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 April 30, 2003


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

For the Transition period from to

Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


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 June 3, 2003

Common Stock, no par value		33,440,810

Page 1 of 28 pages

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands)


					April 30,			October 31,
					2003			2002
					Unaudited			Audited

				ASSETS

Utility Plant, at original cost					$	1,764,910		$	1,730,968
	Less accumulated depreciation					601,005			572,445

			Utility plant, net			1,163,905			1,158,523


Other Physical Property (net of accumulated depreciation of $1,640 in 2003 and $1,531 in 2002)						1,055			1,078


Current Assets:
	Cash and cash equivalents					63,835			5,100
	Restricted cash					5,968			8,028
	Receivables (less allowance for doubtful accounts of $4,503 in 2003 and $810 in 2002)					107,605			37,504
	Unbilled utility revenues					40,048			—
	Gas in storage					15,328			65,688
	Deferred cost of gas					—			13,592
	Deferred income taxes					3,596			—
	Refundable income taxes					—			10,329
	Prepayments					4,597			19,215
	Other					17,984			16,330

			Total current assets			258,961			175,786


Investments, Deferred Charges and Other Assets:
		Investments in non-utility activities, at equity				90,427			80,342
		Unamortized debt expense				3,679			3,841
		Other				23,597			25,518

			Total investments, deferred charges and other assets			117,703			109,701

				Total	$	1,541,624		$	1,445,088


				CAPITALIZATION AND LIABILITIES

Capitalization:
	Common stock equity:
			Common stock		$	364,039		$	352,553
			Retained earnings			301,925			240,026
			Accumulated other comprehensive income			(1,457	)		(2,983	)

				Total common stock equity		664,507			589,596
	Long-term debt					462,000			462,000

				Total capitalization		1,126,507			1,051,596


Current Liabilities:
	Current maturities of long-term debt and sinking fund requirements					47,000			47,000
	Notes payable					—			46,500
	Accounts payable					78,797			51,093
	Deferred income taxes					—			1,384
	Income taxes accrued					17,648			—
	General taxes accrued					8,140			15,094
	Refunds due customers					29,613			15,635
	Other					28,897			28,425

			Total current liabilities			210,095			205,131


Deferred Credits and Other Liabilities:
		Accumulated deferred income taxes				169,959			158,275
		Unamortized federal investment tax credits				5,318			5,593
		Other				29,745			24,493

			Total deferred credits and other liabilities			205,022			188,361

				Total	$	1,541,624		$	1,445,088

See notes to condensed consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Statements of Consolidated Income (Unaudited)

(In thousands)


			Three Months						Six Months						Twelve Months
			Ended						Ended						Ended
			April 30						April 30						April 30

			2003			2002			2003			2002			2003			2002

Operating Revenues			$	407,774		$	293,865		$	901,265		$	582,622		$	1,150,670		$	814,893
Cost of Gas				297,760			175,297			629,557			340,852			784,939			483,376


Margin				110,014			118,568			271,708			241,770			365,731			331,517


Other Operating Expenses:
	Operations			32,368			27,681			65,971			56,631			121,761			112,831
	Maintenance			5,513			4,898			10,405			9,657			21,753			19,426
	Depreciation			15,309			14,253			30,559			28,349			59,803			54,857
	General Taxes			6,367			7,127			12,747			12,382			24,228			25,183
	Income Taxes			15,865			21,497			51,779			45,034			37,772			30,727


		Total other operating expenses		75,422			75,456			171,461			152,053			265,317			243,024


Operating Income				34,592			43,112			100,247			89,717			100,414			88,493


Other Income (Expense):
	Non-utility activities, at equity			9,995			13,975			13,768			21,751			10,950			13,307
	Allowance for equity funds used during construction			339			270			621			515			1,478			1,354
	Other			367			71			741			390			1,135			1,054
	Income taxes			(4,332	)		(5,738	)		(6,084	)		(9,309	)		(5,542	)		(6,654	)


		Total other income (expense), net of tax		6,369			8,578			9,046			13,347			8,021			9,061

Utility Interest Charges				9,961			9,845			20,297			20,049			40,237			39,225


Net Income			$	31,000		$	41,845		$	88,996		$	83,015		$	68,198		$	58,329


Average Shares of Common Stock:
		Basic		33,333			32,689			33,258			32,624			33,078			32,464
		Diluted		33,444			32,861			33,372			32,796			33,223			32,668

Earnings Per Share of Common Stock:
		Basic	$	0.93		$	1.28		$	2.68		$	2.54		$	2.06		$	1.80
		Diluted	$	0.93		$	1.27		$	2.67		$	2.53		$	2.05		$	1.79

Cash Dividends Per Share of Common Stock			$	0.415		$	0.40		$	0.815		$	0.785		$	1.615		$	1.555

See notes to condensed consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Statements of Consolidated Cash Flows (Unaudited)

(In thousands)


				Three Months						Six Months						Twelve Months
				Ended						Ended						Ended
				April 30						April 30						April 30

