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 July 31, 2003

or

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

For the Transition period from ____________ to ____________

Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

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

1915 Rexford Road, Charlotte, North Carolina		28211

(Address of principal executive offices)		(Zip Code)

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

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

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

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 September 2, 2003

Common Stock, no par value		33,564,851

Page 1 of 31 Pages

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

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


					July 31,			October 31,
					2003			2002

ASSETS
Utility Plant, at original cost					$	1,783,891		$	1,730,968
	Less accumulated depreciation					615,574			572,445

			Utility plant, net			1,168,317			1,158,523

Other Physical Property (net of accumulated depreciation of $1,687 in 2003 and $1,531 in 2002)						1,022			1,078

Current Assets:
	Cash and cash equivalents					7,511			5,100
	Restricted cash					6,022			8,028
	Receivables (less allowance for doubtful accounts of $1,363 in 2003 and $810 in 2002)					64,605			37,504
	Unbilled utility revenues					11,074			—
	Gas in storage					68,465			65,688
	Deferred cost of gas					—			13,592
	Deferred income taxes					2,043			—
	Refundable income taxes					25,849			10,329
	Prepayments					18,655			19,215
	Other					17,613			16,330

			Total current assets			221,837			175,786

Investments, Deferred Charges and Other Assets:
		Investments in non-utility activities, at equity				90,534			80,342
		Unamortized debt expense				3,682			3,841
		Other				25,415			25,518

			Total investments, deferred charges and other assets			119,631			109,701

				Total	$	1,510,807		$	1,445,088

CAPITALIZATION AND LIABILITIES
Capitalization:
	Common stock equity:
			Common stock		$	368,611		$	352,553
			Retained earnings			278,366			240,026
			Accumulated other comprehensive income			(1,833	)		(2,983	)

				Total common stock equity		645,144			589,596
	Long-term debt					460,000			462,000

				Total capitalization		1,105,144			1,051,596

Current Liabilities:
	Current maturities of long-term debt and sinking fund requirements					2,000			47,000
	Notes payable					45,000			46,500
	Accounts payable					71,175			51,093
	Deferred income taxes					—			1,384
	Income taxes accrued					8,895			—
	General taxes accrued					12,043			15,094
	Refunds due customers					14,546			15,635
	Other					19,438			28,425

			Total current liabilities			173,097			205,131

Deferred Credits and Other Liabilities:
	Accumulated deferred income taxes					187,179			158,275
	Unamortized federal investment tax credits					5,180			5,593
	Other					40,207			24,493

			Total deferred credits and other liabilities			232,566			188,361

				Total	$	1,510,807		$	1,445,088

See notes to condensed consolidated financial statements.

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


			Three Months						Nine Months						Twelve Months
			Ended						Ended						Ended
			July 31						July 31						July 31

			2003			2002			2003			2002			2003			2002

Operating Revenues			$	140,132		$	127,928		$	1,041,397		$	710,550		$	1,162,876		$	821,041
Cost of Gas				90,832			80,066			720,389			420,918			795,706			485,300

Margin				49,300			47,862			321,008			289,632			367,170			335,741


Other Operating Expenses:
	Operations			31,715			27,013			97,686			83,644			126,463			111,042
	Maintenance			5,977			4,902			16,382			14,559			22,828			19,353
	Depreciation			15,336			14,440			45,895			42,789			60,698			56,293
	General Taxes			6,032			5,541			18,779			17,923			24,720			25,434
	Income Taxes			(7,890	)		(5,662	)		43,889			39,372			35,653			32,718


		Total other operating expenses		51,170			46,234			222,631			198,287			270,362			244,840


Operating Income				(1,870	)		1,628			98,377			91,345			96,808			90,901


Other Income (Expense):
	Non-utility activities, at equity			2,323			(1,975	)		16,092			20,050			15,249			22,328
	Allowance for equity funds used during construction			346			231			967			746			1,318			1,240
	Non-operating income			782			618			1,938			1,182			1,993			1,995
	Non-operating expense			(140	)		(105	)		(556	)		(553	)		(730	)		(915	)
	Income taxes			(1,345	)		487			(7,429	)		(8,822	)		(7,265	)		(10,186	)


		Total other income (expense), net of tax		1,966			(744	)		11,012			12,603			10,565			14,462

Utility Interest Charges				9,773			9,861			30,070			29,910			39,875			39,206


Net Income				($9,677	)		($8,977	)	$	79,319		$	74,038		$	67,498		$	66,157

Average Shares of Common Stock:
		Basic		33,461			32,822			33,327			32,691			33,239			32,610
		Diluted		33,461			32,822			33,439			32,863			33,368			32,798

Earnings Per Share of Common Stock:
		Basic		($0.29	)		($0.27	)	$	2.38		$	2.26		$	2.03		$	2.03
		Diluted		($0.29	)		($0.27	)	$	2.37		$	2.25		$	2.02		$	2.02

Cash Dividends Per Share of Common Stock			$	0.415		$	0.40		$	1.23		$	1.185		$	1.63		$	1.57

See notes to condensed consolidated financial statements.

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


			Three Months						Nine Months						Twelve Months
			Ended						Ended						Ended
			July 31						July 31						July 31

			2003			2002			2003			2002			2003			2002

Cash Flows from Operating Activities:
	Net income			($9,677	)		($8,977	)	$	79,319		$	74,038		$	67,498		$	66,157
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization		15,578			14,648			46,603			43,381			61,614			57,074
		Undistributed earnings from equity investments		(2,323	)		1,975			(16,092	)		(20,050	)		(15,249	)		(22,328	)
		Change in operating assets and liabilities		(47,839	)		(70,381	)		(13,895	)		(6,560	)		(10,898	)		14,824
		Other, net		16,486			15,667			26,824			13,909			24,000			(3,837	)

	Net cash provided by (used in) operating activities			(27,775	)		(47,068	)		122,759			104,718			126,965			111,890

