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, 2004


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 (State or other jurisdiction of incorporation or organization)		56-0556998 (I.R.S. Employer Identification No.)

1915 Rexford Road, Charlotte, North Carolina (Address of principal executive offices)		28211 (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 Exchange Act). 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 Common Stock, no par value		Outstanding at September 3, 2004 38,328,506

Page 1 of 32

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,
	2004			2003
ASSETS
Utility Plant, at original cost	$	2,452,835		$	2,389,122
Less accumulated depreciation		618,861			576,823

Utility plant, net		1,833,974			1,812,299

Other Physical Property (net of accumulated depreciation of $1,873 in 2004 and $1,740 in 2003)		1,039			1,115

Current Assets:
Cash and cash equivalents		4,333			11,172
Restricted cash		12,586			6,749
Marketable securities, at fair market value (cost, $869)		1,538			—
Receivables (less allowance for doubtful accounts of $4,203 in 2004 and $2,743 in 2003)		84,204			58,662
Unbilled utility revenues		13,683			34,630
Gas in storage		103,285			121,723
Refundable income taxes		1,102			23,758
Prepayments		28,362			31,085
Other		21,766			19,865

Total current assets		270,859			307,644

Investments, Deferred Charges and Other Assets:
Investments in non-utility activities, at equity		64,864			96,191
Goodwill		48,130			50,924
Unamortized debt expense		5,381			3,748
Other		24,686			24,485

Total investments, deferred charges and other assets		143,061			175,348

Total	$	2,248,933		$	2,296,406

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock, no par value, 100,000 shares authorized; outstanding, 38,313 in 2004 and 33,655 in 2003	$	562,906		$	372,651
Retained earnings		320,408			259,476
Accumulated other comprehensive income		(316	)		(1,932	)

Total common stock equity		882,998			630,195
Long-term debt		660,000			460,000

Total capitalization		1,542,998			1,090,195

Current Liabilities:
Current maturities of long-term debt and sinking fund requirements		—			2,000
Notes payable		27,000			109,500
Commercial paper		—			445,559
Accounts payable		83,055			90,901
Deferred income taxes		20,762			16,949
Income taxes accrued		22,304			612
General taxes accrued		12,404			19,594
Refunds due customers		709			5,382
Accrued gas cost on unbilled utility revenues		1,335			2,995
Other		27,403			31,670

Total current liabilities		194,972			725,162

Deferred Credits and Other Liabilities:
Deferred income taxes		201,705			188,503
Unamortized federal investment tax credits		4,630			5,042
Asset retirement obligations		262,298			245,879
Other		42,330			41,625

Total deferred credits and other liabilities		510,963			481,049

Total	$	2,248,933		$	2,296,406

See notes to consolidated financial statements.

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


	Three Months Ended						Nine Months Ended						Twelve Months Ended
	July 31						July 31						July 31
	2004			2003			2004			2003			2004			2003
Operating Revenues	$	214,750		$	140,132		$	1,315,933		$	1,041,397		$	1,495,357		$	1,162,876
Cost of Gas		145,022			90,832			903,870			720,389			1,021,422			795,706

Margin		69,728			49,300			412,063			321,008			473,935			367,170

Operating Expenses:
Operations and maintenance		47,803			37,692			148,014			114,068			186,054			149,291
Depreciation		20,886			15,336			61,549			45,895			78,818			60,698
General taxes		6,974			6,032			20,397			18,779			26,028			24,720
Income taxes		(7,400	)		(7,890	)		57,385			43,889			53,535			35,653

Total operating expenses		68,263			51,170			287,345			222,631			344,435			270,362

Operating Income		1,465			(1,870	)		124,718			98,377			129,500			96,808

Other Income (Expense):
Non-utility activities, at equity		3,995			2,323			25,375			16,092			27,256			15,249
Gain on sale of equity investments		—			—			4,683			—			4,683			—
Allowance for equity funds used during construction		323			346			971			967			1,268			1,318
Non-operating income		1,008			782			2,098			1,938			2,720			1,993
Non-operating expense		—			(140	)		(956	)		(556	)		(1,263	)		(730	)
Income taxes		(2,259	)		(1,345	)		(12,896	)		(7,429	)		(14,045	)		(7,265	)

Total other income (expense), net of tax		3,067			1,966			19,275			11,012			20,619			10,565
Utility Interest Charges		12,664			9,773			36,199			30,070			46,463			39,875

Income Before Minority Interest in Income of Consolidated Subsidiary		(8,132	)		(9,677	)		107,794			79,319			103,656			67,498
Less Minority Interest in Income of Consolidated Subsidiary		25			—			70			—			889			—

Net Income	$	(8,157	)	$	(9,677	)	$	107,724		$	79,319		$	102,767		$	67,498

Average Shares of Common Stock:
Basic		38,218			33,461			36,797			33,327			35,989			33,239
Diluted		38,218			33,461			36,888			33,439			36,088			33,368
Earnings Per Share of Common Stock:
Basic	$	(0.21	)	$	(0.29	)	$	2.93		$	2.38		$	2.86		$	2.03
Diluted	$	(0.21	)	$	(0.29	)	$	2.92		$	2.37		$	2.85		$	2.02
Cash Dividends Per Share of Common Stock	$	0.43		$	0.42		$	1.275		$	1.23		$	1.69		$	1.63
Pro Forma Effect of the Declared Two-for-One Stock Split:
Average Shares of Common Stock:
Basic		76,436			66,921			73,594			66,653			71,977			66,478
Diluted		76,436			66,921			73,776			66,879			72,177			66,735
Earnings per Share of Common Stock:
Basic	$	(0.11	)	$	(0.14	)	$	1.46		$	1.19		$	1.43		$	1.02
Diluted	$	(0.11	)	$	(0.14	)	$	1.46		$	1.19		$	1.42		$	1.01
Cash Dividends Per Share of Common Stock	$	0.215		$	0.21		$	0.6375		$	0.615		$	0.845		$	0.815

See notes to consolidated financial statements.

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


	Three Months						Nine Months						Twelve Months
	Ended						Ended						Ended
	July 31						July 31						July 31
	2004			2003			2004			2003			2004			2003
Cash Flows from Operating Activities:
Net income	$	(8,157	)	$	(9,677	)	$	107,724		$	79,319		$	102,767		$	67,498
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		21,465			15,578			63,014			46,603			80,572			61,614
Undistributed earnings from equity investments		(3,995	)		(2,323	)		(25,375	)		(16,092	)		(27,256	)		(15,249	)
Gain on sale of equity investments		—			—			(4,683	)		—			(4,683	)		—
Change in operating assets and liabilities		(81,203	)		(47,839	)		35,433			(13,895	)		(4,049	)		(10,898	)
Other, net		(187	)		16,486			10,843			26,824			16,452			24,000

Net cash provided by (used in) operating activities		(72,077	)		(27,775	)		186,956			122,759			163,803			126,965

Cash Flows from Investing Activities:
Utility construction expenditures		(24,413	)		(18,976	)		(69,067	)		(53,531	)		(93,472	)		(73,418	)
Capital contributions to equity investments		—			—			—			(2,223	)		—			(3,485	)
Capital distributions from equity investments		1,277			1,752			24,761			8,940			26,009			11,039
Proceeds from sale of equity investments		—			—			36,096			—			36,096			—
Purchase of gas distribution system		—			—			—			2,153			—			(23,847	)
Purchase of NCNG and EasternNC, net of cash received		4,212			—			2,724			—			(447,444	)		—
Other		(10	)		(15	)		(56	)		(92	)		(82	)		(101	)

Net cash used in investing activities		(18,934	)		(17,239	)		(5,542	)		(44,753	)		(478,893	)		(89,812	)