				2003			2002			2003			2002			2003			2002

Cash Flows from Operating Activities:
	Net income			$	31,000		$	41,845		$	88,996		$	83,015		$	68,198		$	58,329
	Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation and amortization		15,544			14,443			31,025			28,733			60,684			55,748
			Undistributed earnings from equity investments		(9,995	)		(13,975	)		(13,768	)		(21,751	)		(10,950	)		(13,307	)
			Change in operating assets and liabilities		67,643			85,599			33,944			63,548			(33,416	)		70,046
			Other, net		11,558			(3,018	)		10,338			(1,758	)		23,181			(1,615	)

	Net cash provided by operating activities				115,750			124,894			150,535			151,787			107,697			169,201


Cash Flows from Investing Activities:
	Utility construction expenditures				(17,476	)		(20,424	)		(34,555	)		(37,736	)		(76,957	)		(80,750	)
	Capital contributions to equity investments				(1,377	)		(1,737	)		(2,223	)		(2,312	)		(4,402	)		(4,865	)
	Capital distributions from equity investments				5,938			3,550			7,188			5,264			24,067			15,596
	Purchase of gas distribution system				—			—			2,153			—			(23,847	)		—
	Other				(41	)		(34	)		(78	)		(71	)		(118	)		(367	)

		Net cash used in investing activities			(12,956	)		(18,645	)		(27,515	)		(34,855	)		(81,257	)		(70,386	)


Cash Flows from Financing Activities:
	Increase (Decrease) in bank loans, net				(44,000	)		(33,000	)		(46,500	)		(32,000	)		—			(33,985	)
	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				4,463			4,407			9,313			8,537			19,322			16,508
	Dividends paid				(13,828	)		(13,071	)		(27,098	)		(25,602	)		(53,404	)		(50,466	)

		Net cash used in financing activities			(53,365	)		(41,664	)		(64,285	)		(49,065	)		(36,082	)		(39,943	)


Net Increase in Cash and Cash Equivalents					49,429			64,585			58,735			67,867			(9,642	)		58,872
Cash and Cash Equivalents at Beginning of Period					14,406			8,892			5,100			5,610			73,477			14,605


Cash and Cash Equivalents at End of Period				$	63,835		$	73,477		$	63,835		$	73,477		$	63,835		$	73,477


Cash Paid During the Period for:
	Interest			$	3,727		$	3,765		$	19,796		$	19,932		$	39,560		$	40,281
	Income taxes			$	23,710		$	29,290		$	23,892		$	29,957		$	28,109		$	32,642

See notes to condensed consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Statements of Consolidated Comprehensive Income (Unaudited)

(In thousands)


		Three Months						Six Months
		Ended April 30						Ended April 30

		2003			2002			2003			2002

Net Income		$	31,000		$	41,845		$	88,996		$	83,015
Other Comprehensive Income:
	Unrealized income (loss) on equity investments hedging activities, net of tax of $167 and $36 in the three months ended April 30, 2003 and 2002, respectively, and net of tax of $323 and ($127) in the six months ended April 30, 2003 and 2002, respectively		(254	)		(64	)		(491	)		244
	Reclassification adjustment for (income) loss included in net income, net of tax of ($520) and ($308) in the three months ended April 30, 2003 and 2002, respectively, and net of tax of ($1,320) and ($371) in the six months ended April 30, 2003 and 2002, respectively		797			495			2,017			579

Total Comprehensive Income		$	31,543		$	42,276		$	90,522		$	83,838



Reconciliation of Accumulated Other Comprehensive Income:
	Balance, beginning of period	$	(2,000	)	$	(985	)	$	(2,983	)	$	(1,377	)
	Current period reclassification to earnings		797			495			2,017			579
	Current period change		(254	)		(64	)		(491	)		244

	Balance, end of period	$	(1,457	)	$	(554	)	$	(1,457	)	$	(554	)

See notes to condensed consolidated financial statements.

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 April 30, 2003, and October 31, 2002, and the results of operations and cash flows for the three months, six months and twelve months ended April 30, 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 during the periods covered by the financial statements.

4. 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 April 30, 2003, we had $188.3 million of estimated costs of removal in excess of actual costs incurred included in accumulated depreciation in the consolidated balance sheet.

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. For the quarter ended April 30, 2003, the effect of recording unbilled revenues was a decrease in margin which resulted in a decrease in earnings of $19.4 million, or $.35 per share. For the six months and twelve months ended April 30, 2003, the effect was an increase in margin which resulted in an increase in earnings of $9.7 million, or $.18 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. We estimate that recording unbilled revenues will result in a decrease in earnings in the third quarter and an increase in earnings in the fourth quarter of fiscal year 2003, with the net effect for fiscal 2003 of a one-time, non-recurring increase in earnings per share of $.17.