Cash Flows from Investing Activities:
	Utility construction expenditures			(18,976	)		(22,489	)		(53,531	)		(60,225	)		(73,418	)		(79,344	)
	Capital contributions to equity investments			—			(917	)		(2,223	)		(3,229	)		(3,485	)		(5,626	)
	Capital distributions from equity investments			1,752			14,780			8,940			20,045			11,039			21,913
	Purchase of gas distribution system			—			—			2,153			—			(23,847	)		—
	Other			(15	)		(32	)		(92	)		(104	)		(101	)		(202	)

	Net cash used in investing activities			(17,239	)		(8,658	)		(44,753	)		(43,513	)		(89,812	)		(63,259	)

Cash Flows from Financing Activities:
	Increase (decrease) in bank loans, net			45,000			—			(1,500	)		(32,000	)		45,000			(69,500	)
	Issuance of long-term debt			—			—			—			—			—			60,000
	Retirement of long-term debt			(47,000	)		(2,000	)		(47,000	)		(2,000	)		(47,000	)		(2,000	)
	Issuance of common stock through dividend reinvestment and employee stock plans			4,572			5,048			13,885			13,586			18,846			17,419
	Dividends paid			(13,882	)		(13,122	)		(40,980	)		(38,724	)		(54,165	)		(51,181	)

	Net cash used in financing activities			(11,310	)		(10,074	)		(75,595	)		(59,138	)		(37,319	)		(45,262	)


Net Increase (Decrease) in Cash and Cash Equivalents				(56,324	)		(65,800	)		2,411			2,067			(166	)		3,369

Cash and Cash Equivalents at Beginning of Period				63,835			73,477			5,100			5,610			7,677			4,308


Cash and Cash Equivalents at End of Period			$	7,511		$	7,677		$	7,511		$	7,677		$	7,511		$	7,677


Cash Paid During the Period for:
	Interest		$	16,099		$	16,057		$	35,895		$	35,989		$	39,602		$	39,132
	Income taxes		$	354		$	12		$	32,632		$	29,969		$	36,841		$	32,659

See notes to condensed consolidated financial statements.

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


		Three Months						Nine Months
		Ended July 31						Ended July 31

		2003			2002			2003			2002

Net Income			($9,677	)		($8,977	)	$	79,319		$	74,038
Other Comprehensive Income:
	Unrealized loss of equity investments hedging activities, net of tax of $318 and $416 in the three months ended July 31, 2003 and 2002, respectively, and net of tax of $642 and $289 in the nine months ended July 31, 2003 and 2002, respectively		(493	)		(647	)		(984	)		(403	)
	Reclassification adjustment for loss of equity investments hedging activities included in net income, net of tax of ($75) and ($128) in the three months ended July 31, 2003 and 2002, respectively, and net of tax of ($1,395) and ($499) in the nine months ended July 31, 2003 and 2002, respectively		117			198			2,134			777

Total Comprehensive Income			($10,053	)		($9,426	)	$	80,469		$	74,412


Reconciliation of Accumulated Other Comprehensive Income:
	Balance, beginning of period		($1,457	)		($554	)		($2,983	)		($1,377	)
	Current period reclassification to earnings		117			198			2,134			777
	Current period change		(493	)		(647	)		(984	)		(403	)

	Balance, end of period		($1,833	)		($1,003	)		($1,833	)		($1,003	)

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 July 31, 2003 and October 31, 2002, and the results of operations and cash flows for the three months, nine months and twelve months ended July 31, 2003 and 2002.

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

3. We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we have capitalized certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from 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 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. Our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. The applicable regulatory commissions approve these depreciation rates. We accrue estimated costs of removal of long-lived assets through depreciation expense, with a corresponding credit to accumulated depreciation. Because these estimated removal costs meet the requirements of Statement 71, these accumulated costs are not classified as liabilities. As of July 31, 2003, we had $192.5 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 July 31, 2003, the effect of recording unbilled revenues was a decrease in margin which resulted in a decrease in earnings of $7 million, or $.13 per share. For the nine months and twelve months ended July 31, 2003, the effect was an increase in margin which resulted in an increase in earnings of $2.6 million, or $.05 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 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 nine-month periods ended July 31, 2003, do not necessarily reflect the results to be expected for the full year.

7. Basic earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur when common stock equivalents are added to 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						Nine Months				Twelve Months
		Ended						Ended				Ended
		July 31						July 31				July 31

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

Net Income		$	(9,677	)	$	(8,977	)	$	79,319	$	74,038	$	67,498	$	66,157

Average shares of common stock outstanding for basic earnings per share			33,461			32,822			33,327		32,691		33,239		32,610
Contingently issuable shares under the long-term incentive plan (a)			—			—			112		172		129		188

Average shares of dilutive stock			33,461			32,822			33,439		32,863		33,368		32,798


Earnings Per Share:
	Basic	$	(.29	)	$	(.27	)	$	2.38	$	2.26	$	2.03	$	2.03
	Diluted	$	(.29	)	$	(.27	)	$	2.37	$	2.25	$	2.02	$	2.02

(a) For the three months ended July 31, 2003 and 2002, the inclusion of 111 and 172 contingently issuable shares, respectively, would be antidilutive.

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.

Operations by segment for the three months and nine months ended July 31, 2003 and 2002, are presented below:


	Domestic						Retail Energy
	Natural Gas						Marketing
Three months Ended July 31	Distribution						Services						Other						Total

In thousands	2003			2002			2003			2002			2003			2002			2003			2002

Revenues from external customers*	$	140,132		$	127,928		$	—		$	—		$	—		$	—		$	140,132		$	127,928
Margin		49,300			47,862			—			—			—			—			49,300			47,862
Operations and maintenance expenses		37,710			31,915			(50	)		1			4			9			37,664			31,925
Operating income*		(9,779	)		(4,024	)		46			(18	)		(5	)		(23	)		(9,738	)		(4,065	)
Other income		2,185			2,141			2,351			(1,098	)		(1,298	)		(2,242	)		3,238			(1,199	)
Income before income taxes		(17,366	)		(11,742	)		2,385			(1,130	)		(1,241	)		(2,254	)		(16,222	)		(15,126	)
Construction expenditures		19,601			23,385			—			—			—			—			19,601			23,385
Income from non-utility activities, at equity		1,181			1,276			2,440			(1,009	)		(1,298	)		(2,242	)		2,323			(1,975	)
Investments in non-utility activities, at equity		36,869			33,964			30,610			26,479			23,055			23,653			90,534			84,096

