PIEDMONT NATURAL GAS CO INC - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 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		56-0556998
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)


1915 Rexford Road, Charlotte, North Carolina		28211
(Address of principal executive offices)		(Zip Code)

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

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

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

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


Class		Outstanding at June 7, 2004
Common Stock, no par value		38,197,628

Page 1 of 30 pages

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

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


	April 30,			October 31,
	2004			2003
ASSETS
Utility Plant, at original cost	$	2,428,440		$	2,389,122
Less accumulated depreciation		604,761			576,823

Utility plant, net		1,823,679			1,812,299

Other Physical Property (net of accumulated depreciation of $1,840 in 2004 and $1,740 in 2003)		1,061			1,115

Current Assets:
Cash and cash equivalents		81,372			11,172
Restricted cash		6,806			6,749
Receivables (less allowance for doubtful accounts of $9,373 in 2004 and $2,743 in 2003)		136,200			58,662
Unbilled utility revenues		32,263			34,630
Gas in storage		44,081			121,723
Refundable income taxes		1,102			23,758
Prepayments		7,333			31,085
Other		22,827			19,865

Total current assets		331,984			307,644

Investments, Deferred Charges and Other Assets:
Investments in non-utility activities, at equity		62,588			96,191
Goodwill		52,366			50,924
Unamortized debt expense		5,501			3,748
Other		20,298			24,485

Total investments, deferred charges and other assets		140,753			175,348

Total	$	2,297,477		$	2,296,406

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock, no par value, 100,000 shares authorized; outstanding, 38,177 in 2004 and 33,655 in 2003	$	557,505		$	372,651
Retained earnings		344,994			259,476
Accumulated other comprehensive income		(1,236	)		(1,932	)

Total common stock equity		901,263			630,195
Long-term debt		660,000			460,000

Total capitalization		1,561,263			1,090,195

Current Liabilities:
Current maturities of long-term debt and sinking fund requirements		2,000			2,000
Notes payable		—			109,500
Commercial paper		—			445,559
Accounts payable		90,092			90,901
Deferred income taxes		32,101			16,949
Income taxes accrued		28,143			612
General taxes accrued		7,646			19,594
Refunds due customers		27,868			5,382
Accrued gas cost on unbilled utility revenues		4,109			2,995
Other		37,553			31,670

Total current liabilities		229,512			725,162

Deferred Credits and Other Liabilities:
Deferred income taxes		201,108			188,503
Unamortized federal investment tax credits		4,768			5,042
Asset retirement obligations		256,111			245,879
Other		44,715			41,625

Total deferred credits and other liabilities		506,702			481,049

Total	$	2,297,477		$	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						Six Months						Twelve Months
	Ended						Ended						Ended
	April 30						April 30						April 30
	2004			2003			2004			2003			2004			2003
Operating Revenues	$	482,398		$	407,774		$	1,101,183		$	901,265		$	1,420,740		$	1,150,670
Cost of Gas		336,543			297,760			758,848			629,557			967,233			784,939

Margin		145,855			110,014			342,335			271,708			453,507			365,731

Operating Expenses:
Operations and Maintenance		50,539			37,881			100,211			76,376			175,942			143,514
Depreciation		20,210			15,309			40,663			30,559			73,268			59,803
General Taxes		7,421			6,367			13,423			12,747			25,085			24,228
Income Taxes		21,781			15,865			64,785			51,779			53,065			37,772

Total operating expenses		99,951			75,422			219,082			171,461			327,360			265,317

Operating Income		45,904			34,592			123,253			100,247			126,147			100,414

Other Income (Expense):
Non-utility activities, at equity		12,700			9,995			21,380			13,768			25,584			10,950
Gain on sale of equity investments		(445	)		—			4,683			—			4,683			—
Allowance for equity funds used during construction		344			339			648			621			1,242			1,478
Non-operating income		921			644			1,091			1,156			2,495			1,829
Non-operating expense		(761	)		(277	)		(957	)		(415	)		(1,405	)		(694	)
Income taxes		(5,046	)		(4,332	)		(10,637	)		(6,084	)		(13,111	)		(5,542	)

Total other income (expense), net of tax		7,713			6,369			16,208			9,046			19,488			8,021
Utility Interest Charges		12,324			9,961			23,535			20,297			43,523			40,237

Income Before Minority Interest in Income of Consolidated Subsidiary		41,293			31,000			115,926			88,996			102,112			68,198
Less Minority Interest in Income of Consolidated Subsidiary		34			—			45			—			865			—

Net Income	$	41,259		$	31,000		$	115,881		$	88,996		$	101,247		$	68,198

Average Shares of Common Stock:
Basic		38,082			33,333			36,079			33,258			34,793			33,078
Diluted		38,167			33,444			36,173			33,372			34,902			33,223
Earnings Per Share of Common Stock:
Basic	$	1.08		$	0.93		$	3.21		$	2.68		$	2.91		$	2.06
Diluted	$	1.08		$	0.93		$	3.20		$	2.67		$	2.90		$	2.05
Cash Dividends Per Share of Common Stock	$	0.430		$	0.415		$	0.845		$	0.815		$	1.675		$	1.615

See notes to consolidated financial statements.