Cash Flows from Financing Activities:
Increase (Decrease) in notes payable, net		27,000			45,000			(82,500	)		(1,500	)		(18,000	)		45,000
Decrease in commercial paper		—			—			(445,559	)		—			—			—
Issuance of long-term debt		—			—			200,000			—			200,000			—
Retirement of long-term debt		(2,000	)		(47,000	)		(2,000	)		(47,000	)		(2,000	)		(47,000	)
Proceeds from issuance of common stock, net of expenses		—			—			173,828			—			173,828			—
Issuance of common stock through dividend reinvestment and employee stock plans		5,401			4,572			14,769			13,885			18,809			18,846
Dividends paid		(16,429	)		(13,882	)		(46,791	)		(40,980	)		(60,725	)		(54,165	)

Net cash provided by (used in ) financing activities		13,972			(11,310	)		(188,253	)		(75,595	)		311,912			(37,319	)

Net Increase (Decrease) in Cash and Cash Equivalents		(77,039	)		(56,324	)		(6,839	)		2,411			(3,178	)		(166	)
Cash and Cash Equivalents at Beginning of Period		81,372			63,835			11,172			5,100			7,511			7,677

Cash and Cash Equivalents at End of Period	$	4,333		$	7,511		$	4,333		$	7,511		$	4,333		$	7,511

Cash Paid During the Period for:
Interest	$	20,452		$	16,099		$	39,090		$	35,895		$	43,462		$	39,602
Income taxes	$	9,627		$	354		$	19,549		$	32,632		$	25,798		$	36,841
Noncash Investing and Financing Activities Related to Purchase of NCNG and EasternNC:
Fair value/book value of assets acquired	$	(11,416	)				$	(10,039	)				$	501,096
Cash paid		—						(271	)					(457,624	)
Adjustment of estimated working capital to actual		(819	)					(819	)					1,191

Liabilities assumed	$	(12,235	)				$	(11,129	)				$	44,663

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
	2004			2003			2004			2003
Net Income	$	(8,157	)	$	(9,677	)	$	107,724		$	79,319
Other Comprehensive Income:
Unrealized gain on marketable securities, net of tax of $265 in the three and nine months ended July 31, 2004		404			—			404			—
Unrealized gain (loss) on equity investments hedging activities, net of tax of $353 and $(318) in the three months ended July 31, 2004 and 2003, respectively, and net of tax of $352 and $(611) in the nine months ended July 31, 2004 and 2003, respectively		515			(493	)		506			(937	)
Reclassification adjustment for loss on equity investments hedging activities included in net income, net of tax of $6 and $75 in the three months ended July 31, 2004 and 2003, respectively, and net of tax of $465 and $1,364 in the nine months ended July 31, 2004 and 2003, respectively		1			117			706			2,087

Total Comprehensive Income	$	(7,237	)	$	(10,053	)	$	109,340		$	80,469

Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period	$	(1,236	)	$	(1,457	)	$	(1,932	)	$	(2,983	)
Current period change		919			(493	)		910			(937	)
Current period reclassification to net income		1			117			706			2,087

Balance, end of period	$	(316	)	$	(1,833	)	$	(316	)	$	(1,833	)

See notes to consolidated financial statements.

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

1. Independent auditors have not audited the consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2003 Annual Report.

2. In our opinion, the unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at July 31, 2004 and October 31, 2003, and the results of operations and cash flows for the three, nine and twelve months ended July 31, 2004 and 2003.

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

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 capitalize certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from or refund to utility customers in future periods.

4. All of our goodwill is attributable to the regulated utility segment. The balance in goodwill as of October 31, 2003 and July 31, 2004, and the changes for the nine months ended July 31, 2004, are presented below.


In thousands
Balance as of October 31, 2003	$	50,924
Purchase price allocation adjustments for North Carolina Natural Gas Corporation (NCNG)		(2,724	)
Minority interest in Eastern North Carolina Natural Gas Company (EasternNC)		(70	)

Balance as of July 31, 2004	$	48,130

Effective at the close of business on September 30, 2003, we purchased for $417.5 million in cash 100% of the common stock of NCNG and for $7.5 million in cash a 50% equity interest in EasternNC. The purchase price allocation was completed during the third quarter of 2004. The decrease of $2.7 million in goodwill is primarily due to the recording of $5 million in deferred taxes from book and tax basis differences of the purchase price, partially offset by unrecorded liabilities and the true-up of working capital. All of the goodwill arising from this acquisition and the acquisition of the natural gas distribution assets and liabilities of North Carolina Gas Service in September 2002 have been allocated to the North Carolina operating unit for purposes of impairment testing under SFAS No. 142, “Goodwill and Other Intangible Assets.”

5. Effective February 1, 2004, we adopted SFAS No. 132, “Employers’ Disclosure about Pensions and Other Postretirement Benefits (Revised)” (Statement 132). Statement 132 requires additional disclosures about assets, obligations, cash flows and the net periodic benefit cost of defined-benefit pension plans and other postretirement benefit plans. Components of the net periodic benefit cost for the three, nine and twelve months ended July 31, 2004 and 2003, are presented below.


	Pension Benefits						Other Benefits *
In thousands	2004			2003			2004			2003
Three Months Ended July 31
Service cost	$	2,349		$	1,515		$	341		$	203
Interest cost		3,021			2,496			663			538
Expected return on plan assets		(4,113	)		(3,327	)		(231	)		(205	)
Amortization of transition obligation		—			3			220			220
Amortization of prior-service cost		233			233			258			258
Amortization of actuarial (gain) loss		—			(210	)		95			49

Net periodic benefit cost	$	1,490		$	710		$	1,346		$	1,063

Nine Months Ended July 31
Service cost	$	4,699		$	3,030		$	682		$	406
Interest cost		6,042			4,991			1,325			1,075
Expected return on plan assets		(8,110	)		(6,654	)		(461	)		(409	)
Amortization of transition obligation		—			7			440			439
Amortization of prior-service cost		465			465			515			515
Amortization of actuarial (gain) loss		—			(420	)		191			99

Net periodic benefit cost	$	3,096		$	1,419		$	2,692		$	2,125

Twelve Months Ended July 31
Service cost	$	8,828		$	5,911		$	1,266		$	701
Interest cost		11,690			9,930			2,573			1,968
Expected return on plan assets		(15,499	)		(13,725	)		(897	)		(841	)
Amortization of transition obligation		3			13			879			879
Amortization of prior-service cost		931			931			1,030			601
Amortization of actuarial (gain) loss		(210	)		(848	)		336			160

Net periodic benefit cost	$	5,743		$	2,212		$	5,187		$	3,468

* The expense for other postretirement benefits does not reflect the impact of the Medicare Prescription Drug Improvement and Modernization Act of 2003, which for us are reductions in expense effective with the quarter beginning August 1, 2004.

6. Our business is seasonal in nature. The results of operations for the three and nine months ended July 31, 2004, do not necessarily reflect the results to be expected for the full year.

7. On August 27, 2004, the Board of Directors declared a two-for-one common stock split, subject to regulatory approval by the North Carolina Utilities Commission (NCUC). If approved, the stock split will be in the form of a 100% stock dividend to shareholders of record at the close of business on October 11, 2004. The additional shares will be distributed beginning October 29, 2004. The split will not change the proportionate interest a shareholder has in Piedmont.

We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share, on a pre-split basis, for the three, nine and twelve months ended July 31, 2004 and 2003, is presented below.