Nine months Ended July 31

In thousands	2003			2002			2003			2002			2003			2002			2003			2002

Revenues from external customers*	$	1,041,397		$	710,550		$	—		$	—		$	—		$	—		$	1,041,397		$	710,550
Margin		321,008			289,632			—			—			—			—			321,008			289,632
Operations and maintenance expenses		114,092			98,204			(21	)		100			15			165			114,086			98,469
Operating income*		142,241			130,677			16			(125	)		(18	)		(211	)		142,239			130,341
Other income		6,259			5,668			9,326			16,262			2,751			(103	)		18,336			21,827
Income before income taxes		118,436			106,443			9,302			16,092			2,899			(303	)		130,637			122,232
Construction expenditures		55,350			63,160			—			—			—			—			55,350			63,160
Income from non-utility activities, at equity		3,749			3,714			9,592			16,439			2,751			(103	)		16,092			20,050
Investments in non-utility activities, at equity		36,869			33,964			30,610			26,479			23,055			23,653			90,534			84,096

* 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 nine months ended July 31, 2003 and 2002, is presented below:


		Three months						Nine months
		Ended July 31						Ended July 31

In thousands		2003			2002			2003		2002

Income before income taxes for reportable segments		$	(14,981	)	$	(12,872	)	$	127,738	$	122,535
Income before income taxes for other non-utility activities			(1,241	)		(2,254	)		2,899		(303	)
Income taxes			6,545			6,149			51,318		48,194

	Net income	$	(9,677	)	$	(8,977	)	$	79,319	$	74,038

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


In thousands		July 31, 2003			October 31, 2002

Total assets for reportable segments		$	1,486,920		$	1,457,069
Other assets			70,095			36,133
Eliminations/Adjustments			(46,208	)		(48,114	)

	Consolidated assets	$	1,510,807		$	1,445,088

9. Equity Investments

Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary of Piedmont Natural Gas Company. Piedmont Energy Partners, Inc., is a wholly owned subsidiary of Piedmont Natural Gas Company that is a holding company for certain other wholly owned subsidiaries. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Propane Company and Piedmont Energy Company.

Piedmont Intrastate Pipeline Company owns 16.45% of the membership interests 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 owns 35% of the membership interests 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 an interstate 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 our 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 interests in US Propane, L.P. The other members are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. As of July 31, 2003, US Propane owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. 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 our 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 July 31, 2003, our capital account was positive.

Piedmont Energy Company owns 30% of the membership interests 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). Key governance provisions in the LLC agreement require unanimous approval of the members. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. 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 geographic service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of July 31, 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, nine months and twelve months ended July 31, 2003, by $1.4 million, $5.1 million and $5.7 million, pre-tax, respectively, to reflect our estimates that our earnings from SouthStar will be at a level lower 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 variable cash flows associated with changes in 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” under Statement 133 and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” 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 Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”

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

Piedmont Greenbrier Pipeline Company, LLC, owns 33% of the membership interests 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 July 31, 2003, we have made capital contributions to Greenbrier totaling $9 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On April 9, 2003, 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.

As of July 31, 2003, the amount of our retained earnings that represents undistributed earnings of 50% or less owned entities accounted for by the equity method was $22.5 million.

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 $2.7 million for the three months ended July 31, 2003 and 2002, respectively, $7.9 million and $8.2 million for the nine months ended July 31, 2003 and 2002, respectively, and $10.6 million and $11 million for the twelve months ended July 31, 2003 and 2002, respectively. We owed Pine Needle $.9 million at July 31, 2003 and 2002.

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 July 31, 2003 and 2002, $1.1 million for the nine months ended July 31, 2003 and 2002, and $1.5 million for the twelve months ended July 31, 2003 and 2002. We owed Cardinal $.1 million at July 31, 2003 and 2002.

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 zero and $2.9 million for the three months ended July 31, 2003 and 2002, respectively, $.9 million and $7.4 million for the nine months ended July 31, 2003 and 2002, respectively, and $4.2 million and $10.6 million for the twelve months ended July 31, 2003 and 2002, respectively. As of July 31, 2003, and 2002, SouthStar owed us $29,000 and $.9 million, respectively.

Summarized Financial Information

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the three months and nine months ended June 30, 2003 and 2002, is presented below.


	Three months				Nine months
	Ended June 30				Ended June 30

In thousands	2003		2002		2003		2002

Revenues	$	4,269	$	4,281	$	12,831	$	12,843
Gross profit		—		—		—		—
Income before income taxes		2,786		2,252		7,139		6,980
Total assets		102,543		103,965		102,543		103,965

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for the three months and nine months ended June 30, 2003 and 2002, is presented below.


	Three months				Nine months
	Ended June 30				Ended June 30

In thousands	2003		2002		2003		2002

Revenues	$	5,107	$	5,286	$	15,345	$	15,307
Gross profit		—		—		—		—
Income before income taxes		2,300		2,401		7,205		7,791
Total assets		122,709		115,094		122,709		115,094

Summarized unaudited financial information for Heritage Propane for 100% of Heritage Propane for the three months and nine months ended May 31, 2003 and 2002, as filed in its Form 10-Q with the Securities and Exchange Commission, is presented below.


	Three months						Nine months
	Ended May 31						Ended May 31

In thousands	2003			2002			2003		2002

Revenues	$	148,444		$	142,638		$	650,970	$	534,376
Gross profit		81,663			90,335			398,749		324,695
Income (Loss) before income taxes		(3,070	)		(4,319	)		47,457		21,032
Total assets		730,406			717,264			730,406		717,264

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for the three months and nine months ended June 30, 2003 and 2002, is provided below.