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


	Three Months						Six Months						Twelve Months
	Ended						Ended						Ended
	April 30						April 30						April 30
	2004			2003			2004			2003			2004			2003
Cash Flows from Operating Activities:
Net income	$	41,259		$	31,000		$	115,881		$	88,996		$	101,247		$	68,198
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		20,617			15,544			41,548			31,025			74,685			60,684
Undistributed earnings from equity investments		(12,700	)		(9,995	)		(21,380	)		(13,768	)		(25,584	)		(10,950	)
Gain on sale of equity investments		445			—			(4,683	)		—			(4,683	)		—
Change in assets and liabilities		148,018			67,643			115,149			33,944			32,845			(33,416	)
Other, net		2,217			11,558			11,031			10,338			28,107			23,181

Net cash provided by operating activities		199,856			115,750			257,546			150,535			206,617			107,697

Cash Flows from Investing Activities:
Utility construction expenditures		(24,206	)		(17,476	)		(44,655	)		(34,555	)		(88,035	)		(76,957	)
Capital contributions to equity investments		—			(1,377	)		—			(2,223	)		—			(4,402	)
Capital distributions from equity investments		15,447			5,938			23,484			7,188			26,484			24,067
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 of $7,185		—			—			—			—			(450,168	)		—
Other		(34	)		(41	)		(46	)		(78	)		(87	)		(118	)

Net cash provided by (used in) investing activities		(8,793	)		(12,956	)		14,879			(27,515	)		(475,710	)		(81,257	)

Cash Flows from Financing Activities:
Decrease in bank loans, net		(123,000	)		(44,000	)		(109,500	)		(46,500	)		—			—
Decrease in commercial paper		—			—			(445,559	)		—			—			—
Issuance of long-term debt		—			—			200,000			—			200,000			—
Retirement of long-term debt		—			—			—			—			(47,000	)		(2,000	)
Proceeds from issuance of common stock, net of expenses		(266	)		—			173,828			—			173,828			—
Issuance of common stock through dividend reinvestment and employee stock plans		5,357			4,463			9,369			9,313			17,981			19,322
Dividends paid		(16,373	)		(13,828	)		(30,363	)		(27,098	)		(58,179	)		(53,404	)

Net cash provided by (used in) financing activities		(134,282	)		(53,365	)		(202,225	)		(64,285	)		286,630			(36,082	)

Net Increase (Decrease) in Cash and Cash Equivalents		56,781			49,429			70,200			58,735			17,537			(9,642	)
Cash and Cash Equivalents at Beginning of Period		24,591			14,406			11,172			5,100			63,835			73,477

Cash and Cash Equivalents at End of Period	$	81,372		$	63,835		$	81,372		$	63,835		$	81,372		$	63,835

Cash Paid During the Period for:
Interest	$	3,926		$	3,727		$	19,516		$	19,796		$	39,988		$	39,560
Income taxes	$	9,910		$	23,710		$	9,921		$	23,892		$	16,525		$	28,109
Noncash Investing and Financing Activities Related to Acquisitions of NCNG and EasternNC:
Fair value/book value of assets acquired	$	—					$	1,106					$	512,241
Cash paid		—						—						(457,353	)
Adjustment of estimated working capital to actual		—						—						2,010

Liabilities assumed	$	—					$	1,106					$	56,898

See notes to condensed consolidated financial statements.

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


	Three Months						Six Months
	Ended April 30						Ended April 30
	2004			2003			2004			2003
Net Income	$	41,259		$	31,000		$	115,881		$	88,996
Other Comprehensive Income:
Unrealized income (loss) on equity investments hedging activities, net of tax of ($223) and ($136) in the three months ended April 30, 2004 and 2003, respectively, and net of tax of ($2) and ($293) in the six months ended April 30, 2004 and 2003, respectively		(346	)		(207	)		(9	)		(444	)
Reclassification adjustment for (income) loss included in net income, net of tax of $120 and $489 in the three months ended April 30, 2004 and 2003, respectively, and net of tax of $459 and $1,289 in the six months ended April 30, 2004 and 2003, respectively		185			750			705			1,970

Total Comprehensive Income	$	41,098		$	31,543		$	116,577		$	90,522

Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period		($1,075	)		($2,000	)		($1,932	)		($2,983	)
Current period reclassification to earnings		185			750			705			1,970
Current period change		(346	)		(207	)		(9	)		(444	)

Balance, end of period		($1,236	)		($1,457	)		($1,236	)		($1,457	)

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 April 30, 2004 and October 31, 2003, and the results of operations and cash flows for the three months, six months and twelve months ended April 30, 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 following presents the balance in goodwill as of October 31, 2003 and April 30, 2004, and the changes for the six months ended April 30, 2004.


In thousands
Balance as of October 31, 2003	$	50,924
Purchase price allocation adjustment for North Carolina Natural Gas Corporation (NCNG)		1,488
Minority interest in Eastern North Carolina Natural Gas Company (EasternNC)		(46	)

Balance as of April 30, 2004	$	52,366

The purchase price allocation adjustment is primarily due to an increase in the liability for pension restoration, deferred directors’ fees, inventory adjustments and other working capital adjustments based on additional information obtained subsequent to the initial purchase price allocation.

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

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 net periodic benefit cost of defined-benefit

pension plans and other postretirement benefit plans. The components of net periodic benefit cost for our defined-benefit pension plan and our postretirement health care and life insurance benefit plans for the three months, six months and twelve months ended April 30, 2004 and 2003, are presented below.