	Three Months						Nine Months				Twelve Months
In thousands except per share amounts	2004			2003			2004		2003		2004		2003
Net Income	$	(8,157	)	$	(9,677	)	$	107,724	$	79,319	$	102,767	$	67,498

Average shares of Common Stock outstanding for basic earnings per share		38,218			33,461			36,797		33,327		35,989		33,239
Contingently issuable shares under the Long-Term Incentive Plan*		—			—			91		112		99		129

Average shares of dilutive stock		38,218			33,461			36,888		33,439		36,088		33,368

Earnings Per Share of Common Stock:
Basic	$	(.21	)	$	(.29	)	$	2.93	$	2.38	$	2.86	$	2.03
Diluted	$	(.21	)	$	(.29	)	$	2.92	$	2.37	$	2.85	$	2.02

* For the three months ended July 31, 2004 and 2003, the inclusion of 85 and 111 contingently issuable shares, respectively, would be antidilutive.

8. Based on products and services, regulatory environments and our corporate organization and business decision-making activities, we have two reportable business segments, regulated utility and non-utility activities. Operations of the regulated utility segment are conducted by the parent company and by EasternNC. Operations of the non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy Company.

For all periods in 2003 and for the nine and twelve months ended July 31, 2004, the operations of the non-utility activities segment also included Piedmont Propane Company. On January 20, 2004, Piedmont Propane Company, a wholly owned subsidiary of Piedmont Natural Gas Company, along with the other members of US Propane, L.P., completed the sale of US Propane’s general and limited partnership interests in Heritage Propane. In connection with the sale of US Propane, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units. The Energy Transfer Partners’ units held by us are tradable at our discretion and are presented in the consolidated balance sheets as “Marketable securities.” These securities are held as available for sale and any unrealized gains and losses are recorded in “Accumulated other comprehensive income.”

Operations of the regulated utility segment are reflected in operating income in the consolidated statements of income. Operations of the non-utility activities segment are included in “Other Income (Expense)” in the consolidated statements of income in either “Non-utility activities, at equity” or “Non-operating income.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on income from non-utility activities, at equity, and investments in non-utility activities, at equity. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the audited consolidated financial statements for the year ended October 31, 2003.

Operations by segment for the three and nine months ended July 31, 2004 and 2003, are presented below:


	Regulated						Non-utility
	Utility						Activities						Total
In thousands	2004			2003			2004			2003			2004			2003
Three Months Ended July 31
Revenues from external customers	$	214,750		$	140,132		$	—		$	—		$	214,750		$	140,132
Margin		69,728			49,300			—			—			69,728			49,300
Operations and maintenance expenses		47,803			37,692			32			(28	)		47,835			37,664
Depreciation		20,886			15,336			—			—			20,886			15,336
Operating income		(5,935	)		(9,760	)		(83	)		22			(6,018	)		(9,738	)
Income before income taxes and minority interest		(17,362	)		(18,529	)		4,089			2,307			(13,273	)		(16,222	)
Income from non-utility activities, at equity		—			—			3,995			2,323			3,995			2,323
Construction expenditures		25,078			19,601			—			—			25,078			19,601
Investments in non-utility activities, at equity		—			—			64,864			90,534			64,864			90,534
Nine Months Ended July 31
Revenues from external customers	$	1,315,933		$	1,041,397		$	—		$	—		$	1,315,933		$	1,041,397
Margin		412,063			321,008			—			—			412,063			321,008
Operations and maintenance expenses		148,014			114,068			119			18			148,133			114,086
Depreciation		61,549			45,895			—			—			61,549			45,895
Operating income		182,103			142,266			(180	)		(28	)		181,923			142,238
Income before income taxes and minority interest		147,695			114,707			30,380			15,930			178,075			130,637
Income from non-utility activities, at equity		—			—			25,375			16,092			25,375			16,902
Construction expenditures		71,082			55,350			—			—			71,082			55,350
Investments in non-utility activities, at equity		—			—			64,864			90,534			64,864			90,534

Reconciliations to the consolidated financial statements for the three and nine months ended July 31, 2004 and 2003, and as of July 31, 2004 and October 31, 2003, are presented below.


	Three Months						Nine Months
In thousands	2004			2003			2004			2003
Operating Income:
Segment operating income	$	(6,018	)	$	(9,738	)	$	181,923		$	142,238
Utility income taxes		7,400			7,890			(57,385	)		(43,889	)
Non-utility activities		83			(22	)		180			28

Operating income	$	1,465		$	(1,870	)	$	124,718		$	98,377


	Three Months						Nine Months
In thousands	2004			2003			2004			2003
Net Income:
Income before income taxes and minority interest for reportable segments	$	(13,273	)	$	(16,222	)	$	178,075		$	130,637
Income taxes		5,141			6,545			(70,281	)		(51,318	)
Less minority interest		25			—			70			—

Net income	$	(8,157	)	$	(9,677	)	$	107,724		$	79,319


	July 31,			October 31,
	2004			2003
Consolidated Assets:
Total assets for reportable segments	$	2,273,468		$	2,327,256
Eliminations/Adjustments		(24,535	)		(30,850	)

Consolidated assets	$	2,248,933		$	2,296,406

9. The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and its 50% equity investment in EasternNC. Our equity interest in EasternNC is considered to be a controlling interest and we have consolidated EasternNC for presentation in the accompanying consolidated financial statements. Investments in non-utility activities are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy Company. Our ownership interest in each entity is included in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are included in “Non-utility activities, at equity” in “Other Income (Expense)” in the consolidated statements of income.

As of July 31, 2004, the amount of retained earnings that represented undistributed earnings of 50% or less owned entities accounted for by the equity method was $23.7 million.

Piedmont Intrastate Pipeline Company

Piedmont Intrastate Pipeline Company owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.

We have related party transactions as a transportation customer of Cardinal at rates approved by the NCUC. We record in cost of gas the demand costs charged by Cardinal. These gas costs for the three, nine and twelve months ended July 31, 2004 and 2003, are presented below.


	Three Months				Nine Months				Twelve Months
In thousands	2004		2003		2004		2003		2004		2003
Demand Costs	$	1,181	$	372	$	3,520	$	1,108	$	4,125	$	1,476

As of July 31, 2004 and 2003, we owed Cardinal $.4 million and $.1 million, respectively.

Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for the three and nine months ended June 30, 2004 and 2003, is presented below.


	Three Months				Nine Months
In thousands	2004		2003		2004		2003
Revenues	$	3,870	$	4,269	$	11,654	$	12,831
Gross profit		3,870		4,269		11,654		12,831
Income before income taxes		1,828		2,786		5,913		7,139
Total assets		99,897		102,543		99,897		102,543

Piedmont Interstate Pipeline Company

Piedmont Interstate Pipeline Company owns 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC).

We have related party transactions as a customer of Pine Needle at rates approved by the FERC. We record in cost of gas the storage costs charged by Pine Needle. These gas costs for the three, nine and twelve months ended July 31, 2004 and 2003, are presented below.


	Three Months				Nine Months				Twelve Months
In thousands	2004		2003		2004		2003		2004		2003
Storage Costs	$	3,100	$	2,579	$	9,170	$	7,906	$	11,913	$	10,592

We owed Pine Needle $1 million and $.9 million at July 31, 2004 and 2003, respectively.

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for the three and nine months ended June 30, 2004 and 2003, is presented below.


	Three Months				Nine Months
In thousands	2004		2003		2004		2003
Revenues	$	5,177	$	5,107	$	14,700	$	15,345
Gross profit		5,177		5,107		14,700		15,345
Income before income taxes		2,272		2,300		6,910		7,205
Total assets		116,236		122,709		116,236		122,709

Piedmont Energy Company

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

We have related party transactions as a wholesale gas supplier to SouthStar. Our operating revenues from these sales for the three, nine and twelve months ended July 31, 2004 and 2003, are presented below.