	Three months				Nine months
	Ended June 30				Ended June 30

In thousands	2003		2002		2003		2002

Revenues	$	136,212	$	106,344	$	617,787	$	508,703
Gross profit		27,386		15,820		98,859		110,877
Income before income taxes		12,901		423		47,741		58,583
Total assets		170,946		169,704		170,946		169,704

Summarized unaudited financial information provided to us by Greenbrier for 100% of Greenbrier for the three months and nine months ended June 30, 2003 and 2002, is presented below.


	Three months				Nine months
	Ended June 30				Ended June 30

In thousands	2003		2002		2003		2002

Revenues	$	1	$	—	$	—	$	—
Gross profit		—		—		—		—
Income before income taxes		102		71		284		160
Total assets		29,266		16,221		29,266		16,221

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

As of July 31, 2003, we have purchased and sold financial call options for natural gas for our Tennessee gas purchase portfolio for December 2003 through 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 July 31, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for September 2003 through March 2004. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers subject to our 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. We believe the plan is very structured in composition and designed to limit subjective discretion in making hedging decisions.

As of July 31, 2003, we have purchased and sold financial call options for natural gas for our North Carolina gas purchase portfolio for September 2003 through March 2004. 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. The NCUC recognized that the review of the

prudency of a decision to hedge or not to hedge, just like the review of the prudency of other gas purchasing decisions, must be made on the basis of the information available at the time the decision is made, not on the basis of the information available at the time of the annual prudency review proceeding. Through July 31, 2003, 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. We are impacted by regulation of the NCUC, the PSCSC and the Tennessee Regulatory Authority (TRA). In addition, 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 due to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins.

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

• The capital-intensive nature of our business. In order to maintain our historic growth, we must construct additions to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining 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. Our cash flows are not adequate to finance the cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock.

• Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts 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 the report is filed with the SEC.

Our Business

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 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.

In 1994, our predecessor, Piedmont Natural Gas Company, Inc., a New York corporation incorporated in 1950, was merged into a newly formed North Carolina corporation, whose name was changed to Piedmont Natural Gas Company, Inc., for the purpose of changing our state of incorporation to North Carolina.

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.

Our utility operations are subject to regulation by the NCUC, the PSCSC and the 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 regulations. These regulations include regulations that are particular to the natural gas industry, such as regulations of the FERC that affect the availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that affect the construction, operation and maintenance of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, that are generally applicable to companies doing business in the United States.

We 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. For further information, see Note 10 to the condensed consolidated financial statements and “Results of Operations” in Item 2 of this report beginning on page 22.

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. As discussed below, we have agreed to purchase additional retail natural gas distribution assets that will expand our service area into eastern North Carolina.

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. (Progress), 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 be September 30, 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 has 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:

• There being no order, decree or injunction by any governmental authority that prohibits the consummation of the transactions,

• There being no material adverse effect in the financial condition or results of operations of NCNG, EasternNC and NCNG’s subsidiaries, taken as a whole,

• The representations and warranties of Progress being correct as of the closing date of the acquisition,

• The parties having complied with all covenants that are required to be performed before closing,

• The obligations of NCNG under a $150 million line of credit to Progress being cancelled,

• The transfer prior to closing of certain manufactured gas facilities to a person other than an affiliate of NCNG and

• There being no contract preventing or restricting NCNG or any of its subsidiaries from carrying on any business in any location.

We believe the conditions related to the closing of the transactions will be satisfied by the closing date, which must occur on or before December 31, 2003.

The NCUC approved the transactions by order dated June 26, 2003, including the issuance of up to $500 million of short-term debt to be used to initially finance the acquisitions. On July 16, the NCUC approved the issuance of $500 million of long-term debt and equity securities to repay the short-term debt. On September 2, the SEC approved our requested exemption under the Public Utility Holding Company Act which is the final regulatory approval needed in connection with the transactions.

Financial Condition and Liquidity

We finance current cash requirements primarily from operating cash flows and short-term borrowings. During the quarter ended July 31, 2003, outstanding short-term borrowings under committed bank lines of credit totaling $200 million ranged from zero to $54 million, and interest rates ranged from 1.45% to 1.65%. During the nine months ended July 31, 2003, outstanding short-term borrowings ranged from zero to $86 million, and interest rates ranged from 1.45% to 2.04%. As of July 31, 2003, we had additional uncommitted lines of credit totaling $68 million on a no fee and as needed, if available, basis. As of July 31, 2003, our current assets of $221.8 million were more than our current liabilities of $173.1 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 July 31, 2003, 56% of our sales and transportation revenues were from residential customers and 31% 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. For further information on the WNA, see “Results of Operations” in Item 2 of this report beginning on page 22.

The regulated utility faces competition in the residential and commercial customer markets based on the customers’ preferences for natural gas compared with other energy products and the relative prices of those products. The most significant product competition occurs between natural gas and electricity for space

heating, water heating and cooking. Any upward pressure on the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the end user. This could negatively impact our liquidity if customer growth slows or if customers conserve.

In the industrial market, many of our customers have the capability of burning a fuel other than natural gas. Fuel oil is the most significant competing energy alternative in the market we serve. Our ability to maintain our industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With the growing imbalance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the market price of natural gas in the future. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and policies of foreign and domestic governments. Our liquidity could be impacted either positively or negatively as a result of alternate fuel decisions by industrial customers.

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 to serve additional customer demand during cold weather and to refill storage. Short-term debt may increase 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 growing imbalance between domestic supply and demand, gas prices could fluctuate for the next several years. If wholesale gas prices remain high, we may incur more short-term debt to pay for natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills.

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 July 31, 2003, we issued $18.8 million of common 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 July 31, 2003; however, we did retire $45 million of unsecured 6.23% medium-term notes at the scheduled maturity date. We expect to sell long-term debt and equity securities to fund our proposed acquisition of NCNG and EasternNC.

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

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

• Ratio of net cash flows to capital expenditures,

• Funds from operations interest coverage,

• Ratio of funds from operations to average total debt and

• Pre-tax interest coverage.