	Pension Benefits						Other Benefits *
In thousands	2004			2003			2004			2003
Three Months Ended April 30
Components of net periodic benefit cost:
Service cost	$	2,349		$	1,515		$	341		$	203
Interest cost		3,021			2,496			663			538
Expected return on plan assets		(3,997	)		(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	$	1,606		$	710		$	1,346		$	1,063

Six Months Ended April 30
Components of net periodic benefit cost:
Service cost	$	4,831		$	3,030		$	682		$	363
Interest cost		6,042			4,991			1,325			1,006
Expected return on plan assets		(7,993	)		(6,654	)		(461	)		(408	)
Amortization of transition obligation		—			7			440			440
Amortization of prior-service cost		465			465			515			343
Amortization of actuarial (gain) loss		—			(420	)		191			99

Net periodic benefit cost	$	3,345		$	1,419		$	2,692		$	1,843

Twelve Months Ended April 30
Components of net periodic benefit cost:
Service cost	$	7,861		$	5,762		$	1,127		$	634
Interest cost		11,165			9,877			2,448			1,854
Expected return on plan assets		(14,713	)		(14,142	)		(870	)		(865	)
Amortization of transition obligation		6			14			879			879
Amortization of prior-service cost		931			931			1,030			344
Amortization of actuarial (gain) loss		(420	)		(856	)		290			122

Net periodic benefit cost	$	4,830		$	1,586		$	4,904		$	2,968

* The expense for other postretirement benefits does not reflect the impact of the Medicare Prescription Drug Improvement and Modernization Act of 2003. This will be reflected in expense for the quarter ending October 31, 2004.

6. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 2004, do not necessarily reflect the results to be expected for the full year.

7. We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months, six months and twelve months ended April 30, 2004 and 2003, is presented below:


	Three Months				Six Months				Twelve Months
	Ended				Ended				Ended
	April 30				April 30				April 30
In thousands except per share amounts	2004		2003		2004		2003		2004		2003
Net Income	$	41,259	$	31,000	$	115,881	$	88,996	$	101,247	$	68,198

Average shares of Common Stock outstanding for basic earnings per share		38,082		33,333		36,079		33,258		34,793		33,078
Contingently issuable shares under the Long-Term Incentive Plan		85		111		94		114		109		145

Average shares of dilutive stock		38,167		33,444		36,173		33,372		34,902		33,223

Earnings Per Share:
Basic	$	1.08	$	.93	$	3.21	$	2.68	$	2.91	$	2.06
Diluted	$	1.08	$	.93	$	3.20	$	2.67	$	2.90	$	2.05

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 our regulated utility segment are conducted by the parent company and by EasternNC. Operations of our non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy 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 for $130 million. Our share of the proceeds was $26.9 million. We recognized an estimated pre-tax gain of $5.1 million on the sale in the three months ended January 31, 2004. The pre-tax gain was adjusted downward by $.4 million to $4.7 million in the three months ended April 30, 2004, based on preliminary unaudited information received. 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 37,248 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 will be presented in our consolidated financial statements as marketable securities.

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

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on income from non-utility activities, at equity, and investment in non-utility activities, at equity. 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 months and six months ended April 30, 2004 and 2003, are presented below:


	Regulated				Non-Utility
	Utility				Activities						Total
In thousands	2004		2003		2004			2003			2004		2003
Three Months Ended April 30
Revenues from external customers	$	482,398	$	407,774	$	—		$	—		$	482,398	$	407,774
Margin		145,855		110,014		—			—			145,855		110,014
Operations and maintenance expenses		50,539		37,880		33			22			50,572		37,902
Depreciation		20,210		15,309		—			—			20,210		15,309
Operating income		67,685		50,457		(31	)		(23	)		67,654		50,434
Income before income taxes and minority interest		55,526		41,273		12,594			9,924			68,120		51,197
Income from non-utility activities, at equity		—		—		12,700			9,995			12,700		9,995
Construction expenditures		24,925		18,124		—			—			24,925		18,124
Investments in non-utility activities, at equity		—		—		62,588			90,427			62,588		90,427
Six Months Ended April 30
Revenues from external customers	$	1,101,183	$	901,265	$	—		$	—		$	1,101,183	$	901,265
Margin		342,335		271,708		—			—			342,335		241,770
Operations and maintenance expenses		100,211		76,376		86			46			100,297		76,422
Depreciation		40,663		30,559		—			—			40,663		30,559
Operating income		188,038		152,026		(97	)		(49	)		187,941		151,977
Income before income taxes and minority interest		165,057		133,237		26,291			13,622			191,348		146,859
Income from non-utility activities, at equity		—		—		21,380			13,768			21,380		13,768
Construction expenditures		46,004		35,749		—			—			46,004		35,749
Investments in non-utility activities, at equity		—		—		62,588			90,427			62,588		90,427

A reconciliation to the consolidated financial statements for the three months and six months ended April 30, 2004 and 2003, and as of April 30, 2004 and October 31, 2003, is presented below:


	Three Months						Six Months
	Ended April 30						Ended April 30
In thousands	2004			2003			2004			2003
Operating Income:
Segment operating income	$	67,654		$	50,434		$	187,941		$	151,977
Utility income taxes		(21,781	)		(15,865	)		(64,785	)		(51,779	)
Non-utility activities		31			23			97			49

Operating income	$	45,904		$	34,592		$	123,253		$	100,247

Net Income:
Income before income taxes and minority interest for reportable segments	$	68,120		$	51,197		$	191,348		$	146,859
Income taxes		(26,827	)		(20,197	)		(75,422	)		(57,863	)
Less minority interest		34			—			45			—

Net income	$	41,259		$	31,000		$	115,881		$	88,996


	April 30,			October 31,
	2004			2003
Consolidated Assets:
Total assets for reportable segments	$	2,313,771		$	2,327,256
Eliminations/Adjustments		(16,295	)		(30,850	)

Consolidated assets	$	2,297,477		$	2,296,406

9. The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and its 50% equity investment in Eastern North Carolina Natural Gas Company (EasternNC). Our equity interest in EasternNC is considered to be a controlling interest and we have consolidated EasternNC for presentation in the accompanying consolidated financial statements. 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 April 30, 2004, the amount of our retained earnings that represented undistributed earnings of 50% or less owned entities accounted for by the equity method was $21 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 North Carolina Utilities Commission (NCUC).