	Three Months				Nine Months				Twelve Months
In thousands	2004		2003		2004		2003		2004		2003
Operating Revenues	$	1,100	$	—	$	1,246	$	898	$	1,246	$	4,230

As of July 31, 2004 and 2003, SouthStar owed us $373,000 and $29,000, respectively.

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for the three and nine months ended June 30, 2004 and 2003, is provided below.


	Three Months				Nine Months
In thousands	2004		2003		2004		2003
Revenues	$	148,381	$	136,312	$	662,784	$	617,787
Gross profit		23,618		27,386		105,772		98,859
Income before income taxes		10,528		12,901		69,788		47,741
Total assets		162,506		170,946		162,506		170,946

10. 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 adjustment (PGA) procedures. 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 compliance with our risk management policies.

Through July 31, 2004, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of July 31, 2004, we had forward positions for December 2004 through March 2005. 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 approved by the Tennessee Regulatory Authority (TRA).

Through July 31, 2004, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of July 31, 2004, we had forward positions for September 2004 through March 2005. The cost of these options is pre-approved for recovery from customers by the Public Service Commission of South Carolina (PSCSC) subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.

Through July 31, 2004, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of July 31, 2004, we had forward positions for September 2004 through March 2005. Costs associated with our North Carolina hedging program are not pre-approved for recovery from customers by the NCUC but are treated as gas costs subject to the annual gas cost prudence review by the NCUC.

There is no income statement impact of the North Carolina and South Carolina hedging programs as all costs and related gain or loss amounts are passed through to customers under PGA procedures and are included in “Refunds due customers,” a regulatory liability. We mark the derivative instruments to market with a corresponding entry to “Refunds due customers.” As of July 31, 2004, the amount in “Refunds due customers” of $.7 million included receivables from customers of $2.8 million for the costs of the North Carolina and

South Carolina hedging programs and the related mark-to-market adjustments.

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

Overview

Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. Our subsidiaries are invested in joint venture, energy-related businesses. For the quarter ended July 31, 2004, net income was $(8.2) million, or $(.21) per diluted share, compared with $(9.7) million, or $(.29) per diluted share, for the same period last year. For the nine months ended July 31, 2004, net income was $107.7 million, or $2.92 per diluted share, compared with $79.3 million, or $2.37 per diluted share, for the same period last year. Operating results for the current periods reflect the full effect of the acquisitions of NCNG and a 50% equity interest in EasternNC on September 30, 2003, collectively referred to as the NCNG acquisition.

Our utility operations are weather sensitive. Weather during the current nine months was 2% warmer than normal and 7% warmer than the same period of the prior year. Compared with similar prior periods, system throughput increased from 17.6 million dekatherms to 35.8 million dekatherms for the quarter and from 124.1 million dekatherms to 167.2 million dekatherms for the nine months ended July 31, 2004, due to the NCNG acquisition and continued customer growth. Operations and maintenance expenses for the quarter ended July 31, 2004, increased primarily due to higher payroll, transportation, pension and other employee benefit costs related to the NCNG acquisition, increases in accruals for payroll incentive plans and other corporate expenses. Operations and maintenance expenses for the nine months ended July 31, 2004, increased primarily due to higher payroll, transportation, utilities, outside labor costs, the provision for uncollectibles, other corporate expenses, pension and other employee benefit costs from the NCNG acquisition and increases in accruals for payroll incentive plans.

Other income, net of income taxes, for the quarter ended July 31, 2004, was $3.1 million compared with $2 million in the similar prior year quarter, and $19.3 million for the current nine months compared with $11 million in the similar prior period. The quarter increase was primarily due to an increase in earnings from SouthStar and by the absence of seasonal losses from propane activities due to the sale of our propane interests in January 2004. The increase in the nine months was primarily due to earnings from SouthStar, including a one-time pre-tax benefit of $2.5 million ($.04 per share) from the resolution of certain disproportionate sharing issues between the members of SouthStar and a one-time pre-tax gain of $4.7 million ($.08 per share) from the sale of our propane interests.

Results of Operations

We will discuss the results of operations for the three, nine and twelve months ended July 31, 2004, compared with similar periods in 2003.

Operating Revenues

Operating revenues were $214.8 million and $140.1 million in the three months ended July 31, 2004 and 2003, respectively. Operating revenues in 2004 increased $74.7 million compared with the similar prior period primarily due to the following increases.

• $49 million from volumes delivered to customers obtained through the NCNG acquisition.

• $24.9 million from secondary market transactions.

• $7.9 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

• $1.7 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

These increases were partially offset by $9.1 million due to decreased wholesale gas prices that were passed through to customers.

Operating revenues were $1,315.9 million and $1,041.4 million in the nine months ended July 31, 2004 and 2003, respectively. Operating revenues in 2004 increased $274.5 million compared with the similar prior period primarily due to the following increases.

• $236.1 million from volumes delivered to customers obtained through the NCNG acquisition.

• $52.5 million due to increased wholesale gas prices that were passed through to customers.

• $11.7 million from the weather normalization adjustment mechanisms (WNA) due to surcharges of $1.6 million in 2004 compared with refunds of $10.1 million in 2003, excluding the impact of WNA for NCNG. As discussed in “Financial Condition and Liquidity” below, we have a WNA in all three states that is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin.

• $10 million from secondary market transactions.

• $9.4 million from increased customer rates and charges and changes in rate design, primarily in Tennessee effective November 1, 2003.

These increases were partially offset by $43.6 million due to a decrease in volumes delivered of 6.9 million dekatherms, excluding the impact of the NCNG acquisition, primarily due to weather that was 2% warmer than normal in the current period compared with weather that was 4% colder than normal in the prior period.

Operating revenues were $1,495.4 million and $1,162.9 million in the twelve months ended July 31, 2004 and 2003, respectively. Operating revenues in 2004 increased $332.5 million compared with the similar prior period primarily due to the following increases.

• $256.9 million from volumes delivered to customers obtained through the NCNG acquisition.

• $77 million due to increased wholesale gas prices that were passed through to customers.

• $15.2 million from increased customer rates and charges and changes in rate design effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.

• $12.3 million from the WNA due to surcharges of $2.2 million in 2004 compared with refunds of $10.1 million in 2003.

• $6.5 million from secondary market transactions.

These increases were partially offset by $32.2 million due to a decrease in volumes delivered of 5.6 million dekatherms, excluding the impact of the NCNG acquisition, primarily due to weather that was 3% warmer than normal in the current period compared with weather that was 3% colder than normal in the prior period.

Cost of Gas

Cost of gas was $145 million and $90.8 million in the three months ended July 31, 2004 and 2003, respectively. Cost of gas in 2004 increased $54.2 million compared with the similar prior period primarily due to the following increases.

• $31 million from volumes delivered to customers obtained through the NCNG acquisition.

• $25.3 million from secondary market transactions.

• $5.6 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

These increases were partially offset by $9.1 million due to decreased wholesale gas prices.

Cost of gas was $903.9 million and $720.4 million in the nine months ended July 31, 2004 and 2003, respectively. Cost of gas in 2004 increased $183.5 million compared with the similar prior period primarily due to the following increases.

• $145 million from volumes delivered to customers obtained through the NCNG acquisition.

• $52.5 million due to increased wholesale gas prices.

• $11.3 million from secondary market transactions.

These increases were partially offset by $30.4 million due to a decrease in volumes delivered of 6.9 million dekatherms, excluding the impact of the NCNG acquisition.

Cost of gas was $1,021.4 million and $795.7 million in the twelve months ended July 31, 2004 and 2003, respectively. Cost of gas in 2004 increased $225.7 million compared with the similar prior period primarily due to the following increases.

• $159.5 million from volumes delivered to customers obtained through the NCNG acquisition.

• $77 million due to increased wholesale gas prices.

• $6 million from secondary market transactions.