6. Our business is seasonal in nature. The results of operations for the three-month and six-month periods ended April 30, 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 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:


		Three Months				Six Months				Twelve Months
		Ended				Ended				Ended
		April 30				April 30				April 30

In thousands except per share amounts		2003		2002		2003		2002		2003		2002

Net Income		$	31,000	$	41,845	$	88,996	$	83,015	$	68,198	$	58,329

Average shares of common stock outstanding for basic earnings per share			33,333		32,689		33,258		32,624		33,078		32,464
Contingently issuable shares under the long-term incentive plan			111		172		114		172		145		204

Average shares of dilutive stock			33,444		32,861		33,372		32,796		33,223		32,668

Earnings Per Share:
	Basic	$	.93	$	1.28	$	2.68	$	2.54	$	2.06	$	1.80
	Diluted	$	.93	$	1.27	$	2.67	$	2.53	$	2.05	$	1.79

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 and six months ended April 30, 2003 and 2002, are presented below:


	Domestic				Retail Energy
	Natural Gas				Marketing
Three months Ended April 30	Distribution				Services						Other						Total

In thousands	2003		2002		2003			2002			2003			2002			2003		2002

Revenues from external customers*	$	407,774	$	293,865	$	—		$	—		$	—		$	—		$	407,774	$	293,865
Margin		110,014		118,568		—			—			—			—			110,014		118,568
Operations and maintenance expenses		37,886		32,580		12			53			4			140			37,902		32,773
Operating income*		34,586		43,112		(12	)		(54	)		(5	)		(156	)		34,569		42,902
Other income		2,070		1,674		5,832			11,143			2,781			1,651			10,683		14,468
Income before income taxes		42,563		56,439		5,806			11,148			2,828			1,494			51,197		69,081
Construction expenditures		18,124		21,492		—			—			—			—			18,124		21,492
Income from non-utility activities, at equity		1,293		1,093		5,921			11,231			2,781			1,651			9,995		13,975
Investments in non-utility activities, at equity		37,150		33,696		28,405			40,948			24,872			26,379			90,427		101,023


Six Months Ended April 30
In thousands	2003		2002		2003			2002			2003			2002			2003		2002

Revenues from external customers*	$	901,265	$	582,622	$	—		$	—		$	—		$	—		$	901,265	$	582,622
Margin		271,708		241,770		—			—			—			—			271,708		241,770
Operations and maintenance expenses		76,382		66,288		29			99			11			156			76,422		66,543
Operating income*		100,241		89,668		(30	)		(107	)		(14	)		(189	)		100,197		89,372
Other income		4,075		3,527		6,974			17,360			4,049			2,140			15,098		23,027
Income before income taxes		135,802		118,185		6,917			17,221			4,140			1,952			146,859		137,358
Construction expenditures		35,749		39,776		—			—			—			—			35,749		39,776
Income from non-utility activities, at equity		2,567		2,437		7,152			17,448			4,049			1,866			13,768		21,751
Investments in non-utility activities, at equity		37,150		33,696		28,405			40,948			24,872			26,379			90,427		101,023

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

A reconciliation of net income in the condensed consolidated financial statements for the three months and six months ended April 30, 2003 and 2002, is presented below:


		Three months				Six Months
		Ended April 30				Ended April 30

In thousands		2003		2002		2003		2002

Income before income taxes for reportable segments		$	48,369	$	67,587	$	142,719	$	135,406
Income before income taxes for other non-utility activities			2,828		1,494		4,140		1,952
Income taxes			20,197		27,236		57,863		54,343

	Net income	$	31,000	$	41,845	$	88,996	$	83,015

A reconciliation of consolidated assets in the condensed consolidated financial statements as of April 30, 2003 and October 31, 2002, is presented below:


In thousands		April 30, 2003			October 31, 2002

Total assets for reportable segments		$	1,546,737		$	1,457,069
Other assets			40,416			36,133
Eliminations/Adjustments			(45,529	)		(48,114	)

	Consolidated assets	$	1,541,624		$	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.

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. As of April 30, 2003, US Propane owned 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. On May 20, 2003, Heritage completed a public offering of common units representing limited partner interests in the partnership which decreased US Propane’s ownership percentage in Heritage to 26.28%. 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 April 30, 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 non-controlling 70% interest is owned by a subsidiary of AGL Resources, Inc. (AGLR), following its purchase on March 11, 2003, of the 20% interest owned by a subsidiary of Dynegy Holdings, Inc. Key governance provisions in the LLC agreement that require unanimous approval of the members did not change with this change in membership. 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 April 30, 2003, we estimated that a portion of SouthStar’s earnings for calendar years 2002 and 2003 will be above the threshold, and that disproportionate sharing will occur. We reduced our portion of the equity earnings from SouthStar for the three months, six months and twelve months ended April 30, 2003, by $2.2 million, $3.7 million and $4.5 million, pre-tax, respectively, to reflect our estimates that our earnings from SouthStar will be at a level of approximately 22 to 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, which have not been agreed to by the members, our actual pre-tax earnings reductions due to disproportionate sharing could differ from our estimates.

SouthStar utilizes financial contracts to hedge the price of natural gas. These financial contracts (futures, options and swaps) are considered to be derivatives and fair value is based on selected market indices. Those derivative transactions that qualify as cash-flow hedges are reflected in SouthStar’s balance sheet at the fair values of the open positions, with the corresponding unrealized gain or loss included in “Accumulated other comprehensive income.” 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 began performing in-house those activities previously conducted by Dynegy.

Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s 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. Effective April 1, 2003, the letter of credit was increased to $15 million.

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 April 30, 2003, we have made capital contributions to Greenbrier totaling $9 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On February 28, 2003, the FERC issued its Final Environmental Impact Statement. On April 9, the FERC approved the pipeline and issued its final certificate. Greenbrier filed its acceptance of the certificate with the FERC on May 8. As a result of uncertainty in the demand for pipeline services, the members of Greenbrier are evaluating options on the pipeline’s size, scope and timing to optimize the project’s economics and to best serve the market.

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 $2.6 million and $2.8 million for the three months ended April 30, 2003 and 2002, respectively, $5.3 million and $5.5 million for the six months ended April 30, 2003 and 2002, respectively, and $10.7 million and $11 million for the twelve months ended April 30, 2003 and 2002, respectively. As of April 30, 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 April 30, 2003 and 2002, $.7 million for the six months ended April 30, 2003 and 2002, and $1.5 million for the twelve months ended April 30, 2003 and 2002. As of April 30, 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 $.4 million and $2.8 million for the three months ended April 30, 2003 and 2002, respectively, $.9 million and $4.5 million for the six months ended April 30, 2003 and 2002, respectively, and $7.2 million and $12 million for the twelve months ended April 30, 2003 and 2002, respectively. As of April 30, 2003, and 2002, SouthStar owed us zero and $1.3 million, respectively.

Summarized Financial Information

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the three months and six months ended March 31, 2003 and 2002, is presented below.


	Three months				Six Months
	Ended March 31				Ended March 31

In thousands	2003		2002		2003		2002

Revenues	$	4,281	$	4,281	$	8,562	$	8,562
Gross profit		—		—		—		—
Income before income taxes		1,965		2,349		4,246		4,727
Total assets		103,182		104,967		103,182		104,967

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for the three months and six months ended March 31, 2003 and 2002, is presented below.


	Three months				Six Months
	Ended March 31				Ended March 31

In thousands	2003		2002		2003		2002

Revenues	$	5,250	$	4,949	$	10,238	$	10,021
Gross profit		—		—		—		—
Income before income taxes		2,465		2,664		4,905		5,390
Total assets		116,237		112,104		116,237		112,104

Summarized unaudited financial information for Heritage Propane for 100% of Heritage Propane for the three months and six months ended February 28, 2003 and 2002, as filed in its Form 10-Q with the Securities and Exchange Commission, is presented below.


	Three months				Six Months
	Ended February 28				Ended February 28

In thousands	2003		2002		2003		2002

Revenues	$	329,044	$	229,635	$	502,527	$	391,738
Gross profit		200,624		132,492		317,087		234,360
Income before income taxes		50,672		30,130		51,812		25,351
Total assets		791,332		779,640		791,332		779,640

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for the three months and six months ended March 31, 2003 and 2002, is provided below.


	Three months				Six Months
	Ended March 31				Ended March 31

In thousands	2003		2002		2003		2002

Revenues	$	291,892	$	230,288	$	481,575	$	402,359
Gross profit		45,460		59,828		71,473		95,057
Income before income taxes		26,912		37,438		34,840		58,160
Total assets		174,937		167,811		174,937		167,811

Summarized unaudited financial information provided to us by Greenbrier for 100% of Greenbrier for the three months and six months ended March 31, 2003 and 2002, is presented below.


	Three months				Six Months
	Ended March 31				Ended March 31

In thousands	2003		2002		2003		2002

Revenues	$	—	$	—	$	—	$	—
Gross profit		—		—		—		—
Income before income taxes		71		87		183		89
Total assets		26,838		12,686		26,838		12,686

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 cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

As of April 30, 2003, we have purchased and sold financial call options for natural gas for our Tennessee gas purchase portfolio for December 2003 and February 2004. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing unused 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 costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders, subject to the annual cap. The net overall annual performance results are collected from or refunded to customers, subject to the cap.

As of April 30, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for June 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 subject to the company following the provisions of the plan. This plan operates off of historical pricing deciles 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 hedging portfolio is diversified over a rolling 24 months with a short-term focus (one to 12 months) and a long-term focus (13 to 24 months). Hedges are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis. The plan is very structured in composition and designed to limit subjective discretion in making hedging decisions.

As of April 30, 2003, we have purchased financial call options for natural gas for our North Carolina gas purchase portfolio for June 2003 through October 2003. Costs associated with our North Carolina hedging program are not pre-approved by the NCUC but will be treated as gas costs subject to the annual gas cost prudency review. To date, we have recovered 100% of gas costs subject to 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.

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 service areas 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.

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

• The capital-intensive nature of our business, 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 firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts 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 reduce 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 the assumptions underlying these forward-looking statements to be reasonable, there can be no assurance that these statements will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “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 by reference 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 by reference 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.