We have related party transactions with Cardinal as a transportation customer at rates approved by the NCUC. We record in cost of gas the transportation costs charged by Cardinal. These gas costs for the three months, six months and twelve months ended April 30, 2004 and 2003, are presented below:


In thousands	Three months		Six Months		Twelve Months
April 30, 2004	$	1,159	$	2,339	$	3,316
April 30, 2003		367		736		1,473

As of April 30, 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 its fiscal quarters ended March 31, 2004 and 2003, is presented below.


	Three Months				Six Months
	Ended March 31				Ended March 31
In thousands	2004		2003		2004		2003
Revenues	$	3,870	$	4,281	$	7,783	$	8,562
Gross profit		3,870		4,281		7,783		8,562
Income before income taxes		2,013		2,072		4,086		4,353
Total assets		100,913		103,182		100,913		103,182

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 with Pine Needle as a customer 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 months, six months and twelve months ended April 30, 2004 and 2003, are presented below:


In thousands	Three months		Six Months		Twelve Months
April 30, 2004	$	3,001	$	6,070	$	11,392
April 30, 2003		2,621		5,327		10,699

We owed Pine Needle $1 million and $.9 million at April 30, 2004 and 2003, respectively.

Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for its fiscal quarters ended March 31, 2004 and 2003, is presented below.


	Three Months				Six Months
	Ended March 31				Ended March 31
In thousands	2004		2003		2004		2003
Revenues	$	4,613	$	5,250	$	9,524	$	10,238
Gross profit		4,613		5,250		9,524		10,238
Income before income taxes		2,258		2,465		4,638		4,905
Total assets		108,279		116,237		108,279		116,237

Piedmont Energy Company

Piedmont Energy Company owns 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

On March 29, 2004, we executed an amended and restated limited liability company (LLC) agreement with AGL Resources, Inc. (AGLR), the other member of SouthStar. This new agreement eliminates the disproportionate sharing provision in the original LLC agreement and allocates earnings and losses starting in January 2004 at 25% to us and 75% to AGLR. In addition,

we agreed to a management services agreement which provides that AGL Services Company will provide and administer accounting, treasury, internal audit, human resources and information technology functions on behalf of SouthStar.

We have related party transactions with SouthStar which purchases wholesale gas supplies from us. Our operating revenues from these sales for the three months, six months and twelve months ended April 30, 2004 and 2003, are presented below:


In thousands	Three months		Six Months		Twelve Months
April 30, 2004	$	146	$	146	$	146
April 30, 2003		354		898		7,151

As of April 30, 2004 and 2003, SouthStar owed us $94,000 and zero, respectively.

Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for its fiscal quarters ended March 31, 2004 and 2003, is provided below.


	Three Months				Six Months
	Ended March 31				Ended March 31
In thousands	2004		2003		2004		2003
Revenues	$	306,992	$	291,892	$	514,403	$	481,575
Gross profit		56,629		45,460		82,154		71,473
Income before income taxes		43,824		26,912		59,260		34,840
Total assets		161,301		174,937		161,301		174,937

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 April 30, 2004, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of April 30, 2004, we had forward positions for December 2004 through February 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 April 30, 2004, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of April 30, 2004, we had forward positions for June 2004 through October 2004. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.

Through April 30, 2004, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of April 30, 2004, we had forward positions for June 2004 through October 2004. Costs associated with our North Carolina hedging program are not

pre-approved 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 April 30, 2004, the amount in “Refunds due customers” of $27.9 million is net of $3.2 million due from customers 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 three months ended April 30, 2004, net income was $41.3 million, or $1.08 per diluted share, compared with $31 million, or $.93 per diluted share, for the same period last year. For the six months ended April 30, 2004, net income was $115.9 million, or $3.20 per diluted share, compared with $89 million, or $2.67 per diluted share, for the same period last year. Operating results for the current three- and six-month periods reflect the full effect of the acquisitions of NCNG and a 50% interest in EasternNC on September 30, 2003.

Our utility operations are weather sensitive. Weather in our service area during the current quarter was 1% colder than normal and 4% colder than in the similar prior year quarter. Weather during the current six months was 1% warmer than normal and 6% warmer than in the similar prior six months. System throughput increased from 42.9 million dekatherms to 58 million dekatherms for the quarter and increased from 106.4 million dekatherms to 131.4 million for the six months ended April 30, 2004, due to the acquisitions of NCNG and a 50% interest in EasternNC and continued customer growth. Operations and maintenance expenses increased primarily due to higher payroll, transportation, pension and other employee benefit costs from the addition of NCNG and an increase in the provision for uncollectibles for the three months ended April 30, 2004, and higher payroll, transportation, pension and other employee benefit costs from the addition of NCNG and increases in the provision for uncollectibles, outside labor and other corporate expenses, partially offset by a decrease in outside consultants, for the six months ended April 30, 2004.