These increases were partially offset by $22.6 million due to a decrease in volumes delivered of 5.6 million dekatherms, excluding the impact of the NCNG acquisition.

Margin (Operating Revenues less Cost of Gas)

Margin was $69.7 million and $49.3 million in the three months ended July 31, 2004 and 2003, respectively. Margin in 2004 increased $20.4 million compared with the similar prior period due to the following increases.

• $18 million from volumes delivered to customers obtained through the NCNG acquisition.

• $1.8 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

• $2.3 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

These increases were partially offset by the following decreases.

• $.9 million in capitalized storage inventory charges.

• $.4 million in secondary market transactions.

Margin was $412.1 million and $321 million in the nine months ended July 31, 2004 and 2003, respectively. Margin in 2004 increased $91.1 million compared with the similar prior period due to the following increases.

• $91.1 million from volumes delivered to customers obtained through the NCNG acquisition.

• $11.7 million from the WNA.

• $8 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

These increases were partially offset by the following decreases.

• $13.2 million due to a decrease in volumes delivered of 6.9 million dekatherms, excluding the impact of NCNG. The weather-related volume impact is partially offset by the WNA and the change in volumetric margin is partially offset by the impact of changes in rate design in Tennessee noted above.

• $1.3 million from secondary market transactions.

• $1 million in capitalized storage inventory charges.

Margin was $473.9 million and $367.2 million in the twelve months ended July 31, 2004 and 2003, respectively. Margin in 2004 increased $106.7 million compared with the similar prior period due to the following increases.

• $97.4 million from volumes delivered to customers obtained through the NCNG acquisition since September 30, 2003.

• $12 million from increased customer rates and charges, including changes in rate design, effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.

• $12.3 million from the WNA.

These increases were partially offset by $9.6 million due to a decrease in volumes delivered of 5.3 million dekatherms, excluding the impact of the NCNG acquisition. The weather-related volume impact is partially offset by the WNA and the change in volumetric margin is partially offset by the impact of rate design changes in North Carolina, South Carolina and Tennessee noted above.

Under PGA procedures 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, recoveries of gas costs are subject to findings made in annual gas cost recovery proceedings to determine the prudence 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 in 1996. 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 were $47.8 million and $37.7 million in the three months ended July 31, 2004 and 2003, respectively. Operations and maintenance expenses for 2004 increased $10.1 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $5.8 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accruals for short-term incentive plans.

• Increase of $1.7 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from the acquisition of NCNG.

• Increase of $1.1 million in other corporate expense primarily related to amortization of certain NCNG integration costs, industry fees and bank fees.

• Increase of $.8 million in transportation expense primarily due to the acquisition of NCNG.

• Increase of $.6 million in utilities expense primarily due to increased telecommunication expenses related to the acquisition of NCNG.

• Decrease of $1.1 million in the provision for uncollectibles primarily due to improved collection results and a reduction in amounts charged off.

Operations and maintenance expenses were $148 million and $114.1 million in the nine months ended July 31, 2004 and 2003, respectively. Operations and maintenance expenses for 2004 increased $33.9 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $18 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accruals for short-term incentive plans.

• Increase of $4.5 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from the acquisition of NCNG.

• Increase of $2.8 million in other corporate expense primarily related to bank fees, industry fees, amortization of certain NCNG integration costs, fees to renew the franchise in Nashville, Tennessee, and Department of Transportation and pipeline costs related to NCNG.

• Increase of $2.1 million in transportation expense primarily due to the acquisition of NCNG.

• Increase of $1.8 million in outside labor costs primarily due to the acquisition of NCNG, pipeline locating and building and computer services.

• Increase of $1.5 million in the provision for uncollectibles primarily due to the acquisition of NCNG and higher gas prices.

• Increase of $1.2 million in utilities expense due to increased telecommunication expenses related to the acquisition of NCNG.

• Decrease of $.9 million in outside consultant fees due to the completion of projects and the amortization of NCNG’s environmental liability.

Operations and maintenance expenses were $186.1 million and $149.3 million in the twelve months ended July 31, 2004 and 2003, respectively. Operations and maintenance expenses in 2004 increased $36.8 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $21.9 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accruals for short-term incentive plans and severance paid to NCNG employees not retained.

• Increase of $5.7 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from NCNG.

• Increase of $3 million in other corporate expense primarily related to bank fees, amortization of certain NCNG integration costs, fees to renew the Nashville franchise, Department of Transportation and pipeline costs related to NCNG and industry fees.

• Increase of $2.5 million in transportation expense primarily due to the acquisition of NCNG.

• Increase of $1.9 million in the provision for uncollectibles primarily due to the acquisition of NCNG and higher gas prices.

• Increase of $1.6 million in outside labor costs primarily due to the acquisition of NCNG, pipeline locating and building and computer services, partially offset by regulatory asset treatment to defer certain NCNG integration costs.

• Increase of $1.4 million in utilities due to increased telecommunication expenses related to the acquisition of NCNG.

• Decrease of $2.7 million due to the deferral of operations and maintenance expenses of EasternNC that were expensed prior to September 30, 2003. As ordered by the NCUC, these expenses are treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper by the NCUC.

• Decrease of $2 million in outside consultant fees due to the completion of projects, regulatory asset treatment to defer certain NCNG integration costs and amortization of NCNG’s environmental liability.

Depreciation

Depreciation expense was $20.9 million and $15.3 million in the three months ended July 31, 2004 and 2003, respectively, $61.5 million and $45.9 million in the nine months ended July 31, 2004 and 2003, respectively, and $78.8 million and $60.7 million in the twelve months ended July 31, 2004 and 2003, respectively. Depreciation expense in 2004 increased over similar prior periods primarily due to increases in plant in service, including depreciation expense on plant acquired from NCNG and EasternNC.

General Taxes

General taxes were $7 million and $6 million in the three months ended July 31, 2004 and 2003, respectively. General taxes in 2004 increased $1 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $.8 million in property taxes.

• Increase of $.4 million in payroll taxes.

• Decrease of $.2 million in Tennessee gross receipts taxes.

General taxes were $20.4 million and $18.8 million in the nine months ended July 31, 2004 and 2003, respectively. General taxes in 2004 increased $1.6 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $2.2 million in property taxes in states other than Tennessee.

• Increase of $1.5 million in payroll taxes.

• Decrease of $1.7 million in Tennessee property taxes as a result of a favorable court ruling.

• Decrease of $.6 million in Tennessee gross receipts taxes.

General taxes were $26 million and $24.7 million in the twelve months ended July 31, 2004 and 2003, respectively. General taxes increased $1.3 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $2.4 million in property taxes in states other than Tennessee.

• Increase of $1.8 million in payroll taxes.

• Decrease of $2.2 million in Tennessee property taxes as noted above.

• Decrease of $.8 million in Tennessee gross receipts taxes.

Other Income (Expense)

Income from non-utility activities, at equity, was $4 million and $2.3 million in the three months ended July 31, 2004 and 2003, respectively. Income increased $1.7 million compared with the similar prior period primarily due to an increase in earnings from SouthStar of $.2 million and the avoidance of summer seasonal losses which were $1.3 million in the three months ended July 31, 2003, due to the sale of our propane interests in January 2004.

Income from non-utility activities, at equity, was $25.4 million and $16.1 million in the nine months ended July 31, 2004 and 2003, respectively. Income increased $9.3 million compared with the

similar prior period primarily due to an increase in earnings from SouthStar of $9.6 million, including a one-time benefit of $2.5 million.

Income from non-utility activities, at equity, was $27.3 million and $15.2 million in the twelve months ended July 31, 2004 and 2003, respectively. Income increased $12.1 million compared with the similar prior period primarily due to an increase in earnings from SouthStar of $12.3 million, including a one-time benefit of $2.5 million.

