UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended January 31, 2007

or

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

For the transition period from                      to                     

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check One):

Large accelerated filer þ          Accelerated filer o          Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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

Class	Outstanding at March 2, 2007
Common Stock, no par value		74,599,552

TABLE OF CONTENTS

Part I. Financial Information
	Item. 1. Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures about Market Risk
	Item 4. Controls and Procedures
Part II. Other Information
	Item 1. Legal Proceedings
	Item 1A. Risk Factors
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
	Item 6. Exhibits
SIGNATURES
Exhibits
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

Part I. Financial Information

Item. 1. Financial Statements

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

	January 31,		October 31,
	2007		2006
ASSETS
Utility Plant, at original cost	$	2,798,695	$	2,808,992
Less accumulated depreciation		712,307		733,682
Utility plant, net		2,086,388		2,075,310
Other Physical Property, at cost (net of accumulated depreciation of $2,079 in 2007 and $2,040 in 2006)		1,119		1,154
Current Assets:
Cash and cash equivalents		17,952		8,886
Trade accounts receivable (less allowance for doubtful accounts of $3,058 in 2007 and $1,239 in 2006)		222,684		90,493
Income taxes receivable		12,756		30,849
Other receivables		260		160
Unbilled utility revenues		123,490		45,938
Gas in storage		142,776		138,183
Gas purchase options, at fair value		9,965		3,147
Amounts due from customers		62,244		89,635
Prepayments		18,859		62,356
Other		5,408		6,317
Total current assets		616,394		475,964
Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities		80,977		75,330
Goodwill		47,383		47,383
Unamortized debt expense		11,125		11,306
Regulatory cost of removal asset		12,404		12,086
Other		33,781		35,406
Total investments, deferred charges and other assets		185,670		181,511
Total	$	2,889,571	$	2,733,939

See notes to condensed consolidated financial statements.

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	January 31,		October 31,
(In thousands)	2007		2006
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized	$	—	$	—
Common stock — no par value — shares authorized: 200,000 in 2007 and in 2006; shares outstanding: 74,585 in 2007 and 75,464 in 2006		508,587		532,764
Paid-in capital		142		56
Retained earnings		401,600		348,765
Accumulated other comprehensive income		1,684		1,340
Total stockholders’ equity		912,013		882,925
Long-term debt		825,000		825,000
Total capitalization		1,737,013		1,707,925
Current Liabilities:
Notes payable		232,500		170,000
Trade accounts payable		128,520		80,304
Other accounts payable		44,602		50,935
Income taxes accrued		2,028		1,184
Accrued interest		11,691		21,273
Customers’ deposits		25,360		22,308
Deferred income taxes		50,084		25,085
General taxes accrued		7,772		18,522
Amounts due to customers		14		123
Other		14,464		10,655
Total current liabilities		517,035		400,389
Deferred Credits and Other Liabilities:
Deferred income taxes		238,513		235,411
Unamortized federal investment tax credits		3,284		3,417
Cost of removal obligations		335,604		330,104
Other		58,122		56,693
Total deferred credits and other liabilities		635,523		625,625
Total	$	2,889,571	$	2,733,939

See notes to condensed consolidated financial statements.

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

	Three Months Ended
	January 31
	2007			2006
Operating Revenues	$	677,241		$	921,347
Cost of Gas		468,756			711,975
Margin		208,485			209,372
Operating Expenses:
Operations and maintenance		52,210			53,222
Depreciation		21,611			21,887
General taxes		9,259			8,710
Income taxes		43,708			44,392
Total operating expenses		126,788			128,211
Operating Income		81,697			81,161
Other Income (Expense):
Income from equity method investments		5,543			5,751
Non-operating income		131			19
Non-operating expense		(152	)		(67	)
Income taxes		(2,165	)		(2,225	)
Total other income (expense)		3,357			3,478
Utility Interest Charges		14,338			12,642
Net Income	$	70,716		$	71,997
Average Shares of Common Stock:
Basic		74,619			76,685
Diluted		74,938			76,928
Earnings Per Share of Common Stock:
Basic	$	0.95		$	0.94
Diluted	$	0.94		$	0.94
Cash Dividends Per Share of Common Stock	$	0.24		$	0.23

See notes to condensed consolidated financial statements.