Other income, net of income taxes, for the current quarter was $7.7 million compared with $6.4 million in the similar prior year quarter, and $16.2 million for the current six months compared with $9 million in the similar prior six months. The quarter increase was primarily due to an increase in earnings from SouthStar, partially offset by the absence of earnings from propane activities due to the sale of our interest in Heritage Propane Partners, L.P. (Heritage Propane), in January 2004. The increase in the six 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 interest in Heritage Propane.

Results of Operations

We will discuss the results of operations for the three months, six months and twelve months ended April 30, 2004, compared with similar periods in 2003.

Operating Revenues

Operating revenues were $482.4 million and $407.8 million in the three months ended April 30, 2004 and 2003, respectively. Operating revenues in 2004 increased $74.6 million compared with the similar prior period primarily due to the following increases:

• $78.4 million from volumes to NCNG and EasternNC customers.

• $3.1 million due to increased wholesale gas prices charged to customers.

• $2.8 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.

• $11.2 million from secondary market transactions.

• $1.1 million from weather normalization adjustment mechanisms (WNA) due to refunds of $2 million in 2004 compared with refunds of $.9 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.

• $1 million due to a decrease in volumes of .2 million dekatherms, excluding the impact of NCNG.

Operating revenues were $1,101.2 million and $901.3 million in the six months ended April 30, 2004 and 2003, respectively. Operating revenues in 2004 increased $199.9 million compared with the similar prior period primarily due to the following increases:

• $188.5 million from volumes to NCNG and EasternNC customers.

• $70.3 million due to increased wholesale gas prices charged to customers.

• $11.7 million from the WNA due to surcharges of $1.5 million in 2004 compared with refunds of $10.2 million in 2003, excluding the impact of WNA for NCNG.

• $8.2 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.

• $63.9 million due to a decrease in volumes of 9.2 million dekatherms, excluding the impact of NCNG.

• $14.9 million from secondary market transactions.

Operating revenues were $1,420.7 million and $1,150.7 million in the twelve months ended April 30, 2004 and 2003, respectively. Operating revenues in 2004 increased $270 million compared with the similar prior period primarily due to the following increases:

• $207.6 million from volumes to NCNG and EasternNC customers.

• $111.6 million due to increased wholesale gas prices charged to customers.

• $19.8 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.

These increases were partially offset by the following decreases.

• $67.8 million due to a decrease in sales volumes of 10.9 million dekatherms, excluding the impact of NCNG.

• $12 million from secondary market transactions.

Cost of Gas

Cost of gas was $336.5 million and $297.8 million in the three months ended April 30, 2004 and 2003, respectively. Cost of gas in 2004 increased $38.7 million compared with the similar prior period primarily due to the following increases:

• $45.4 million from volumes to NCNG customers.

• $3 million due to increased wholesale gas prices.

These increases were partially offset by the following decreases.

• $10.1 million from secondary market transactions.

• $.7 million due to a decrease in sales volumes of .2 million dekatherms, excluding the impact of NCNG.

Cost of gas was $758.8 million and $629.6 million in the six months ended April 30, 2004 and 2003, respectively. Cost of gas in 2004 increased $129.2 million compared with the similar prior period primarily due to the following increases:

• $113.9 million from volumes to NCNG customers.

• $70.3 million due to increased wholesale gas prices.

These increases were partially offset by the following decreases.

• $44.6 million due to a decrease in volumes of 9.2 million dekatherms, excluding the impact of NCNG.

• $13.3 million from secondary market transactions.

Cost of gas was $967.2 million and $784.9 million in the twelve months ended April 30, 2004 and 2003, respectively. Cost of gas in 2004 increased $182.3 million compared with the similar prior period primarily due to the following increases:

• $124.7 million from volumes to NCNG customers.

• $111.6 million due to increased wholesale gas prices.

• $19.8 million from facility charges due to rate increases and growth.

These increases were partially offset by the following decreases.

• $67.7 million due to a decrease in volumes of 10.9 million dekatherms, excluding the impact of NCNG.

• $10.8 million from secondary market transactions.

Margin (Operating Revenues less Cost of Gas)

Margin was $145.9 million and $110 million in the three months ended April 30, 2004 and 2003, respectively. Margin in 2004 increased $35.9 million compared with the similar prior period due to the following increases.

• $32.4 million due to the acquisitions of NCNG and an equity interest in EasternNC.

• $2.8 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.

• $1.1 million from the WNA.

• $.3 million due to a decrease in sales and transportation volumes of ..2 million dekatherms, excluding the impact of NCNG.

• $.2 million from secondary market transactions.

Margin was $342.3 million and $271.7 million in the six months ended April 30, 2004 and 2003, respectively. Margin in 2004 increased $70.6 million compared with the similar prior period due to the following increases.

• $73 million due to the acquisitions of NCNG and an equity interest in EasternNC.

• $11.7 million from the WNA.

• $5.7 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 the following decreases.

• $20.5 million due to a decrease in sales and transportation volumes of 9.2 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 rate design changes in Tennessee discussed above.

• $.9 million from secondary market transactions.

Margin was $453.5 million and $365.7 million in the twelve months ended April 30, 2004 and 2003, respectively. Margin in 2004 increased $87.8 million compared with the similar prior period due to the following increases.

• $79.3 million due to the acquisitions of NCNG and an equity interest in EasternNC since September 30, 2003.