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 at the end of July or August 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. On April 29, a hearing was held before the NCUC. The outcome of this proceeding cannot be determined at this time.

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 condensed 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 April 30, 2003, outstanding short-term borrowings under committed bank lines of credit totaling $150 million ranged from zero to $44 million, and interest rates ranged from 1.655% to 1.875%. During the six months ended April 30, 2003, outstanding short-term borrowings ranged from zero to $86 million, and interest rates ranged from 1.655% to 2.04%. As of April 30, 2003, we had additional uncommitted lines of credit totaling $73 million on a no fee and as needed, if available, basis. Effective May 1, 2003, committed bank lines of credit increased to $200 million with additional uncommitted lines of credit of $68 million.

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 April 30, 2003, 57% of our sales and transportation revenues were from residential customers and 30% 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.

Given the current prices of natural gas compared with alternate fuels, some industrial customers have

switched to alternate fuels. We expect that some industrial customers will continue to switch to alternate fuels for the near term.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to increased purchases of natural gas supplies required to serve additional customer demand during cold weather and to refill storage. 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. Given the close balance that exists between supply and demand, gas prices could remain high for the next several years. If wholesale gas prices remain high, we could incur more short-term debt to pay our natural gas suppliers and satisfy other operating costs since collections from customers could be slower and customers may not be able to pay their gas 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 April 30, 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 April 30, 2003. We expect to sell debt and equity securities to fund our proposed acquisition of NCNG and EasternNC.

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, 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, under a commercial paper program, that will be refinanced within approximately three months through the issuance of long-term debt and equity securities. As of May 30, 2003, we have received commitments from lenders for a $450 million credit facility to backstop the commercial paper program. While this acquisition will be positive in the long run as we expand our customer base in North Carolina, it will 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. We believe our risk exposure to the financial condition of the pipelines and marketers 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 April 30, 2003. Accounts payable and accounts receivable increased during this same period 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 $40 million at April 30, 2003.

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 April 30, 2003, were $18.1 million, compared with $21.5 million

for the same period in 2002. Utility construction expenditures for the six months ended April 30, 2003, were $35.7 million, compared with $39.7 million for the same period in 2002. Utility construction expenditures for the twelve-month period ended April 30, 2003, were $79.7 million, compared with $85.9 million for the same period in 2002. Due to projected 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 April 30, 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 $53.4 million.

Our expected future contractual obligations as of April 30, 2003, for long-term debt, pipeline and storage capacity and gas supply and operating leases are as follows:


In millions	Payments Due by Period

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

Contractual Obligations
Long-term debt	$	509,000	$	47,000	$	37,000	$	—	$	425,000
Pipeline and storage capacity and gas supply*		811,952		95,633		239,039		142,662		334,618
Operating leases		14		4		7		1		2

*100% recoverable due to purchased gas cost recovery mechanisms.

As of April 30, 2003, our capitalization consisted of 41% in long-term debt and 59% 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 in the appropriate months.

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

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 and if performance measures are met, awards are distributed in the form of shares of common stock and cash withheld to pay taxes. 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, six months and twelve months ended April 30, 2003, compared with similar periods in 2002.

Margin (Operating Revenues less Cost of Gas)

Margin for the three months ended April 30, 2003, decreased $8.6 million compared with the same period in 2002 primarily for the reasons listed below.

• Decrease of $19.4 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 $50.6 million decrease in operating revenues less a $31.2 million decrease in cost of gas.

• Margin for the current three-month period includes $5 million in billed refunds from the WNA compared with billed surcharges of $7.4 million in the prior period, a net decrease in margin of $12.4 million. The WNA is designed to offset the impact of unusually cold or warm weather on customer billings and margin.

• Decrease of $.4 million from secondary market transactions.

• Decrease of $.2 million from the allocation and capitalization of demand costs.

These decreases were partially offset by the following increases.

• Increase of $14.1 million due to an increase in volumes of 5.5 million dekatherms due to 4% colder weather and growth in customer base.

• Increase of $7.2 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2.2 million from the acquisition of North Carolina Gas Service effective September 30, 2002.

• Increase of $.7 million in other revenues primarily due to an increase in revenues from late payment fees.

Margin for the six months ended April 30, 2003, increased $29.9 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $35.6 million due to an increase in volumes billed of 14.5 million dekatherms due to 25% colder weather and growth in customer base.

• Increase of $9.7 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 $40 million increase in operating revenues less a $30.3 million increase in cost of gas.

• Increase of $13 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $4.5 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

• Increase in other revenues of $.9 million, largely due to an increase in revenues from late payment fees.

These increases were partially offset by the following decreases.

• Margin for the current six-month period includes $10.2 million in billed refunds from the WNA compared with billed surcharges of $19.8 million in the prior period, a net decrease in margin of $30 million.

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

• Decrease of $2.4 million from the allocation and capitalization of demand costs.

Margin for the twelve months ended April 30, 2003, increased $34.2 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $34.9 million from increased volumes due to colder weather and growth in customer base. Billed volumes increased 18.9 million dekatherms over the same period in 2002 primarily due to 22% colder weather.