Gain on sale of equity investments of $4.7 million in the nine months and twelve months ended July 31, 2004, resulted from the sale of our propane interests effective January 20, 2004.

The equity portion of the allowance for funds used during construction (AFUDC) decreased slightly in the three months and twelve months ended July 31, 2004, and increased slightly in the nine months ended July 31, 2004, compared with similar prior periods. 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. We received $.6 million in the current nine months period from our interest in the retained units of Energy Transfer Partners, LP, an investment accounted for under the cost method from January 20, 2004 until May 21, 2004, when the units became tradable at our discretion.

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

Utility Interest Charges

Utility interest charges were $12.7 million and $9.8 million in the three months ended July 31, 2004 and 2003, respectively. Utility interest charges in 2004 increased $2.9 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $2 million in interest on long-term debt due to higher amounts of debt outstanding due to the permanent financing of the NCNG acquisition.

• Increase of $.8 million in interest related to temporary book and tax timing differences agreed upon in connection with the Internal Revenue Service (IRS) audit of our federal income tax return for the year ended October 31, 2001.

Utility interest charges were $36.2 million and $30.1 million in the nine months ended July 31, 2004 and 2003, respectively. Utility interest charges in 2004 increased $6.1 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $4.6 million in interest on long-term debt due to higher amounts of debt outstanding due to the permanent financing of the NCNG acquisition.

• Increase of $1.2 million in interest on short-term debt due to the commercial paper issued to temporarily finance the NCNG acquisition.

• Increase of $.8 million in interest to the IRS noted above.

• Decrease of $.6 million in interest on refunds due customers due to higher average

receivables from customers in 2004 compared with significantly higher average payables in 2003.

Utility interest charges were $46.5 million and $39.9 million in the twelve months ended July 31, 2004 and 2003, respectively. Utility interest charges in 2004 increased $6.6 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $3.8 million in interest on long-term debt due to higher amounts of debt outstanding, including amounts due to the permanent financing of the NCNG acquisition.

• Increase of $2.3 million in interest on short-term debt due to the commercial paper issued to temporarily finance the NCNG acquisition.

• Increase of $.8 million in interest to the IRS noted above.

• Decrease of $.6 million in interest on refunds due customers due to higher average receivables from customers in 2004 compared with significantly higher average payables in 2003.

Our Business

Piedmont Natural Gas, which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 940,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee, including 60,000 customers served by municipalities who are our wholesale customers. Our subsidiaries are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. We also sell residential and commercial gas appliances in Tennessee.

We have two reportable business segments, regulated utility and non-utility activities. For further information on segments, see Note 8 to the 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 federal regulations include regulations that are particular to the natural gas industry, such as regulations of the FERC that affect the availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that affect the construction, operation and maintenance of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, that are generally applicable to companies doing business in the United States.

We 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 on non-utility activities, see Note 9 to the consolidated financial statements.

In the Carolinas, our service area is comprised of numerous cities, towns and communities including

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

Financial Condition and Liquidity

We finance current cash requirements primarily from operating cash flows and short-term borrowings. During the three months ended July 31, 2004, outstanding short-term borrowings under committed bank lines of credit totaling $200 million ranged from zero to $41 million, and interest rates ranged from 1.71% to 1.84%. During the nine months ended July 31, 2004, outstanding short-term borrowings under committed bank lines of credit ranged from zero to $174 million, and interest rates ranged from 1.39% to 1.84%. As of July 31, 2004, we had additional uncommitted lines of credit totaling $103 million on a no fee and as needed, if available, basis.

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 impact operating cash flows, thereby altering the need for short-term borrowings to meet current cash requirements. During the twelve months ended July 31, 2004, 52% of our sales and transportation revenues were from residential customers and 30% were from commercial customers, both of which are weather sensitive.

Our regulatory commissions approve rates that are designed to produce revenues to cover our gas costs and our fixed and variable non-gas costs assuming normal weather. We have a WNA in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for weather-sensitive customers. Weather for the nine months ended July 31, 2004, was 2% warmer than normal, compared with 4% colder than normal for the same period in 2003. The WNA generated credits to customers of $.2 million for the nine months ended July 31, 2004, and credits to customers of $10.2 million for the similar prior period. In North Carolina and Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection or disbursement to all customers in the class. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA.

The regulated utility faces competition in the residential and commercial customer markets based on customer 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. Increases in the price of natural gas can 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 being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With the 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 the 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. Gas prices could fluctuate for the next several years due to the relationship between domestic supply and demand. 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.

When required, 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, 2004, we issued $18.8 million of common equity through dividend reinvestment and stock purchase plans.

On June 4, 2004, the Board of Directors approved a share repurchase plan for up to three million shares. We began purchasing shares on the open market, on a programmed basis, on September 1, 2004. We will then re-issue such shares when the need arises to the dividend reinvestment and stock purchase plan, the employee stock purchase plan and the long-term incentive plan. We project annual open market purchases and re-issues to be approximately 600,000 shares.

As of July 31, 2004, our capitalization consisted of 43% in long-term debt and 57% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

As of July 31, 2004, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service. Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include:

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

• Ratio of net cash flows to capital expenditures,

• Funds from operations interest coverage,

• Ratio of funds from operations to average total debt and

• Pre-tax interest coverage.

Qualitative factors include, among other things:

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

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

• Predictability of cash flows,

• Business strategy and management,

• Corporate governance guidelines and practices,

• Industry position and

• Contingencies.

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

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

• Interest coverage of less than 1.75 times,

• Total debt cannot exceed 70% of total capitalization,

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

• Failure to make payments on any capitalized lease obligation,

• Bankruptcy, liquidation or insolvency and

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

The default provisions of our medium-term notes are:

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

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

• Bankruptcy, liquidation or insolvency.

Failure to satisfy any of the default provisions results in total outstanding issues becoming due. There are cross default provisions in all our debt agreements. Based on our calculations, we met the default provisions as of July 31, 2004.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is minimal based on our receipt of the products and 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 fluctuations in short-term borrowings noted above. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. Inventories of gas in storage decreased from October 31, 2003 to July 31, 2004, and supplier accounts payable and accounts receivable increased during this same period due to seasonality, higher gas prices, the growth of our

business 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 current annual growth in customer base. Utility construction expenditures in the three months ended July 31, 2004, were $25.1 million, compared with $19.6 million in the similar prior period. Utility construction expenditures in the nine months ended July 31, 2004, were $71 million, compared with $55.3 million in the similar prior period. Utility construction expenditures in the twelve months ended July 31, 2004, were $96.1 million, compared with $75.9 million in the similar prior period. Due to projected growth in our service area, significant utility construction expenditures are expected to continue.

On August 26, 2004, the Board of Directors authorized management to pursue the establishment of a charitable foundation. The foundation is expected to be formed and funded in our fiscal fourth quarter through a cash contribution of up to $10 million.

As of July 31, 2004, our estimated future contractual obligations were as follows.


	Payments Due by Period
	Less than		1-3		4-5		After
In thousands	1 Year		Years		Years		5 Years		Total
Long-Term Debt (1)	$	—	$	35,000	$	—	$	625,000	$	660,000
Interest on Long-Term Debt (1)		44,891		133,073		84,608		478,374		740,946
Pipeline and Storage Capacity (2)		116,395		322,341		209,208		397,187		1,045,131
Gas Supply (3)		13,320		378		—		—		13,698
Telecommunications and Information Technology (4)		41,210		13,466		27,745		—		82,421
Other Purchase Obligations (5)		14,328		—		—		—		14,328
Operating Leases		4,036		6,555		1,227		1,549		13,367

(1) For further detail on long-term debt, see Note 4 of Item 8. Financial Statements and Supplementary Data in our Form 10-K for 2003.