• $19.8 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 $19.9 million due to a decrease in sales and transportation volumes of 11.3 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 rate design changes in North Carolina, South Carolina and Tennessee discussed 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, recovery of gas costs is 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 $50.5 million and $37.9 million in the three months ended April 30, 2004 and 2003, respectively. Operations and maintenance expenses for 2004 increased $12.6 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $6 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accrual of the short-term incentive plan.

• Increase of $2 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices.

• Increase of $1.3 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 $1.2 million in other corporate expense primarily related to bank fees, amortization of NCNG integration costs, fees to renew a major franchise and Department of Transportation and pipeline costs related to NCNG.

• Increase of $.8 million in transportation expense primarily due to the acquisitions of NCNG and EasternNC.

• Increase of $.7 million in outside labor costs primarily due to the acquisition of NCNG and pipeline locating expenses.

Operations and maintenance expenses were $100.2 million and $76.4 million in the six months ended April 30, 2004 and 2003, respectively. Operations and maintenance expenses for 2004 increased $23.8 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $12.2 million in payroll primarily due to the addition of employees from the

acquisition of NCNG, merit increases and accrual of the short-term incentive plan.

• Increase of $2.8 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 $2.7 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices.

• Increase of $1.4 million in transportation expense primarily due to the acquisitions of NCNG and EasternNC.

• Increase of $1.7 million in other corporate expense primarily related to bank fees, amortization of NCNG integration costs, fees to renew a major franchise and Department of Transportation and pipeline costs related to NCNG.

• Increase of $1.6 million in outside labor costs primarily due to the acquisition of NCNG and pipeline locating expenses.

• Decrease of $1.2 million in outside consultant fees due to the completion of some projects and amortization of NCNG’s environmental liability.

Operations and maintenance expenses were $175.9 million and $143.5 million in the twelve months ended April 30, 2004 and 2003, respectively. Operations and maintenance expenses in 2004 increased $32.4 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $18.1 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 of the short-term and long-term incentive plans and severance paid to NCNG employees not acquired.

• Increase of $4.9 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 $4.1 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices.

• Increase of $1.9 million in other corporate expense expense primarily related to bank fees, amortization of NCNG integration costs, fees to renew a major franchise and Department of Transportation and pipeline costs related to NCNG.

• Increase of $1.8 million in outside labor primarily related to pipeline locating services, building services and computer services.

• Increase of $1.8 million in transportation expense primarily due to the acquisitions of NCNG and EasternNC.

• 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 should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper.

• Decrease of $2 million in outside consultant fees due to the completion of some projects, deferral of NCNG integration costs and amortization of NCNG’s environmental liability.

Depreciation

Depreciation expense was $20.2 million and $15.3 million in the three months ended April 30, 2004 and 2003, respectively, $40.7 million and $30.6 million in the six months ended April 30, 2004 and 2003, respectively, and $73.3 million and $59.8 million in the twelve months ended April 30, 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 $7.4 million and $6.4 million in the three months ended April 30, 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 $.7 million in property taxes.

• Increase of $.5 million in payroll taxes.

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

General taxes were $13.4 million and $12.7 million in the six months ended April 30, 2004 and 2003, respectively. General taxes in 2004 increased $.7 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $1.5 million in property taxes in states other than Tennessee.

• Increase of $1.2 million in payroll taxes.

• Decrease of $1.8 million in Tennessee property taxes as a result of a favorable court ruling.

• Decrease of $.3 million in Tennessee gross receipts taxes.

General taxes were $25.1 million and $24.2 million in the twelve months ended April 30, 2004 and 2003, respectively. General taxes increased $.9 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $1.5 million in payroll taxes.

• Increase of $1.8 million in property taxes in states other than Tennessee.

• Decrease of $1.8 million in Tennessee property taxes as noted above.

• Decrease of $.4 million in Tennessee gross receipts taxes.

Other Income (Expense)

Income from equity investments was $12.7 million and $10 million in the three months ended April 30, 2004 and 2003, respectively. Income from equity investments increased $2.7 million compared with the similar prior period primarily due to an increase in earnings from SouthStar of $5 million, partially offset by a decrease in earnings from US Propane of $2.3 million as a result of the sale of our interest in Heritage Propane in January 2004.

Income from equity investments was $21.4 million and $13.8 million in the six months ended April 30, 2004 and 2003, respectively. Income from equity investments increased $7.6 million compared with the similar prior period primarily due to increases in earnings from SouthStar of $9.4 million, including a one-time benefit of $2.5 million, partially offset by a decrease in earnings from US Propane of $1.9 million as a result of the sale of our interest in Heritage Propane.

Income from equity investments was $25.6 million and $11 million in the twelve months ended April 30, 2004 and 2003, respectively. Income from equity investments in 2004 increased $14.6 million

compared with the similar prior period primarily due to increases in earnings from SouthStar of $15.5 million, including a one-time benefit of $2.5 million, partially offset by a decrease in earnings from US Propane of $.7 million as a result of the sale of our interest in Heritage Propane.

Gain on sale of equity investments of ($.4) million in the three months and $4.7 million in the six months and twelve months ended April 30, 2004, resulted from the sale of our interest in Heritage Propane. In the current quarter, we adjusted the estimated gain of $5.1 million reported last quarter to reflect preliminary unaudited amounts received from Heritage Propane during the current quarter.

The equity portion of the allowance for funds used during construction (AFUDC) in the three months and six months ended April 30, 2004, increased slightly and in the twelve months ended April 30, 2004, decreased slightly 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 in the current quarter $.4 million from an investment accounted for under the cost method.