Qualitative factors include, among other things:

• Stability of regulation in 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.

We are subject to default provisions related to our long-term debt, short-term bank lines of credit and accounts receivable financing.

The default provisions under our senior notes are as follows:

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

• Interest coverage of 1.75 times,

• Total debt cannot exceed 70% of total capitalization,

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

• Failure to make payments on any capitalized lease obligation,

• Bankruptcy, liquidation or insolvency and

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

Failure to satisfy any of the above results in total outstanding issues becoming due. There are cross default provisions to all debt outstanding.

The default provisions of our medium-term notes are as follows:

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

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

• Bankruptcy, liquidation or insolvency.

Failure to satisfy these provisions results in the same outcome as for the senior notes.

We are within the debt default provisions established for our senior notes, medium-term notes, short-term bank lines of credit and accounts receivable financings. As of July 31, 2003, all of our long-term debt was unsecured.

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 under shelf registration statements. We have received commitments from lenders for a $450 million credit facility to backstop the commercial paper program. On June 25, 2003, Moody’s Investors Service (Moody’s) assigned a first-time rating of Prime-2 to the $450 million commercial paper program. On July 22, Standard & Poor’s Ratings Services (S&P) assigned its “A-1” rating to the program.

Pursuant to our request for a rating on the shelf registration statements, S&P notified us on June 23 that the unsecured debt securities had been assigned a preliminary rating of A and that a final rating will be assigned to each drawdown under the shelf registration statement only after S&P reviews the terms. On June 25, Moody’s lowered its debt rating of our senior unsecured debt to “A3” with a negative outlook from “A2.” Any significant delays in obtaining regulatory approvals or in the execution of a permanent financing plan for the NCNG and EasternNC acquisitions could further impact our debt rating from Moody’s.

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 our 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. In accordance with industry-wide practice, we normally inject natural gas into storage during the summer months (principally April through October) for withdrawal from storage during winter months (principally November through March) when customer demand is higher. Inventory of stored gas increased from October 31, 2002 to July 31, 2003. Accounts payable and accounts receivable increased during this same period due to this seasonality, higher gas prices and the demand for gas during the winter season.

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 July 31, 2003, were $19.6 million, compared with $23.4 million for the same period in 2002. Utility construction expenditures for the nine months ended July 31, 2003, were $55.3 million, compared with $63.1 million for the same period in 2002. Utility construction expenditures for the twelve months ended July 31, 2003, were $75.9 million, compared with $84 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.

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


In thousands	Payments Due by Period

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

Long-term debt	$	462,000	$	2,000	$	35,000	$	—	$	425,000
Pipeline and storage capacity and gas supply*		786,466		94,596		234,577		142,235		315,058
Operating leases		14,022		3,991		6,976		1,284		1,771

* 100% recoverable through purchased gas cost recovery mechanisms.

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

Critical Accounting Policies and Estimates

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

assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Our regulated utility segment is subject to regulation by certain state and federal authorities. We have accounting policies that conform to Statement 71 and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and income in 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 those portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded.

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 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. See Note 5 to the condensed consolidated financial statements.

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, nine months and twelve months ended July 31, 2003, compared with similar periods in 2002.

Margin (Operating Revenues less Cost of Gas)

Margin for the three months ended July 31, 2003, increased $1.4 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $5.4 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2.2 million from secondary market transactions.

• Increase of $1.8 million due to an increase in higher volumetric margin residential and commercial volumes which was offset by a decrease in lower-margin industrial volumes, for a net decrease of .9 million dekatherms.

• Increase of $.8 million from the acquisition of customers of North Carolina Gas Service (NCGS) effective September 30, 2002.

• Increase of $.4 million in other revenues primarily due to an increase in late payment fees.

These increases were partially offset by the following decreases.

• Decrease of $7 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

• Decrease of $1.7 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

Margin for the nine months ended July 31, 2003, increased $31.4 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $37.4 million due to an increase in volumes billed of 13.6 million dekatherms due to 23% colder weather and growth in the customer base.

• Increase of $19.5 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2.6 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

• Increase of $5.3 million from the acquisition of customers of NCGS effective September 30, 2002.

• Increase of $1.9 million from secondary market transactions.

• Increase of $1.3 million in other revenues primarily due to an increase in late payment fees.

These increases were partially offset by the following decreases.

• Margin for the current nine-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 $4.1 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

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

Margin for the twelve months ended July 31, 2003, increased $31.4 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $35.2 million from increased volumes billed due to colder weather and growth in the customer base. Billed volumes increased 12.9 million dekatherms primarily due to 18% colder weather.

• Increase of $21 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

• Increase of $2.6 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

• Increase of $5.6 million from the acquisition of customers of NCGS effective September 30, 2002.

• Increase of $3.5 million from secondary market transactions.

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

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 $1.7 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

• Decrease of $1.3 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 consolidated balance sheets. 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. Annual prudence reviews were eliminated in Tennessee when the incentive plan was established. This plan established an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark rates, together with income from marketing transportation and storage capacity in the secondary market.

Operations and Maintenance Expenses

Operations and maintenance expenses for the three months ended July 31, 2003, increased $5.8 million

compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $2 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases and accruals of the short-term and long-term incentive plans.

• Increase of $1.1 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

• Increase of $.8 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

• Increase of $.5 million in advertising expense primarily due to amortization of demand-side management costs as approved by the PSCSC.

• Increase of $.4 million in outside consultants fees primarily related to the pending NCNG acquisition and the upgrade of our geographical mapping system.

• Increase of $.4 million in outside labor costs primarily due to the pending NCNG integration.

Operations and maintenance expenses for the nine months ended July 31, 2003, increased $15.9 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $5.2 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, and accruals of the short-term and long-term incentive plans.

• Increase of $3.9 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

• Increase of $3.1 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

• Increase of $1.4 million in outside consultants fees primarily related to the pending NCNG acquisition.

• Increase of $1 million in risk insurance due to higher premiums.