• Increase of $9.7 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 $40 million increase in operating revenues less a $30.3 million increase in cost of gas.

• Increase of $14.6 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2 million from the allocation and capitalization of demand costs.

• Increase of $4.8 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 $10.2 million in billed refunds from the WNA, compared with billed surcharges of $19.8 million in the prior period, a net decrease in margin of $30 million.

• Decrease of $1.4 million in margin from power generation customers.

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 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 April 30, 2003, increased $5.3 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, merit increases, accrual of the short-term incentive program and accrual of the long-term incentive plan.

• Increase of $.6 million in risk insurance primarily due to higher renewal premiums.

• Increase of $.7 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

• Increase of $1.8 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 six months ended April 30, 2003, increased $10.1 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $3.1 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accrual of the short-term incentive program and accrual of the long-term incentive plan.

• Increase of $2 million in the provision for uncollectibles primarily due to higher gas bills due to higher costs and colder weather and anticipated higher charge-offs.

• Increase of $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 $1.1 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

• Increase of $.8 million in risk insurance primarily due to higher renewal premiums.

Operations and maintenance expenses for the twelve months ended April 30, 2003, increased $11.3 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, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accrual of the short-term incentive program and accrual of the long-term incentive plan.

• Increase of $4.9 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 $1.1 million in risk insurance primarily due to higher renewal premiums.

• Increase of $1.1 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

These increases were partially offset by the following decreases.

• Decrease of $1 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 $1.4 million in the provision for uncollectibles primarily due to lower write-offs of accounts receivable compared with the similar prior period when bills and subsequent write-offs were impacted by much higher gas prices and colder weather.

Depreciation

Depreciation expense for the three months, six months and twelve months ended April 30, 2003, increased over similar prior periods due to the growth of plant in service. Due to the continued growth in 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 April 30, 2003, decreased $.8 million compared with the same period in 2002 primarily due to a decrease of $.7 million in property taxes.

General taxes for the six months ended April 30, 2003, increased $.4 million compared with the same period in 2002 primarily due to an increase of $.3 million in Tennessee gross receipts taxes.

General taxes for the twelve months ended April 30, 2003, decreased $1 million compared with the same period in 2002 primarily due to a decrease of $2 million in property taxes, partially offset by increases of $.3 million in franchise taxes, $.5 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 April 30, 2003, decreased $4 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $5.3 million. This decrease was partially offset by an increase of $1.1 million in earnings from US Propane.

Income from equity investee earnings for the six months ended April 30, 2003, decreased $8 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $10.3 million. This decrease was partially offset by an increase of $2.1 million in earnings from US Propane.

Income from equity investee earnings for the twelve months ended April 30, 2003, decreased $2.4 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $3.4 million. This decrease was partially offset by an increase of $.6 million in earnings from US Propane which included 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, six months and twelve months ended April 30, 2003, compared with similar periods in 2002, increased slightly by $.1 million, for all three periods. 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 April 30, 2003, increased $.3 million compared with the same period in 2002 primarily due to increases in earnings from jobbing operations and in interest income.

Other for the six months ended April 30, 2003, increased $.4 million compared with the same period in 2002 primarily due to increases in earnings from jobbing operations and in interest income.

Other for the twelve months ended April 30, 2003, increased $.1 million compared with the same period in 2002 primarily due to increases in earnings from jobbing operations and in interest income and a decrease in charitable contributions due to timing.

Utility Interest Charges

Utility interest charges for the three months ended April 30, 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 $.3 million in interest on refunds due customers due to lower balances outstanding.

Utility interest charges for the six months ended April 30, 2003, increased $.2 million compared with the same period in 2002 primarily due to a decrease of $1 million in the portion of AFUDC attributable to borrowed funds, partially offset by a decrease of $.7 million in interest on refunds due customers due to lower balances outstanding.

Utility interest charges for the twelve months ended April 30, 2003, increased $1 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $.7 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 $1.9 million in interest on refunds due customers due to lower balances outstanding.

• Decrease of $.6 million in interest on short-term debt due to lower interest rates.

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 April 30, 2003, we had no short-term debt outstanding. During the quarter, short-term debt ranged from zero to $44 million with a weighted average interest rate of 1.78%. 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 as of April 30, 2003, about our long-term debt that is sensitive to changes in interest rates.


	Expected Maturity Date																			Fair Value at
																				April 30,
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		$	584,000
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,

• Industry position and

• Contingencies.

As of April 30, 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 16.

Item 4. Controls and Procedures

Within 90 days prior to 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.

Part II. Other Information

Item 1. Legal Proceedings

There are a number of lawsuits pending against us in the ordinary course of business for damages alleged to have been caused by our employees. We have liability insurance which we believe is adequate to cover any material judgments that may result from these lawsuits.

Item 2. Changes in Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

Regulatory Proceedings

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 at the end of July or August 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. On April 29, a hearing was held before the NCUC. The outcome of this proceeding cannot be determined at this time.