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

Utility Interest Charges

Utility interest charges were $12.3 million and $10 million in the three months ended April 30, 2004 and 2003, respectively. Utility interest charges in 2004 increased $2.3 million compared with the similar prior period primarily due to an increase of $2 million in interest on long-term debt due to higher amounts of debt outstanding associated with the permanent debt financing of NCNG.

Utility interest charges were $23.5 million and $20.3 million in the six months ended April 30, 2004 and 2003, respectively. Utility interest charges in 2004 increased $3.2 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $1.2 million in interest on short-term debt due to the commercial paper issued to temporarily finance the acquisitions of NCNG and an equity interest in EasternNC.

• Increase of $2.6 million in interest on long-term debt due to higher amounts of debt outstanding associated with the permanent debt financing of NCNG .

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

Utility interest charges were $43.5 million and $40.2 million in the twelve months ended April 30, 2004 and 2003, respectively. Utility interest charges in 2004 increased $3.3 million compared with the similar prior period primarily for the reasons listed below.

• Increase of $2.3 million in interest on short-term debt due to the commercial paper issued to temporarily finance the acquisitions of NCNG and an equity interest in EasternNC.

• Increase of $1.7 million in interest on long-term debt due to higher amounts of debt outstanding, including amounts associated with the permanent debt financing of NCNG .

• Decrease of $.9 million in interest on refunds due customers due to a significantly higher average payables in 2003 as compared with 2004.

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 April 30, 2004, outstanding short-term borrowings under committed bank lines of credit totaling $200 million ranged from zero to $123 million, and interest rates ranged from 1.39% to 1.6%. During the six months ended April 30, 2004, outstanding short-term borrowings under committed bank lines of credit ranged from zero to $133 million, and interest rates ranged from 1.39% to 1.61%. As of April 30, 2004, we had additional uncommitted lines of credit totaling $68 million on a no fee and as needed, if available, basis. Effective May 1, 2004, our additional

uncommitted lines of credit increased to $103 million.

Our utility operations are weather sensitive. The primary factor that impacts our cash flows from operations is weather. Warmer weather can lead to lower total margin from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but extremely cold weather may lead to conservation by our customers in order to reduce their consumption. Weather outside the normal range of temperatures can impact operating cash flows, thereby altering the need for short-term borrowings to meet current cash requirements. During the twelve months ended April 30, 2004, 53% of our sales and transportation revenues were from residential customers and 31% 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. In addition, 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 three months ended April 30, 2004, was 1% colder than normal, compared with 3% warmer than normal for the same period in 2003. The WNA generated credits to customers of $2.8 million for the three months ended April 30, 2004, and credits to customers of $.9 million for the similar prior period. Weather for the six months ended April 30, 2004, was 1% 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 six months ended April 30, 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 growing imbalance 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.

We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. During the twelve months ended April 30, 2004, we also issued $18 million of common equity through dividend reinvestment and stock purchase plans.

On June 4, 2004, the Board of Directors approved a share repurchase plan of up to 3 million shares. Rather than issuing new shares, we plan to make open market purchases to fund needs generated by the dividend reinvestment and stock purchase plan, by the employee stock purchase plan and by stock-based incentive compensation plans. We project annual open market purchases to total approximately 600,000 shares.

As of April 30, 2004, our capitalization consisted of 42% in long-term debt and 58% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

As of April 30, 2004, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services which changed its outlook from negative to stable on April 13, 2004. Our long-term debt is rated “A3” by Moody’s Investors Service which changed its outlook from negative to stable on April 28, 2004. 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, short-term bank lines of credit and accounts receivable financing. 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 April 30, 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 April 30, 2004, and accounts payable and accounts receivable increased during this same period due to seasonality, higher gas prices, the growth of our business, including the acquisitions of NCNG and EasternNC, 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 April 30, 2004, were $24.9 million, compared with $18.1 million in the similar prior period. Utility construction expenditures in the six months ended April 30, 2004, were $46 million, compared with $35.7 million in the similar prior period. Utility construction expenditures in the twelve months ended April 30, 2004, were $90.6 million, compared with $79.7 million in the similar prior period. Due to projected growth in our service area, significant utility construction expenditures are expected to continue.

As of April 30, 2004, our estimated future contractual obligations for long-term debt, purchase obligations and capital and operating leases were as follows:


In thousands	Payments Due by Period
	Less than		1-3		4-5		After
Contractual Obligations	1 Year		Years		Years		5 Years		Total
Long-term debt	$	2,000	$	35,000	$	—	$	625,000	$	662,000
Purchase obligations*		131,171		304,711		195,463		389,946		1,021,291
Capital leases		2		—		—		—		2
Operating leases		4,162		7,058		1,390		1,637		14,247

*Purchase obligations consist of pipeline and storage capacity and gas supply contracts that are 100% recoverable through PGA procedures.

Off-balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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 our Form 10-K. We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted. These interim financial statements should be read together with the consolidated financial statements, notes and the critical accounting policies and estimates included in our Form 10-K.

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 the 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 2004. We are currently evaluating the effect of the FSP on our plan.

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. As a result of deregulation, we expect this highly competitive environment to continue.

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

• 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 cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock.

• Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts will allow us to remain competitive. Natural gas is an unregulated commodity subject to market supply and demand and price volatility. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging 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 regulations and cost of compliance.

• Earnings from our equity investments. We have investments in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks.

All of these factors are difficult to predict and many are beyond our control. Accordingly, while we believe the assumptions underlying these forward-looking statements to be reasonable, there can be no assurance that these statements will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “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 for natural gas.