• Increase of $.6 million in advertising expense primarily due to amortization of demand-side management costs as approved by the PSCSC.

Operations and maintenance expenses for the twelve months ended July 31, 2003, increased $18.9 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $7.6 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, and accruals of the short-term and long-term incentive plans.

• Increase of $5 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

• Increase of $1.6 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

• Increase of $1.5 million in outside consultants fees primarily related to the pending NCNG acquisition.

• Increase of $1.3 million in risk insurance due to higher premiums.

• Increase of $.6 million in advertising primarily due to amortization of demand side-management costs as approved by the PSCSC.

Depreciation

Depreciation expense for the three months, nine months and twelve months ended July 31, 2003, increased over similar prior periods due to increases in 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 July 31, 2003, increased $.5 million compared with the same period in 2002 primarily due to increases of $.4 million in property taxes and $.2 million in gross receipts taxes.

General taxes for the nine months ended July 31, 2003, increased $.9 million compared with the same period in 2002 primarily due to increases of $.5 million in gross receipts taxes, $.4 million in property taxes and $.3 million in payroll taxes, partially offset by a decrease of $.3 million in sales taxes resulting from an audit by the taxing authority.

General taxes for the twelve months ended July 31, 2003, decreased $.7 million compared with the same period in 2002 primarily due to a decrease of $1.6 million in property taxes and $.3 million in sales taxes resulting from an audit, partially offset by increases of $.7 million in gross receipts taxes and $.3 million in payroll taxes.

Other Income (Expense)

Income from equity investee earnings for the three months ended July 31, 2003, increased $4.3 million compared with the same period in 2002 primarily due to an increase in earnings from SouthStar of $3.5 million and from US Propane of $.9 million.

Income from equity investee earnings for the nine months ended July 31, 2003, decreased $4 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $6.8 million, partially offset by an increase in earnings from US Propane of $2.8 million.

Income from equity investee earnings for the twelve months ended July 31, 2003, decreased $7.1 million compared with the same period in 2002 primarily due to a decrease in earnings from SouthStar of $9.2 million, partially offset by an increase in earnings from US Propane of $1.8 million. Such earnings 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 that was recorded in the quarter ended July 31, 2002.

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

Non-operating income is comprised of merchandising, jobbing and compressed natural gas operations, the non-equity portion of activities of the subsidiaries, interest income and other miscellaneous income.

Non-operating income for the three months ended July 31, 2003, increased $.2 million compared with the same period in 2002 primarily due to increases in interest income.

Non-operating income for the nine months ended July 31, 2003, increased $.8 million compared with the same period in 2002 primarily due to increases of $.2 million in earnings from jobbing operations, $.3 million in interest income and $.2 million in miscellaneous income.

Non-operating income for the twelve months ended July 31, 2003, decreased slightly compared with the same period in 2002 primarily due to a decrease in earnings from merchandise operations, partially offset by an increase in interest income.

Non-operating expense is composed of charitable contributions and other miscellaneous expenses.

Non-operating expense for the three months ended July 31, 2003, increased $35,000 compared with the same period in 2002 primarily due to an increase in charitable contributions.

Non-operating expense for the nine months ended July 31, 2003, increased $3,000 compared with the same period in 2002 primarily due to an increase in other miscellaneous expenses.

Non-operating expense for the twelve months ended July 31, 2003, decreased $.2 million compared with the same period in 2002 primarily due to a decrease in charitable contributions related to the timing of payments.

Utility Interest Charges

Utility interest charges for the three months ended July 31, 2003, decreased $.1 million compared with the same period in 2002 primarily due to decreases of $.4 million in interest on refunds due customers and $.1 million in interest on long-term debt due to lower amounts outstanding during the period, partially offset by a decrease of $.4 million in the portion of AFUDC attributable to borrowed funds.

Utility interest charges for the nine months ended July 31, 2003, increased $.2 million compared with the same period in 2002 primarily due to a decrease of $1.4 million in the portion of AFUDC attributable to borrowed funds, partially offset by decreases of $1.1 million in interest on refunds due customers and $.2 million in interest on long-term debt due to lower amounts outstanding during the period.

Utility interest charges for the twelve months ended July 31, 2003, increased $.7 million compared with the same period in 2002 primarily for the reasons listed below.

• Increase of $.3 million in interest on long-term debt due to higher amounts outstanding during the period.

• Decrease of $2.5 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 $.4 million in interest on short-term debt due to lower interest rates.

Accounting Pronouncements

Effective July 1, 2003, we adopted Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). Statement 149 amends and clarifies financial accounting and reporting for derivative instruments embedded in other contracts and for hedging activities under Statement 133. The adoption of Statement 149 did not have a material effect on financial position or results of operations.

Effective August 1, 2003, we will adopt FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). We believe that FIN 46 applies to our equity investments, all of which were acquired prior to February 1, 2003. We are currently evaluating the impact of FIN 46 on our equity method investments and anticipate that we will not be considered the primary beneficiary under FIN 46 as we do not absorb a majority of the expected losses nor are we entitled to a majority of the residual returns. We believe that the adoption of FIN 46 will not have a material effect on financial position or results of operations.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We hold all financial instruments discussed below for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. 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 July 31, 2003, we had $45 million of short-term debt outstanding. During the quarter ended July 31, 2003, short-term debt ranged from zero to $54 million with a weighted average interest rate of 1.55%. Our short-term borrowing needs are met through a competitive bid process among those financial institutions providing us with committed lines of credit. The carrying amount of such debt approximates fair value.

The table below provides information as of July 31, 2003, about our long-term debt.


	Expected Maturity Date																		Fair Value at
																			July 31,
In thousands	2004			2005		2006			2007		2008		Thereafter			Total			2003

Fixed Rate
Long–term Debt	$	2,000		$	—	$	35,000		$	—	$	—	$	425,000		$	462,000		$	497,000
Average Interest Rate		10.06	%		—		9.44	%		—		—		7.55	%		7.71	%

Commodity Price Risk

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

customers under gas cost recovery mechanisms.