(2) 100% recoverable through PGA procedures.

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

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

(5) Other purchase obligations consist of pipeline products, vehicles, contractor invoices, merchandise and computer hardware and software.

Off-balance Sheet Arrangements

We have no material off-balance sheet arrangements other than operating leases.

Critical Accounting Policies and Estimates

We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Our accounting policies are fundamental to understanding our results of operations and financial condition. In our Form 10-K for the year ended October 31, 2003, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we identified one critical policy and five other policies that require significant judgments and estimates in preparing the consolidated financial statements. We also described the more significant accounting policies we use in Note 1 to the consolidated financial statements in the Form 10-K.

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.

The interim financial statements in this Form 10-Q for the quarter ended July 31, 2004, should be read together with the consolidated financial statements, notes and the critical accounting policies and estimates included in our Form 10-K for 2003.

Accounting Pronouncements

On May 19, 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization act of 2003.” This FSP provides guidance on accounting for the effects of the act for employers that sponsor postretirement health care plans that provide prescription drug benefits, and requires employers to provide certain disclosures regarding the effect of the federal subsidy provided by the act. We will adopt the FSP in our fourth quarter beginning August 1, 2004. We believe that the effect of adoption will be a reduction of expense for postretirement benefits of approximately $1.1 million on an annual basis.

Forward-Looking Statements

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

• Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We are impacted by regulation of the NCUC, the PSCSC and the 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 and we expect this highly competitive environment to continue.

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

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

• The capital-intensive nature of our business. In order to maintain 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 full cost of this construction. As a result, we must fund a portion of our cash needs through borrowings.

• 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 market subject to 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 activities 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 and safety regulations and the cost of compliance.

• Earnings from our equity investments. We invest in companies that engage in interstate natural gas storage, intrastate natural gas transportation and unregulated retail natural gas marketing. These companies have risks that are inherent to their business 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,” “seek,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.

Factors relating to regulation and management 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 may also 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.

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 wholesale supply, demand and price of natural gas.

Interest Rate Risk

We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period depending upon many factors, including 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, 2004, we had no short-term debt outstanding. During the three months ended July 31, 2004, short-term debt ranged from zero to $41 million, with interest rates ranging from 1.71% to 1.84%. During the nine months ended July 31, 2004, short-term debt ranged from zero to $174 million, with interest rates ranging from 1.39% to 1.84%. The carrying amount of short-term debt approximates fair value.

Information as of July 31, 2004, about our long-term debt that is sensitive to changes in interest rates is presented below.


																		Fair
																		Value
	Expected Maturity Date																	as of
																		July 31,
In thousands	2004		2005		2006			2007		2008		Thereafter			Total			2004
Fixed Rate Long–Term Debt	$	—	$	—	$	35,000		$	—	$	—	$	625,000		$	660,000		$	794,930
Average Interest Rate		—		—		9.44	%		—		—		6.90	%		7.03	%

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various durations for the forward sale and purchase of natural gas. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers and financial price-hedging instruments. 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 and the costs of hedging our gas supplies are passed on to customers under PGA procedures.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 2 of this Form 10-Q.

Item 4. Controls and Procedures

As of July 31, 2004, management, including the Chairman, 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

We have only routine litigation in the normal course of business. We do not expect any material impact on financial position or results of operations from any pending legal proceedings.

Item 2. Unregistered Sales of Equity 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

(a) Other

None.

(b) There have been no changes to the procedures by which security holders may recommend nominees to our board of directors.

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 Officer.

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

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

(b) Reports on Form 8-K –

On June 4, 2004, we filed a report on Form 8-K regarding a press release to announce second quarter operating results, the declaration of a dividend on common stock and a common stock buy-back program.

On June 17, 2004, we filed a report on Form 8-K regarding a press release on June 16 to announce that Ms. Minor Mickel Shaw was elected to the Board of Directors effective July 1, 2004.

Outside of the period, on August 27, 2004, we filed a report on Form 8-K regarding press releases to (1) report financial results for the third quarter ended July 31, 2004, the declaration of a cash dividend on common stock, the declaration of a 2-for-1 stock split in

1.		Independent auditors have not audited the consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2003 Annual Report.

2.		In our opinion, the unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at July 31, 2004 and October 31, 2003, and the results of operations and cash flows for the three, nine and twelve months ended July 31, 2004 and 2003.

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

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 capitalize certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from or refund to utility customers in future periods.

4.		All of our goodwill is attributable to the regulated utility segment. The balance in goodwill as of October 31, 2003 and July 31, 2004, and the changes for the nine months ended July 31, 2004, are presented below.

6.		Our business is seasonal in nature. The results of operations for the three and nine months ended July 31, 2004, do not necessarily reflect the results to be expected for the full year.

7.		On August 27, 2004, the Board of Directors declared a two-for-one common stock split, subject to regulatory approval by the North Carolina Utilities Commission (NCUC). If approved, the stock split will be in the form of a 100% stock dividend to shareholders of record at the close of business on October 11, 2004. The additional shares will be distributed beginning October 29, 2004. The split will not change the proportionate interest a shareholder has in Piedmont.

8.		Based on products and services, regulatory environments and our corporate organization and business decision-making activities, we have two reportable business segments, regulated utility and non-utility activities. Operations of the regulated utility segment are conducted by the parent company and by EasternNC. Operations of the non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy Company.

		For all periods in 2003 and for the nine and twelve months ended July 31, 2004, the operations of the non-utility activities segment also included Piedmont Propane Company. On January 20, 2004, Piedmont Propane Company, a wholly owned subsidiary of Piedmont Natural Gas Company, along with the other members of US Propane, L.P., completed the sale of US Propane’s general and limited partnership interests in Heritage Propane. In connection with the sale of US Propane, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units. The Energy Transfer Partners’ units held by us are tradable at our discretion and are presented in the consolidated balance sheets as “Marketable securities.” These securities are held as available for sale and any unrealized gains and losses are recorded in “Accumulated other comprehensive income.”

		Operations of the regulated utility segment are reflected in operating income in the consolidated statements of income. Operations of the non-utility activities segment are included in “Other Income (Expense)” in the consolidated statements of income in either “Non-utility activities, at equity” or “Non-operating income.”

9.		The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and its 50% equity investment in EasternNC. Our equity interest in EasternNC is considered to be a controlling interest and we have consolidated EasternNC for presentation in the accompanying consolidated financial statements. Investments in non-utility activities are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy Company. Our ownership interest in each entity is included in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are included in “Non-utility activities, at equity” in “Other Income (Expense)” in the consolidated statements of income.

		As of July 31, 2004, the amount of retained earnings that represented undistributed earnings of 50% or less owned entities accounted for by the equity method was $23.7 million.

		Piedmont Intrastate Pipeline Company

		Piedmont Intrastate Pipeline Company owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.

		We have related party transactions as a transportation customer of Cardinal at rates approved by the NCUC. We record in cost of gas the demand costs charged by Cardinal. These gas costs for the three, nine and twelve months ended July 31, 2004 and 2003, are presented below.

10.		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 adjustment (PGA) procedures. 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 compliance with our risk management policies.

		Through July 31, 2004, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of July 31, 2004, we had forward positions for December 2004 through March 2005. 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 approved by the Tennessee Regulatory Authority (TRA).

		Through July 31, 2004, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of July 31, 2004, we had forward positions for September 2004 through March 2005. The cost of these options is pre-approved for recovery from customers by the Public Service Commission of South Carolina (PSCSC) subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.

		Through July 31, 2004, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of July 31, 2004, we had forward positions for September 2004 through March 2005. Costs associated with our North Carolina hedging program are not pre-approved for recovery from customers by the NCUC but are treated as gas costs subject to the annual gas cost prudence review by the NCUC.