On April 29, 2003, we filed an application with the Tennessee Regulatory Authority requesting an annual increase in revenues of $18.5 million, an increase of 8.6%. In addition, we requested changes in cost allocations and rate design and changes in tariffs and service regulations. We anticipate that a hearing will be set for some time in September. We are unable to predict the outcome of this proceeding at this time.

Item 6. Exhibits and Reports on Form 8-K


(a)	Exhibits –

	10.1	Employment Agreement between the Company and Kim R. Cocklin, dated February 3, 2003.

	10.2	Severance Agreement between the Company and Kim R. Cocklin, dated February 3, 2003.

	12	Computation of Ratio of Earnings to Fixed Charges.

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

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

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


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

(b) Reports on Form 8-K –

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.

Outside of the period, on May 30, 2003, we filed a report on Form 8-K regarding the issuance of two press releases to report (1) second quarter results, declaration of dividend and earnings guidance for 2003 and (2) retirement of a board member.

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	June 12, 2003	/s/ David J. Dzuricky

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

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

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

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 April 30, 2003, and October 31, 2002, and the results of operations and cash flows for the three months, six months and twelve months ended April 30, 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 during the periods covered by the financial statements.

4.		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 April 30, 2003, we had $188.3 million of estimated costs of removal in excess of actual costs incurred included in accumulated depreciation in the consolidated balance sheet.

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. For the quarter ended April 30, 2003, the effect of recording unbilled revenues was a decrease in margin which resulted in a decrease in earnings of $19.4 million, or $.35 per share. For the six months and twelve months ended April 30, 2003, the effect was an increase in margin which resulted in an increase in earnings of $9.7 million, or $.18 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. We estimate that recording unbilled revenues will result in a decrease in earnings in the third quarter and an increase in earnings in the fourth quarter of fiscal year 2003, with the net effect for fiscal 2003 of a one-time, non-recurring increase in earnings per share of $.17.

6.		Our business is seasonal in nature. The results of operations for the three-month and six-month periods ended April 30, 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 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 and six months ended April 30, 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. As of April 30, 2003, US Propane owned 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. On May 20, 2003, Heritage completed a public offering of common units representing limited partner interests in the partnership which decreased US Propane’s ownership percentage in Heritage to 26.28%. 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 April 30, 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 non-controlling 70% interest is owned by a subsidiary of AGL Resources, Inc. (AGLR), following its purchase on March 11, 2003, of the 20% interest owned by a subsidiary of Dynegy Holdings, Inc. Key governance provisions in the LLC agreement that require unanimous approval of the members did not change with this change in membership. 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 April 30, 2003, we estimated that a portion of SouthStar’s earnings for calendar years 2002 and 2003 will be above the threshold, and that disproportionate sharing will occur. We reduced our portion of the equity earnings from SouthStar for the three months, six months and twelve months ended April 30, 2003, by $2.2 million, $3.7 million and $4.5 million, pre-tax, respectively, to reflect our estimates that our earnings from SouthStar will be at a level of approximately 22 to 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, which have not been agreed to by the members, our actual pre-tax earnings reductions due to disproportionate sharing could differ from our estimates.

		SouthStar utilizes financial contracts to hedge the price of natural gas. These financial contracts (futures, options and swaps) are considered to be derivatives and fair value is based on selected market indices. Those derivative transactions that qualify as cash-flow hedges are reflected in SouthStar’s balance sheet at the fair values of the open positions, with the corresponding unrealized gain or loss included in “Accumulated other comprehensive income.” 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 began performing in-house those activities previously conducted by Dynegy.

		Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s 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. Effective April 1, 2003, the letter of credit was increased to $15 million.

		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 April 30, 2003, we have made capital contributions to Greenbrier totaling $9 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On February 28, 2003, the FERC issued its Final Environmental Impact Statement. On April 9, the FERC approved the pipeline and issued its final certificate. Greenbrier filed its acceptance of the certificate with the FERC on May 8. As a result of uncertainty in the demand for pipeline services, the members of Greenbrier are evaluating options on the pipeline’s size, scope and timing to optimize the project’s economics and to best serve the market.

		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 $2.6 million and $2.8 million for the three months ended April 30, 2003 and 2002, respectively, $5.3 million and $5.5 million for the six months ended April 30, 2003 and 2002, respectively, and $10.7 million and $11 million for the twelve months ended April 30, 2003 and 2002, respectively. As of April 30, 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 April 30, 2003 and 2002, $.7 million for the six months ended April 30, 2003 and 2002, and $1.5 million for the twelve months ended April 30, 2003 and 2002. As of April 30, 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 $.4 million and $2.8 million for the three months ended April 30, 2003 and 2002, respectively, $.9 million and $4.5 million for the six months ended April 30, 2003 and 2002, respectively, and $7.2 million and $12 million for the twelve months ended April 30, 2003 and 2002, respectively. As of April 30, 2003, and 2002, SouthStar owed us zero and $1.3 million, respectively.