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

	Three Months Ended
	January 31
	2007			2006
Cash Flows from Operating Activities:
Net income	$	70,716		$	71,997
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		22,785			22,885
Amortization of investment tax credits		(132	)		(134	)
Allowance for doubtful accounts		1,820			2,965
Allowance for funds used during construction		—			(634	)
Earnings from equity method investments		(5,543	)		(5,751	)
Distributions of earnings from equity method investments		1,196			1,277
Deferred income taxes		27,880			13,219
Change in assets and liabilities		(96,851	)		(224,663	)
Net cash provided by (used in) operating activities		21,871			(118,839	)
Cash Flows from Investing Activities:
Utility construction expenditures		(29,485	)		(51,102	)
Allowance for funds used during construction		(1,340	)		—
Reimbursements from bond fund		—			8,034
Distributions of capital from equity method investments		138			—
Decrease in restricted cash		—			13,103
Other		732			(227	)
Net cash used in investing activities		(29,955	)		(30,192	)
Cash Flows from Financing Activities:
Increase in notes payable		62,500			191,500
Expenses related to issuance of long-term debt		(5	)		—
Issuance of common stock through dividend reinvestment and employee stock plans		3,955			4,916
Repurchases of common stock		(31,395	)		(7,223	)
Dividends paid		(17,905	)		(17,630	)
Net cash provided by financing activities		17,150			171,563
Net Increase in Cash and Cash Equivalents		9,066			22,532
Cash and Cash Equivalents at Beginning of Period		8,886			7,065
Cash and Cash Equivalents at End of Period	$	17,952		$	29,597
Noncash Investing and Financing Activities:
Accrued construction expenditures	$	(2,680	)	$	(4,316	)
Guaranty	$	961			—

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

	Three Months
	Ended January 31,
In thousands except per share amounts	2007		2006
Net Income	$	70,716	$	71,997
Other Comprehensive Income:
Unrealized gain from hedging activities of equity method investments net of tax of $10 in 2007 and $1,424 in 2006		16		2,241
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $211 in 2007 and ($211) in 2006		328		(333	)
Total Comprehensive Income	$	71,060	$	73,905

See notes to condensed consolidated financial statements.

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

1. Unaudited Interim Financial Information.

The condensed consolidated financial statements have not been audited. These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2006.

     Seasonality and Use of Estimates.

In our opinion, the unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at January 31, 2007 and October 31, 2006, the results of operations for the three months ended January 31, 2007 and 2006, and cash flows for the three months ended January 31, 2007 and 2006. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2007 do not necessarily reflect the results to be expected for the full year.

We make estimates and assumptions when preparing the condensed 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

     Significant Accounting Policies.

Our accounting policies are described in Note 1 to our Annual Report on Form 10-K for the year ended October 31, 2006. There were no significant changes to those accounting policies during the three months ended January 31, 2007.

     Rate-Regulated Basis of Accounting.

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, in order to provide for recovery from or refund to utility customers in future periods. The amounts recorded as regulatory assets in the condensed consolidated balance sheets as of January 31, 2007 and October 31, 2006, were $115.1 million and $143.5 million, respectively. The amounts recorded as regulatory liabilities in the condensed consolidated balance sheets as of January 31, 2007 and October 31, 2006, were $341.9 million and $337 million, respectively.

Significant inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with Statement 71. See Note 7 for information on related party transactions.

     Accounting Pronouncements.

