were outstanding.

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

	•		Ratio of net cash flows to capital expenditures,

	•		Funds from operations interest coverage,

	•		Ratio of funds from operations to average total debt and

	•		Pre-tax interest coverage.

	•		Stability of regulation in each jurisdiction in which we operate,

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

	•		Predictability of cash flows,

	•		Business strategy and management,

	1.		I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

	2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

	4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

			a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

			b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

			c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

	5.		The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

			(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

			(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and