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

Item 4. Controls and Procedures

As of the end of the period covered by 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

Each of the proposed transactions is subject to a number of conditions, including:

We believe the conditions related to the closing of the transactions will be satisfied by the closing date, which must occur on or before December 31, 2003.

On September 2, 2003, a settlement agreement supported by all parties in an NCNG general rate case proceeding was filed with the NCUC. The agreement provides for, among other things, an annual increase in NCNG’s revenues of $29.4 million. We expect an order from the NCUC to be effective November 1, 2003; however, we are unable to determine the outcome of this proceeding at this time.

On April 29, 2003, we filed an application with the TRA requesting an annual increase in revenues along with changes in cost allocations and rate design and changes in tariffs and service regulations. On September 9, a settlement agreement with the Tennessee Consumer Advocate was filed with the TRA that would increase revenues by $10.3 million annually. We expect an order from the TRA to be effective November 1, 2003; however, we are unable to predict the outcome of this proceeding at this time.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits –


	12		Computation of Ratio of Earnings to Fixed Charges.
	31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.


	31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Offer.
	32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
	32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

(b) Reports on Form 8-K –

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.

On June 13, 2003, we filed a report on Form 8-K regarding the filling of Section 906 Certificates for previously filed reports.

On June 27, 2003, we filed a report on Form 8-K regarding (1) NCUC approval on June 26, 2003, of our proposed acquisition of NCNG and of an equity interest in EasternNC and approval of the issuance of up to $500 million of short-term debt to be used to initially finance the acquisitions, (2) the notification by S&P on June 23, 2003, that our senior unsecured debt securities had been assigned a preliminary rating of “A” and (3) the notification by Moody’s on June 25, 2003, that it had lowered its debt ratings of our senior unsecured debt to “A3” from “A2.”

Outside of the period, on August 22, 2003, we filed a report on Form 8-K regarding the issuance of a press release to report (1) third quarter results, (2) declaration of dividend and (3) earnings guidance for 2003.

Outside of the period, on September 5, 2003, we filed a report on Form 8-K regarding the approval by the SEC of our requested exemption under the Public Utility Holding Company Act in connection with our proposed acquisition of NCNG and of an equity interest in EasternNC.

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 September 12, 2003		/s/ David J. Dzuricky

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

Date September 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 July 31, 2003 and October 31, 2002, and the results of operations and cash flows for the three months, nine months and twelve months ended July 31, 2003 and 2002.

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

3.		We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we have capitalized certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from 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 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. Our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. The applicable regulatory commissions approve these depreciation rates. We accrue estimated costs of removal of long-lived assets through depreciation expense, with a corresponding credit to accumulated depreciation. Because these estimated removal costs meet the requirements of Statement 71, these accumulated costs are not classified as liabilities. As of July 31, 2003, we had $192.5 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 July 31, 2003, the effect of recording unbilled revenues was a decrease in margin which resulted in a decrease in earnings of $7 million, or $.13 per share. For the nine months and twelve months ended July 31, 2003, the effect was an increase in margin which resulted in an increase in earnings of $2.6 million, or $.05 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 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 nine-month periods ended July 31, 2003, do not necessarily reflect the results to be expected for the full year.

7.		Basic earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur when common stock equivalents are added to 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.

		Operations by segment for the three months and nine months ended July 31, 2003 and 2002, are presented below:

9.		Equity Investments

		Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary of Piedmont Natural Gas Company. Piedmont Energy Partners, Inc., is a wholly owned subsidiary of Piedmont Natural Gas Company that is a holding company for certain other wholly owned subsidiaries. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Propane Company and Piedmont Energy Company.

		Piedmont Intrastate Pipeline Company owns 16.45% of the membership interests 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 owns 35% of the membership interests 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 an interstate 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 our 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 interests in US Propane, L.P. The other members are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. As of July 31, 2003, US Propane owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network. 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 our 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 July 31, 2003, our capital account was positive.

		Piedmont Energy Company owns 30% of the membership interests 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). Key governance provisions in the LLC agreement require unanimous approval of the members. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. 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 geographic service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of July 31, 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, nine months and twelve months ended July 31, 2003, by $1.4 million, $5.1 million and $5.7 million, pre-tax, respectively, to reflect our estimates that our earnings from SouthStar will be at a level lower 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 variable cash flows associated with changes in 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” under Statement 133 and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” 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 Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”

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

		Piedmont Greenbrier Pipeline Company, LLC, owns 33% of the membership interests 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 July 31, 2003, we have made capital contributions to Greenbrier totaling $9 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On April 9, 2003, 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.

		As of July 31, 2003, the amount of our retained earnings that represents undistributed earnings of 50% or less owned entities accounted for by the equity method was $22.5 million.

		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 $2.7 million for the three months ended July 31, 2003 and 2002, respectively, $7.9 million and $8.2 million for the nine months ended July 31, 2003 and 2002, respectively, and $10.6 million and $11 million for the twelve months ended July 31, 2003 and 2002, respectively. We owed Pine Needle $.9 million at July 31, 2003 and 2002.

		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 July 31, 2003 and 2002, $1.1 million for the nine months ended July 31, 2003 and 2002, and $1.5 million for the twelve months ended July 31, 2003 and 2002. We owed Cardinal $.1 million at July 31, 2003 and 2002.

		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 zero and $2.9 million for the three months ended July 31, 2003 and 2002, respectively, $.9 million and $7.4 million for the nine months ended July 31, 2003 and 2002, respectively, and $4.2 million and $10.6 million for the twelve months ended July 31, 2003 and 2002, respectively. As of July 31, 2003, and 2002, SouthStar owed us $29,000 and $.9 million, respectively.

		Summarized Financial Information

		Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the three months and nine months ended June 30, 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 area where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

		As of July 31, 2003, we have purchased and sold financial call options for natural gas for our Tennessee gas purchase portfolio for December 2003 through 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 July 31, 2003, we have purchased and sold financial call options for natural gas for our South Carolina gas purchase portfolio for September 2003 through March 2004. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers subject to our 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. We believe the plan is very structured in composition and designed to limit subjective discretion in making hedging decisions.