Interest Rate Risk

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

As of April 30, 2004, we had no short-term debt outstanding. During the three months ended April 30, 2004, short-term debt ranged from zero to $123 million, with interest rates ranging from 1.39% to 1.6%. During the six months ended April 30, 2004, short-term debt ranged from zero to $133 million, with interest rates ranging from 1.39% to 1.61%. The carrying amount of our short-term debt approximates fair value.

Information as of April 30, 2004, about our long-term debt that is sensitive to changes in interest rates is presented below.


	Expected Maturity Date																		Fair Value as of
																			April 30,
In thousands	2004			2005		2006			2007		2008		Thereafter			Total			2004
Fixed Rate
Long — Term Debt	$	2,000		$	—	$	35,000		$	—	$	—	$	625,000		$	662,000		$	806,329
Average Interest
Rate		10.06	%		—		9.44	%		—		—		6.90	%		7.04	%

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various durations for the forward sales and purchase of natural gas. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers 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 April 30, 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.

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits –


3.1		By-Laws, dated February 27, 2004.

10.1		Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, effective January 1, 2004, between Piedmont Energy Company and Georgia Natural Gas Company.

10.2		Executive Long-Term Incentive Plan, dated February 27, 2004.

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 March 1, 2004, we filed a report on Form 8-K regarding press releases to announce first-quarter operating results and the declaration of a dividend on common stock.

Outside of the period, 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 that will be used to fund our various common stock-based programs, most notably our Dividend Reinvestment and Stock Purchase Plan and Executive Long-Term Incentive Plan.


		Piedmont Natural Gas Company, Inc.

		(Registrant)

Date June 10, 2004		/s/ David J. Dzuricky

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

Date June 10, 2004		/s/ Barry L. Guy

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

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 April 30, 2004 and October 31, 2003, and the results of operations and cash flows for the three months, six months and twelve months ended April 30, 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 following presents the balance in goodwill as of October 31, 2003 and April 30, 2004, and the changes for the six months ended April 30, 2004.

		The purchase price allocation adjustment is primarily due to an increase in the liability for pension restoration, deferred directors’ fees, inventory adjustments and other working capital adjustments based on additional information obtained subsequent to the initial purchase price allocation.

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

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 net periodic benefit cost of defined-benefit

6.		Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 2004, do not necessarily reflect the results to be expected for the full year.

7.		We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months, six months and twelve months ended April 30, 2004 and 2003, is presented below:

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 our regulated utility segment are conducted by the parent company and by EasternNC. Operations of our non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Energy 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 for $130 million. Our share of the proceeds was $26.9 million. We recognized an estimated pre-tax gain of $5.1 million on the sale in the three months ended January 31, 2004. The pre-tax gain was adjusted downward by $.4 million to $4.7 million in the three months ended April 30, 2004, based on preliminary unaudited information received. 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 37,248 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 will be presented in our consolidated financial statements as marketable securities.

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

		We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on income from non-utility activities, at equity, and investment in non-utility activities, at equity. 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.

9.		The consolidated financial statements reflect the accounts of Piedmont, its wholly owned subsidiaries and its 50% equity investment in Eastern North Carolina Natural Gas Company (EasternNC). Our equity interest in EasternNC is considered to be a controlling interest and we have consolidated EasternNC for presentation in the accompanying consolidated financial statements. 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 April 30, 2004, the amount of our retained earnings that represented undistributed earnings of 50% or less owned entities accounted for by the equity method was $21 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 North Carolina Utilities Commission (NCUC).

		We have related party transactions with Cardinal as a transportation customer at rates approved by the NCUC. We record in cost of gas the transportation costs charged by Cardinal. These gas costs for the three months, six months and twelve months ended April 30, 2004 and 2003, are presented below:

		As of April 30, 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 its fiscal quarters ended March 31, 2004 and 2003, is presented below.

		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 with Pine Needle as a customer 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 months, six months and twelve months ended April 30, 2004 and 2003, are presented below:

		Piedmont Energy Company

		Piedmont Energy Company owns 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

		On March 29, 2004, we executed an amended and restated limited liability company (LLC) agreement with AGL Resources, Inc. (AGLR), the other member of SouthStar. This new agreement eliminates the disproportionate sharing provision in the original LLC agreement and allocates earnings and losses starting in January 2004 at 25% to us and 75% to AGLR. In addition,

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 April 30, 2004, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of April 30, 2004, we had forward positions for December 2004 through February 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 April 30, 2004, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of April 30, 2004, we had forward positions for June 2004 through October 2004. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.

		Through April 30, 2004, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of April 30, 2004, we had forward positions for June 2004 through October 2004. Costs associated with our North Carolina hedging program are not

		pre-approved 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 April 30, 2004, the amount in “Refunds due customers” of $27.9 million is net of $3.2 million due from customers for the costs of the North Carolina and South Carolina hedging programs and the related mark-to-market adjustments.

•		$111.6 million due to increased wholesale gas prices charged to customers.

•		$19.8 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.

•		Failure to make payments on any capitalized lease obligation,

•		Bankruptcy, liquidation or insolvency and

(b)		Reports on Form 8-K –

		On March 1, 2004, we filed a report on Form 8-K regarding press releases to announce first-quarter operating results and the declaration of a dividend on common stock.

		Outside of the period, 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 that will be used to fund our various common stock-based programs, most notably our Dividend Reinvestment and Stock Purchase Plan and Executive Long-Term Incentive Plan.