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax

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position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. This interpretation is effective the beginning of the first annual period beginning after December 15, 2006. Accordingly, we will adopt FIN 48 in our fiscal year 2008. We are currently assessing the impact FIN 48 may have on our consolidated financial statements; however, we believe the adoption of FIN 48 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under Statement 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. Accordingly, we will adopt Statement 157 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158). Statement 158 requires an employer to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in the financial statements by recognizing in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status rather than only disclosing the funded status in the footnotes to the financial statements. Statement 158 requires employers to recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Under Statement 158, gains and losses, prior service costs and credits, and any remaining transition amounts that have not yet been recognized through net periodic benefit cost will be recognized in accumulated other comprehensive income (OCI), net of tax effects, until they are amortized as a component of net periodic cost. Statement 158 also requires that the company measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year. We are already in compliance with this requirement as our pension plans’ measurement dates are already the same as our fiscal year end date.

The requirement to recognize the funded status of a benefit plan and the related disclosure requirements initially will apply as of the end of the fiscal year ending after December 15, 2006. Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. We believe the adoption of Statement 158 will not have a material effect on our financial position, results of operations or cash flows.

Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any amounts that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. We intend to meet with our regulators in fiscal year 2007 to discuss the regulatory accounting and rate treatment of the impact of the adoption of Statement 158. Assuming regulatory treatment, if Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7 million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could be substantially different depending on the discount rate, asset returns and plan population at that date.

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In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (Statement 159). Statement 159 provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 159 will not have a material impact on our financial position, results of operations or cash flows.

2. Regulatory Matters.

In North Carolina and South Carolina, recoveries of gas costs are subject to annual gas cost recovery proceedings to determine the prudence of our gas purchases. We have been found prudent in all such past proceedings. We are currently undergoing our annual review of gas costs covering the period from June 2005 through May 2006 in North Carolina. A hearing date has been scheduled for April 10, 2007.

3. Accelerated Share Repurchase Program.

On November 3, 2006, we entered into an accelerated share repurchase (ASR) agreement. On November 7, 2006, we purchased and retired 1 million shares of our common stock from an investment bank at the closing price that day of $26.48 per share. Total consideration paid to purchase the shares of $26.6 million, including $118,800 in commissions and other fees, was recorded in “Stockholders’ equity” as a reduction in “Common stock.”

As part of the accelerated share repurchase, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 50 trading days. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 1 million shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price was higher than the November 7, 2006, closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price for the shares purchased was lower than the November 7, 2006, closing price. At settlement on January 19, 2007, we paid cash of $.8 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction in “Common stock.” The $.8 million was the difference between the investment bank’s weighted average purchase price of $27.3234 and the November 7, 2006, closing price of $26.48 per share multiplied by 1 million shares.

4. Earnings Per Share.

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 ended January 31, 2007 and 2006 is presented below.

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	Three Months
In thousands except per share amounts	2007		2006
Net Income	$	70,716	$	71,997
Average shares of common stock outstanding for basic earnings per share		74,619		76,685
Contingently issuable shares under the Executive Long-Term Incentive Plan (LTIP) and Incentive Compensation Plan		319		243
Average shares of dilutive stock		74,938		76,928
Earnings Per Share:
Basic	$	0.95	$	0.94
Diluted	$	0.94	$	0.94

5. Employee Benefit Plans.

Components of the net periodic benefit cost for our defined-benefit pension plans and our postretirement health care and life insurance benefits (OPEB) plan for the three months ended January 31, 2007 and 2006 are presented below.

	2007			2006			2007		2006		2007			2006
In thousands	Qualified Pension						Nonqualified Pension				Other Benefits
Service cost	$	2,938		$	3,149		$	15	$	16	$	330		$	409
Interest cost		3,286			3,971			69		72		471			629
Expected return on plan assets		(4,368	)		(4,987	)		—		—		(318	)		(421	)
Amortization of transition obligation		—			—			—		—		167			240
Amortization of prior service cost		148			268			—		—		—			—
Amortization of actuarial (gain) loss		246			224			—		—		—			(82	)
Total	$	2,250		$	2,625		$	84	$	88	$	650		$	775

We estimate that we will contribute $16.5 million to the qualified pension plans, $.6 million to the nonqualified pension plans and $3 million to the OPEB plan in 2007.