		There is no income statement impact of the North Carolina and South Carolina hedging programs as all costs and related gain or loss amounts are passed through to customers under PGA procedures and are included in “Refunds due customers,” a regulatory liability. We mark the derivative instruments to market with a corresponding entry to “Refunds due customers.” As of July 31, 2004, the amount in “Refunds due customers” of $.7 million included receivables from customers of $2.8 million for the costs of the North Carolina and

•		$49 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$24.9 million from secondary market transactions.

•		$7.9 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

•		$1.7 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

•		$236.1 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$52.5 million due to increased wholesale gas prices that were passed through to customers.

•		$11.7 million from the weather normalization adjustment mechanisms (WNA) due to surcharges of $1.6 million in 2004 compared with refunds of $10.1 million in 2003, excluding the impact of WNA for NCNG. As discussed in “Financial Condition and Liquidity” below, we have a WNA in all three states that is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin.

•		$10 million from secondary market transactions.

•		$9.4 million from increased customer rates and charges and changes in rate design, primarily in Tennessee effective November 1, 2003.

•		$256.9 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$77 million due to increased wholesale gas prices that were passed through to customers.

•		$15.2 million from increased customer rates and charges and changes in rate design effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.

•		$12.3 million from the WNA due to surcharges of $2.2 million in 2004 compared with refunds of $10.1 million in 2003.

•		$6.5 million from secondary market transactions.

•		$31 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$25.3 million from secondary market transactions.

•		$5.6 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

•		$145 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$52.5 million due to increased wholesale gas prices.

•		$11.3 million from secondary market transactions.

•		$159.5 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$77 million due to increased wholesale gas prices.

•		$6 million from secondary market transactions.

•		$18 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$1.8 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

•		$2.3 million due to an increase in volumes delivered of 2.4 million dekatherms, excluding the impact of the NCNG acquisition.

•		$.9 million in capitalized storage inventory charges.

•		$.4 million in secondary market transactions.

•		$91.1 million from volumes delivered to customers obtained through the NCNG acquisition.

•		$11.7 million from the WNA.

•		$8 million from increased customer rates and charges and changes in rate design, primarily in Tennessee, effective November 1, 2003.

•		$13.2 million due to a decrease in volumes delivered of 6.9 million dekatherms, excluding the impact of NCNG. The weather-related volume impact is partially offset by the WNA and the change in volumetric margin is partially offset by the impact of changes in rate design in Tennessee noted above.

•		$1.3 million from secondary market transactions.

•		$1 million in capitalized storage inventory charges.

•		$97.4 million from volumes delivered to customers obtained through the NCNG acquisition since September 30, 2003.

•		$12 million from increased customer rates and charges, including changes in rate design, effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.

•		$12.3 million from the WNA.

•		Increase of $5.8 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accruals for short-term incentive plans.

•		Increase of $1.7 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from the acquisition of NCNG.

•		Increase of $1.1 million in other corporate expense primarily related to amortization of certain NCNG integration costs, industry fees and bank fees.

•		Increase of $.8 million in transportation expense primarily due to the acquisition of NCNG.

•		Increase of $.6 million in utilities expense primarily due to increased telecommunication expenses related to the acquisition of NCNG.

•		Decrease of $1.1 million in the provision for uncollectibles primarily due to improved collection results and a reduction in amounts charged off.

•		Increase of $18 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accruals for short-term incentive plans.

•		Increase of $4.5 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from the acquisition of NCNG.

•		Increase of $2.8 million in other corporate expense primarily related to bank fees, industry fees, amortization of certain NCNG integration costs, fees to renew the franchise in Nashville, Tennessee, and Department of Transportation and pipeline costs related to NCNG.

•		Increase of $2.1 million in transportation expense primarily due to the acquisition of NCNG.

•		Increase of $1.8 million in outside labor costs primarily due to the acquisition of NCNG, pipeline locating and building and computer services.

•		Increase of $1.5 million in the provision for uncollectibles primarily due to the acquisition of NCNG and higher gas prices.

•		Increase of $1.2 million in utilities expense due to increased telecommunication expenses related to the acquisition of NCNG.

•		Decrease of $.9 million in outside consultant fees due to the completion of projects and the amortization of NCNG’s environmental liability.

•		Increase of $21.9 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accruals for short-term incentive plans and severance paid to NCNG employees not retained.

•		Increase of $5.7 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from NCNG.

•		Increase of $3 million in other corporate expense primarily related to bank fees, amortization of certain NCNG integration costs, fees to renew the Nashville franchise, Department of Transportation and pipeline costs related to NCNG and industry fees.

•		Increase of $2.5 million in transportation expense primarily due to the acquisition of NCNG.

•		Increase of $1.9 million in the provision for uncollectibles primarily due to the acquisition of NCNG and higher gas prices.

•		Increase of $1.6 million in outside labor costs primarily due to the acquisition of NCNG, pipeline locating and building and computer services, partially offset by regulatory asset treatment to defer certain NCNG integration costs.

•		Increase of $1.4 million in utilities due to increased telecommunication expenses related to the acquisition of NCNG.

•		Decrease of $2.7 million due to the deferral of operations and maintenance expenses of EasternNC that were expensed prior to September 30, 2003. As ordered by the NCUC, these expenses are treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper by the NCUC.

•		Decrease of $2 million in outside consultant fees due to the completion of projects, regulatory asset treatment to defer certain NCNG integration costs and amortization of NCNG’s environmental liability.

•		Increase of $.8 million in property taxes.

•		Increase of $.4 million in payroll taxes.

•		Decrease of $.2 million in Tennessee gross receipts taxes.

•		Increase of $2.2 million in property taxes in states other than Tennessee.

•		Increase of $1.5 million in payroll taxes.

•		Decrease of $1.7 million in Tennessee property taxes as a result of a favorable court ruling.

•		Decrease of $.6 million in Tennessee gross receipts taxes.

•		Increase of $2.4 million in property taxes in states other than Tennessee.

•		Increase of $1.8 million in payroll taxes.

•		Decrease of $2.2 million in Tennessee property taxes as noted above.

•		Decrease of $.8 million in Tennessee gross receipts taxes.

•		Increase of $2 million in interest on long-term debt due to higher amounts of debt outstanding due to the permanent financing of the NCNG acquisition.

•		Increase of $.8 million in interest related to temporary book and tax timing differences agreed upon in connection with the Internal Revenue Service (IRS) audit of our federal income tax return for the year ended October 31, 2001.

•		Increase of $4.6 million in interest on long-term debt due to higher amounts of debt outstanding due to the permanent financing of the NCNG acquisition.

•		Increase of $1.2 million in interest on short-term debt due to the commercial paper issued to temporarily finance the NCNG acquisition.

•		Increase of $.8 million in interest to the IRS noted above.

•		Decrease of $.6 million in interest on refunds due customers due to higher average

•		Increase of $3.8 million in interest on long-term debt due to higher amounts of debt outstanding, including amounts due to the permanent financing of the NCNG acquisition.

•		Increase of $2.3 million in interest on short-term debt due to the commercial paper issued to temporarily finance the NCNG acquisition.

•		Increase of $.8 million in interest to the IRS noted above.

•		Decrease of $.6 million in interest on refunds due customers due to higher average receivables from customers in 2004 compared with significantly higher average payables in 2003.

•		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 the jurisdictions in which we operate,

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

•		Predictability of cash flows,

•		Business strategy and management,

•		Corporate governance guidelines and practices,

•		Industry position and

•		Contingencies.

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

•		Interest coverage of less than 1.75 times,

•		Total debt cannot exceed 70% of total capitalization,

•		Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total 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.