		As of July 31, 2003, we have purchased and sold financial call options for natural gas for our North Carolina gas purchase portfolio for September 2003 through March 2004. 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. The NCUC recognized that the review of the

	•		Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We are impacted by regulation of the NCUC, the PSCSC and the Tennessee Regulatory Authority (TRA). In addition, 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 due to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins.

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

	•		The capital-intensive nature of our business. In order to maintain our historic growth, we must construct additions to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining 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. Our cash flows are not adequate to finance the cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock.

	•		Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts 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.

	•		There being no order, decree or injunction by any governmental authority that prohibits the consummation of the transactions,

	•		There being no material adverse effect in the financial condition or results of operations of NCNG, EasternNC and NCNG’s subsidiaries, taken as a whole,

	•		The representations and warranties of Progress being correct as of the closing date of the acquisition,

	•		The parties having complied with all covenants that are required to be performed before closing,

	•		The obligations of NCNG under a $150 million line of credit to Progress being cancelled,

	•		The transfer prior to closing of certain manufactured gas facilities to a person other than an affiliate of NCNG and

	•		There being no contract preventing or restricting NCNG or any of its subsidiaries from carrying on any business in any location.

	•		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.

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

	•		Interest coverage of 1.75 times,

	•		Total debt cannot exceed 70% of total capitalization,

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

	•		Failure to make payments on any capitalized lease obligation,

	•		Bankruptcy, liquidation or insolvency and

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

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

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

	•		Bankruptcy, liquidation or insolvency.

	•		Increase of $5.4 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2.2 million from secondary market transactions.

	•		Increase of $1.8 million due to an increase in higher volumetric margin residential and commercial volumes which was offset by a decrease in lower-margin industrial volumes, for a net decrease of .9 million dekatherms.

	•		Increase of $.8 million from the acquisition of customers of North Carolina Gas Service (NCGS) effective September 30, 2002.

	•		Increase of $.4 million in other revenues primarily due to an increase in late payment fees.

	•		Decrease of $7 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

	•		Decrease of $1.7 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

	•		Increase of $37.4 million due to an increase in volumes billed of 13.6 million dekatherms due to 23% colder weather and growth in the customer base.

	•		Increase of $19.5 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2.6 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

	•		Increase of $5.3 million from the acquisition of customers of NCGS effective September 30, 2002.

	•		Increase of $1.9 million from secondary market transactions.

	•		Increase of $1.3 million in other revenues primarily due to an increase in late payment fees.

	•		Margin for the current nine-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 $4.1 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

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

	•		Increase of $35.2 million from increased volumes billed due to colder weather and growth in the customer base. Billed volumes increased 12.9 million dekatherms primarily due to 18% colder weather.

	•		Increase of $21 million from increased customer rates and charges, including changes in rate design effective November 1, 2002, in North Carolina and South Carolina.

	•		Increase of $2.6 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 5 to the condensed consolidated financial statements.

	•		Increase of $5.6 million from the acquisition of customers of NCGS effective September 30, 2002.

	•		Increase of $3.5 million from secondary market transactions.

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

	•		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 $1.7 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.

	•		Decrease of $1.3 million in margin from power generation customers.

	•		Increase of $2 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases and accruals of the short-term and long-term incentive plans.

	•		Increase of $1.1 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

	•		Increase of $.8 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

	•		Increase of $.5 million in advertising expense primarily due to amortization of demand-side management costs as approved by the PSCSC.

	•		Increase of $.4 million in outside consultants fees primarily related to the pending NCNG acquisition and the upgrade of our geographical mapping system.

	•		Increase of $.4 million in outside labor costs primarily due to the pending NCNG integration.

	•		Increase of $5.2 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, and accruals of the short-term and long-term incentive plans.

	•		Increase of $3.9 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

	•		Increase of $3.1 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

	•		Increase of $1.4 million in outside consultants fees primarily related to the pending NCNG acquisition.

	•		Increase of $1 million in risk insurance due to higher premiums.

	•		Increase of $.6 million in advertising expense primarily due to amortization of demand-side management costs as approved by the PSCSC.

	•		Increase of $7.6 million in payroll primarily due to the addition of employees from the acquisition of NCGS, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, and accruals of the short-term and long-term incentive plans.

	•		Increase of $5 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of reducing the expected long-term rate of return on plan assets.

	•		Increase of $1.6 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices and colder weather.

	•		Increase of $1.5 million in outside consultants fees primarily related to the pending NCNG acquisition.

	•		Increase of $1.3 million in risk insurance due to higher premiums.

	•		Increase of $.6 million in advertising primarily due to amortization of demand side-management costs as approved by the PSCSC.

	•		Increase of $.3 million in interest on long-term debt due to higher amounts outstanding during the period.

	•		Decrease of $2.5 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 $.4 million in interest on short-term debt due to lower interest rates.

(b)		Reports on Form 8-K –

		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.

		On June 13, 2003, we filed a report on Form 8-K regarding the filling of Section 906 Certificates for previously filed reports.

		On June 27, 2003, we filed a report on Form 8-K regarding (1) NCUC approval on June 26, 2003, of our proposed acquisition of NCNG and of an equity interest in EasternNC and approval of the issuance of up to $500 million of short-term debt to be used to initially finance the acquisitions, (2) the notification by S&P on June 23, 2003, that our senior unsecured debt securities had been assigned a preliminary rating of “A” and (3) the notification by Moody’s on June 25, 2003, that it had lowered its debt ratings of our senior unsecured debt to “A3” from “A2.”

		Outside of the period, on August 22, 2003, we filed a report on Form 8-K regarding the issuance of a press release to report (1) third quarter results, (2) declaration of dividend and (3) earnings guidance for 2003.

		Outside of the period, on September 5, 2003, we filed a report on Form 8-K regarding the approval by the SEC of our requested exemption under the Public Utility Holding Company Act in connection with our proposed acquisition of NCNG and of an equity interest in EasternNC.