6. Business Segments.

We have two reportable business segments, regulated utility and non-utility activities. These segments were identified based on products and services, regulatory environments and our corporate organization and business decision-making activities. Operations of our regulated utility segment are conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures.

Operations of the regulated utility segment are reflected in operating income in the condensed consolidated statements of income. Operations of the non-utility activities segment are included in the condensed consolidated statements of income in “Income from equity method investments.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance

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expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements for the year ended October 31, 2006.

Operations by segment for the three months ended January 31, 2007 and 2006 are presented below.

	Regulated		Non-Utility
In thousands	Utility		Activities			Total
2007
Revenues from external customers	$	677,241	$	—		$	677,241
Margin		208,485		—			208,485
Operations and maintenance expenses		52,210		135			52,345
Income from equity method investments		—		5,543			5,543
Operating income (loss) before income taxes		125,405		(236	)		125,169
Income before income taxes		111,371		5,218			116,589
2006
Revenues from external customers	$	921,347	$	—		$	921,347
Margin		209,372		—			209,372
Operations and maintenance expenses		53,222		43			53,265
Income from equity method investments		—		5,751			5,751
Operating income (loss) before income taxes		125,553		(172	)		125,381
Income before income taxes		113,141		5,473			118,614

Reconciliations to the condensed consolidated statements of income for the three months ended January 31, 2007 and 2006 are presented below.

In thousands	2007			2006
Operating Income:
Segment operating income before income taxes	$	125,169		$	125,381
Utility income taxes		(43,708	)		(44,392	)
Non-utility activities before income taxes		236			172
Operating Income	$	81,697		$	81,161
Net Income:
Income before income taxes for reportable segments	$	116,589		$	118,614
Income taxes		(45,873	)		(46,617	)
Net Income	$	70,716		$	71,997

7. Equity Method Investments.

The condensed consolidated financial statements include the accounts of wholly-owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the condensed consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the condensed consolidated statements of operations.

We own 21.49% 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 as a transportation customer of Cardinal, and we

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record in cost of gas the transportation costs charged by Cardinal. For each period of three months ended January 31, 2007 and 2006, these gas costs were $1.2 million. As of January 31, 2007 and October 31, 2006, we owed Cardinal $.4 million and $.1 million, respectively.

We own 40% 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 storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For each period of three months ended January 31, 2007 and 2006, these gas costs were $3.2 million. As of January 31, 2007 and October 31, 2006, we owed Pine Needle $.8 million and $1.1 million, respectively.

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement (Restated Agreement), earnings and losses are allocated 25% to us and 75% to the other member, Georgia Natural Gas Company (GNGC), a subsidiary of AGL Resources, Inc., with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States, with most of its business in the unregulated retail gas market in Georgia. We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the three months ended January 31, 2007 and 2006, these gas revenues were $2.7 million and $8.6 million, respectively. As of January 31, 2007 and October 31, 2006, SouthStar owed us $2.1 million and $.8 million, respectively.

Contained in the SouthStar Restated Agreement mentioned above between us and GNGC, there are provisions providing for the disposition of ownership interests between members, including a provision granting three options to GNGC to purchase our ownership interest in SouthStar. By notice no later than November 1, 2007, with the option effective on January 1, 2008 (2008 option), GNGC has the option to purchase one-third of our 30% interest in SouthStar. With the same notice in the following years, GNGC has the option to purchase 50% of our interest to be effective on January 1, 2009 (2009 option), and 100% of our interest to be effective on January 1, 2010. The purchase price would be based on the market value of SouthStar as defined in the Restated Agreement.

If GNGC exercises either the 2008 option or the 2009 option, we, at our discretion, may cause GNGC to purchase our entire ownership interest.

For further information on this provision, please see the Restated Agreement that was filed with the Securities and Exchange Commission (SEC) as Exhibit 10.1 in our Form 10-Q for the quarter ended April 30, 2004.

Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly-owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage is constructing an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that it intends to own and operate. The storage facility is expected to be in service in April 2007. On June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for up to a total of $173.1 million for funding during the construction period. Once in service, and after the satisfaction of certain conditions in the note purchase agreement, the two members of Hardy Storage will pay off 30% of the construction financing with their equity contributions and the remaining 70% debt will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. The other member of Hardy Storage will contribute assets and cash as part of its share of the 30% owner contributions, and we will contribute cash as our share.

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The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. The guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly-owned subsidiary of Piedmont and a sister company of Piedmont Hardy. Our share of the guaranty is capped at $111.5 million. Depending upon the facility’s performance over the first three years after the in-service date, there could be additional construction expenditures of up to $10 million, of which PEP will guarantee 50%.

Securing PEP’s guaranty is a pledge of intercompany notes issued by Piedmont held by non-utility subsidiaries of PEP. Should Hardy Storage be unable to perform its payment obligation under the construction financing, PEP will call on Piedmont for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interests in Hardy Storage.

As we are in the formation stage of the joint venture, we are recording a liability at fair value for this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changes, the fair value of the guaranty is adjusted accordingly through a quarterly evaluation.

On October 26, 2006, Hardy Storage filed an application with the FERC, for an amendment to its certificate of public convenience and necessity for approval of a settlement that establishes revised initial rates based on updated cost estimates. The estimated cost of the project as refiled with the FERC was $164 million, an increase of $43 million from the original application of $121 million, due to higher costs for skilled labor, material and equipment for the project.

As of January 31, 2007, $89.5 million was outstanding under the construction loan, and we have recorded a guaranty liability of $2.8 million. Subsequent to the end of the quarter, an additional $19.7 million became outstanding under the construction financing.

8. Financial Instruments.

We have a syndicated five-year revolving credit facility with aggregate commitments totaling $350 million, which may be increased up to $600 million that includes annual renewal options. This facility includes letters of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $350 million. The facility provides a line of credit for letters of credit of $5 million. The credit facility bears interest based on the 30-day LIBOR rate plus from .15% to .35%, based on our credit ratings. At January 31, 2007 and October 31, 2006, outstanding short-term borrowings under the line as included in “Notes payable” in the condensed consolidated balance sheets were $232.5 million and $170 million, respectively. During the three months ended January 31, 2007, short-term borrowings ranged from $139.5 million to $280.5 million, and when borrowing, interest rates ranged from 5.57% to 5.6% (weighted average of 5.58%). Our credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 54% at January 31, 2007.

We have purchased and sold financial derivative instruments for natural gas in all three states for our gas purchase portfolios. The gains or losses on financial derivatives utilized in the regulated utility segment ultimately will be included in our rates to customers. Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due customers in accordance with Statement 71. Accordingly, there is no earnings impact on the regulated utility segment as a result of the use of these financial derivatives. The fair value of gas purchase options increased from $3.1 million as of October 31, 2006, to $10 million as of January 31, 2007, primarily due to options being exercised or options expiring during the period and an increase in the market values of the financial derivative instruments held at January 31, 2007.

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9. Restructuring.

On April 13, 2006, we announced plans to restructure our management group at an estimated one-time cost of $7 to $8 million. The restructuring plans are part of an ongoing, larger effort aimed at streamlining business processes, capturing operational and organizational efficiencies and improving customer service. The restructuring began with an offer of early retirement for 23 employees in our management group, and eventually included the further consolidation and reorganization of management positions and functions that was completed in July 2006.

Since April 2006, we have recognized a liability and expense of $7.8 million, which was included in operations and maintenance expense for the cost of the restructuring program. This liability included early retirement for 22 employees of the management group and severance for 17 additional employees through further consolidation. Due to the short discount period, the liability for the program was recorded at its gross value.