		Summarized Financial Information

		Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the three months and six months ended March 31, 2003 and 2002, 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 cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

		As of April 30, 2003, we have purchased and sold financial call options for natural gas for our Tennessee gas purchase portfolio for December 2003 and February 2004. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing unused 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 costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders, subject to the annual cap. The net overall annual performance results are collected from or refunded to customers, subject to the cap.

		As of April 30, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for June 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 subject to the company following the provisions of the plan. This plan operates off of historical pricing deciles 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 hedging portfolio is diversified over a rolling 24 months with a short-term focus (one to 12 months) and a long-term focus (13 to 24 months). Hedges are executed within the parameters of the matrix compared with NYMEX monthly prices as reviewed on a daily basis. The plan is very structured in composition and designed to limit subjective discretion in making hedging decisions.

		As of April 30, 2003, we have purchased financial call options for natural gas for our North Carolina gas purchase portfolio for June 2003 through October 2003. Costs associated with our North Carolina hedging program are not pre-approved by the NCUC but will be treated as gas costs subject to the annual gas cost prudency review. To date, we have recovered 100% of gas costs subject to 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 service areas 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.

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

	•		The capital-intensive nature of our business, 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 firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts 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 reduce 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.

	•		Decrease of $19.4 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 $50.6 million decrease in operating revenues less a $31.2 million decrease in cost of gas.

	•		Margin for the current three-month period includes $5 million in billed refunds from the WNA compared with billed surcharges of $7.4 million in the prior period, a net decrease in margin of $12.4 million. The WNA is designed to offset the impact of unusually cold or warm weather on customer billings and margin.

	•		Decrease of $.4 million from secondary market transactions.

	•		Decrease of $.2 million from the allocation and capitalization of demand costs.

	•		Increase of $14.1 million due to an increase in volumes of 5.5 million dekatherms due to 4% colder weather and growth in customer base.

	•		Increase of $7.2 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2.2 million from the acquisition of North Carolina Gas Service effective September 30, 2002.

	•		Increase of $.7 million in other revenues primarily due to an increase in revenues from late payment fees.

	•		Increase of $35.6 million due to an increase in volumes billed of 14.5 million dekatherms due to 25% colder weather and growth in customer base.

	•		Increase of $9.7 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 $40 million increase in operating revenues less a $30.3 million increase in cost of gas.

	•		Increase of $13 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $4.5 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

	•		Increase in other revenues of $.9 million, largely due to an increase in revenues from late payment fees.

	•		Margin for the current six-month period includes $10.2 million in billed refunds from the WNA compared with billed surcharges of $19.8 million in the prior period, a net decrease in margin of $30 million.

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

	•		Decrease of $2.4 million from the allocation and capitalization of demand costs.

	•		Increase of $34.9 million from increased volumes due to colder weather and growth in customer base. Billed volumes increased 18.9 million dekatherms over the same period in 2002 primarily due to 22% colder weather.

	•		Increase of $9.7 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 $40 million increase in operating revenues less a $30.3 million increase in cost of gas.

	•		Increase of $14.6 million from increased customer charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2 million from the allocation and capitalization of demand costs.

	•		Increase of $4.8 million from the acquisition of North Carolina Gas Service, effective September 30, 2002.

	•		Margin for the current twelve-month period includes $10.2 million in billed refunds from the WNA, compared with billed surcharges of $19.8 million in the prior period, a net decrease in margin of $30 million.

	•		Decrease of $1.4 million in margin from power generation customers.

	•		Increase of $1.6 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, merit increases, accrual of the short-term incentive program and accrual of the long-term incentive plan.

	•		Increase of $.6 million in risk insurance primarily due to higher renewal premiums.

	•		Increase of $.7 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

	•		Increase of $1.8 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 $3.1 million in payroll primarily due to the addition of employees from the acquisition of North Carolina Gas Service, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accrual of the short-term incentive program and accrual of the long-term incentive plan.

	•		Increase of $2 million in the provision for uncollectibles primarily due to higher gas bills due to higher costs and colder weather and anticipated higher charge-offs.

	•		Increase of $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 $1.1 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

	•		Increase of $.8 million in risk insurance primarily due to higher renewal premiums.

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

	•		Increase of $4.9 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 $1.1 million in risk insurance primarily due to higher renewal premiums.

	•		Increase of $1.1 million in outside consultants fees primarily related to the pending North Carolina Natural Gas acquisition.

	•		Decrease of $1 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 $1.4 million in the provision for uncollectibles primarily due to lower write-offs of accounts receivable compared with the similar prior period when bills and subsequent write-offs were impacted by much higher gas prices and colder weather.

	•		Increase of $.7 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 $1.9 million in interest on refunds due customers due to lower balances outstanding.

	•		Decrease of $.6 million in interest on short-term debt due to lower interest rates.

	•		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,

	•		Industry position and

	•		Contingencies.

(b)		Reports on Form 8-K –

		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.

		Outside of the period, on May 30, 2003, we filed a report on Form 8-K regarding the issuance of two press releases to report (1) second quarter results, declaration of dividend and earnings guidance for 2003 and (2) retirement of a board member.