A reconciliation of activity to the liability during the quarter ended January 31, 2007 is as follows:

In thousands
Beginning liability, October 31, 2006	$	1,155
Costs paid during the quarter		(1,006	)
Adustments to accruals		(66	)
Ending liability, January 31, 2007	$	83

10. Share-Based Payments.

At our annual meeting of shareholders, held March 3, 2006, shareholders approved the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan (ICP) effective November 1, 2005. The ICP permits the grant of annual incentive awards, performance awards, restricted stock, stock options and stock appreciation rights to eligible employees and members of the Board of Directors.

Under our ICP, 65,000 restricted shares of our common stock with a value at the date of grant of $1.7 million were granted to our President and Chief Executive Officer on September 1, 2006. During the vesting period, any dividends paid on these shares will be accrued and converted into additional shares at the closing price on the date of the dividend payment. The restricted shares and any additional shares accrued through dividends will vest over a five-year period only if he is an employee on each vesting date. For the three months ended January 31, 2007, we have recorded $.08 million as compensation expense. We are recording compensation under the ICP on the straight-line method.

Under the LTIP and ICP, the Board of Directors has awarded units to eligible officers and other participants. Depending upon the levels of performance targets achieved by Piedmont during multi-year performance periods, distribution of those awards may be made in the form of shares of common stock and cash withheld for payment of applicable taxes on the compensation. The LTIP and ICP require that a minimum threshold performance be achieved in order for any award to be distributed. For the three months ended January 31, 2007 and 2006, we recorded compensation expense for the LTIP and ICP of $1 million and $1.4 million, respectively. Shares of common stock to be issued under the LTIP and ICP are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

As of January 31, 2007 and October 31, 2006, we have accrued $6 million and $11.4 million for these

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awards. The accrual is based on the fair market value of our stock at the end each quarter. The liability is re-measured to market value at the settlement date.

11. Legal Obligations.

From time to time, we conduct business with unaffiliated third party marketers who act as agents for various industrial customers of ours or who purchase natural gas directly for their own account. We previously had such an arrangement with National Gas Distributors LLC (NGD), which filed a voluntary bankruptcy petition on January 20, 2006. The bankruptcy trustee for this petition claimed that certain amounts paid by NGD to us for gas supply constituted preference payments, and sought their return. We disputed these claims and vigorously defended our position on the matter. In October 2006, we agreed to settle with the NGD bankruptcy trustee in order to avoid protracted litigation and the expense thereof. During the fourth quarter, we recorded our estimated liability under the settlement. In January 2007, the bankruptcy court approved the settlement. The settlement did not have a material adverse impact on our financial position, results of operations or cash flows.

Otherwise, we have only routine litigation in the normal course of business.

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

Forward-Looking Statements

This report as well as other documents we file with the 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. These statements are based on management’s current expectations and information currently available, and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to:

• Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our effectiveness in achieving the allowed rates of return and initiate rate proceedings or operating changes as needed. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated.

• 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, and fluctuations in the wholesale prices of natural gas and competitive energy sources.

• Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies, and we expect this competitive environment to continue. We must be able to adapt to the changing environments and the competition.

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

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

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• The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and 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.

• Capital market conditions. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets could affect access to and cost of capital.

• 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 allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.

• Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.

• Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.

• Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

• Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.

• Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and we assume such risks as an equity investor.

Other factors may be described elsewhere in this report. All of these factors are difficult to predict and many of them are beyond our control. For these reasons, you should not rely on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “will,” “assume,” “can,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

Forward-looking statements are only as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Please reference our website at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website as soon as reasonably practicable after the report is filed with or furnished to the SEC.

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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 portions of North Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments ^___ the regulated utility segment and the non-utility activities segment.

The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the three months ended January 31, 2007, 96% of our earnings before taxes came from our regulated utility segment.

The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.

Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are generated during the winter season. During warm winters or unevenly cold winters, heating customers may significantly reduce their consumption of natural gas. In South Carolina and Tennessee, we have weather normalization adjustment (WNA) mechanisms that are designed to protect a portion of our revenues against warmer-than-normal weather as deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a Customer Utilization Tracker (CUT) provides for the recovery of our approved margin per customer independent of both weather and other consumption patterns of residential and commercial customers. For further information, see “Our Business” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Over the past few years, there have been significant increases in the wholesale cost of natural gas. The relationship between supply and demand has the greatest impact on wholesale gas prices. Increased wholesale prices for natural gas are being driven by increased demand that is exceeding the growth in accessible supply. Continued high gas prices could shift our customers’ preference away from natural gas toward other energy sources, particularly in the industrial market. High gas prices could also affect consumption levels as customers react to high bills. We expect that the wholesale price of natural gas will remain high and volatile until natural gas supply and demand are in better balance.

The majority of our natural gas supplies come from the Gulf Coast region. We believe that diversification of our supply portfolio is in our customers’ best interest. We have a firm transportation contract pending with Midwestern Gas Transmission Company for additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. Due to regulatory delays impacting the commencement of construction for service during the winter of 2006-2007, Midwestern has only been able to provide a portion of the original contracted capacity. It is anticipated that the entire capacity will be available during the 2007-2008 winter. We have also executed an agreement with Hardy Storage Company, LLC for market-area storage capacity in West Virginia with an anticipated in-service date in April 2007.

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Part of our strategic plan is to manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers and the pursuit of customer growth opportunities in our service areas. We strive for quality customer service by investing in technology, processes and people. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

Our strategic plan includes a focus on maintaining a long-term debt-to-capitalization ratio within a range of 45 to 50%. We will continue to stress the importance of maintaining a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

Results of Operations

We reported net income of $70.7 million for the three months ended January 31, 2007, as compared to $72 million for the similar period in 2006. The following table sets forth a comparison of the components of our income statement for the three months ended January 31, 2007, as compared with the three months ended January 31, 2006.

								Percent
	Three Months Ended January 31							Increase
In thousands, except per share amounts	2007		2006		Change			(Decrease)
Operating Revenues	$	677,241	$	921,347	$	(244,106	)		(26.5	)%
Cost of Gas		468,756		711,975		(243,219	)		(34.2	)%
Margin		208,485		209,372		(887	)		(0.4	)%
Operating Expenses		126,788		128,211		(1,423	)		(1.1	)%
Operating Income		81,697		81,161		536			0.7	%
Other Income (Expense)		3,357		3,478		(121	)		(3.5	)%
Utility Interest Charges		14,338		12,642		1,696			13.4	%
Net Income	$	70,716	$	71,997	$	(1,281	)		(1.8	)%
Average Shares of Common Stock:
Basic		74,619		76,685		(2,066	)		(2.7	)%
Diluted		74,938		76,928		(1,990	)		(2.6	)%
Earnings Per Share of Common Stock:
Basic	$	0.95	$	0.94	$	0.01			1.1	%
Diluted	$	0.94	$	0.94	$	—			—	%

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Key statistics are shown in the table below for the three months ended January 31, 2007 and 2006.

Gas Deliveries, Customers, Weather Statistics and Number of Employees
	Three Months Ended									Percent
	January 31									Increase
Gas Sales and Deliveries in Dekatherms (in thousands)	2007			2006			Variance			(Decrease)
Sales Volumes		45,432			48,146			(2,714	)		(5.6	)%
Transportation Volumes		21,481			18,033			3,448			19.1	%
Throughput		66,913			66,179			734			1.1	%
Secondary Market Volumes		9,660			8,826			834			9.4	%
Customers Billed (at period end)		939,509			918,879			20,630			2.2	%
Gross Customer Additions		8,927			9,368			(441	)		(4.7	)%
Degree Days
Actual		1,615			1,723			(108	)		(6.3	)%
Normal		1,900			1,906			(6	)		(0.3	)%
Percent colder (warmer) than normal		(15.0	)%		(9.6	)%		n/a			n/a
Number of Employees		1,967			2,107			(140	)		(6.6	)%

Operating Revenues

Operating revenues decreased $244.1 million for the three months ended January 31, 2007, compared with the similar period in 2006 primarily due to the following decreases:

• $185.2 million from decreased commodity gas costs passed through to sales customers.

• $33.9 million from decreased volumes to sales customers.

• $29.8 million from decreased commodity gas costs in secondary market activity. Secondary market transactions consist of off-system sales and capacity release arrangements.

These decreases were partially offset by the following increases:

• $6.1 million increase from the CUT mechanism amount in 2007 compared to the 2006 CUT amount. As discussed in “Financial Condition and Liquidity” below, the CUT mechanism became effective November 1, 2005 in North Carolina to offset the impact of conservation and unusually cold or warm weather on residential and commercial customer billings and margin.

• $5 million from increased transportation volumes.

• $2.8 million increase from the WNA surcharged in 2007 compared to the 2006 WNA surcharged. As discussed in “Financial Condition and Liquidity” below, we had a WNA in South Carolina and Tennessee to offset the impact of unusually cold or warm weather on residential and commercial customer billings and margin.

Cost of Gas

Cost of gas decreased $243.2 million for the three months ended January 31, 2007, compared with the similar period in 2006 primarily due to the following decreases:

• $185.2 million from lower commodity gas costs passed through to customers.

• $33.9 million from decreased volumes to sales customers.

• $30.2 million from lower commodity gas costs in secondary market activity.

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Under purchased gas adjustment (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 “Amounts due from customers” or “Amounts due to customers” in the condensed consolidated balance sheets.

Margin

Margin decreased $.9 million for the three months ended January 31, 2007, compared with the similar period in 2006, primarily due to $1.5 million of gas cost accounting adjustments related to lost and unaccounted for gas and interest charges related to gas purchases, $.75 million of annual adjustments under the CUT settlement and warmer weather, which were partially offset by growth in the residential and commercial customer base.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for upstream capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity prices, which account for approximately 70% of revenues.

Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this document or in our Form 10-K for the year ended October 31, 2006. These include WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization in South Carolina, Gas Purchase Incentive Plan in Tennessee, CUT in North Carolina, negotiated loss treatment in all three jurisdictions and the collection of uncollectible gas costs in all three jurisdictions.

We retain 25% of margins generated through off-system sales and capacity release activity related to North Carolina and South Carolina, with 75% credited to the customers through the PGA mechanism.

Operations and Maintenance Expenses

Operations and maintenance expenses decreased $1 million for the three months ended January 31, 2007, compared with the similar period in 2006 primarily due to the following decreases:

• $1.5 million in payroll primarily related to the 2006 management restructuring program, including impacts on short-term and long-term incentive plan accruals.

• $.6 million in the provision for uncollectibles due to a change in methodology approved by the Public Service Commission of South Carolina (PSCSC) and lower charge-offs. Effective November 1, 2006, the PSCSC authorized the recovery of all uncollected gas costs through the gas deferred account. As a result, only the portion of accounts written off relating to non-gas costs, or margin, is included in base rates and accordingly, only this portion is included in the provision for uncollectibles expense. A similar mechanism has been in place for our North Carolina operations since November 2005 and for our Tennessee operations since March 2004.

• $.5 million in materials primarily due to less maintenance activity during the period.

• $.3 million in regulatory expense primarily due to lower regulatory fees, which are calculated on revenues, which are lower as a result of a decrease in the commodity cost of gas.

• $.2 million in transportation costs primarily due to a decrease in the cost of fuel and the impact of fewer vehicles being used as a result of the automated meter reading initiative.

These decreases were partially offset by the following increases:

• $1.2 million in outside services primarily due to enhanced customer service initiative activities.

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• $.7 million in other corporate expense primarily due to the funding of conservation programs under our CUT settlement.

Depreciation

Depreciation expense decreased $.3 million for the three months ended January 31, 2007 compared with the similar period in 2006 primarily due to asset retirements, in the normal course of business, of personal computers whose depreciable lives were reduced from six years to four years.

General Taxes

General taxes increased $.5 million for the three months ended January 31, 2007 as compared with the similar period in 2006 primarily due to increases in gross receipts taxes and state franchise taxes.

Other Income (Expense)

Income from equity method investments includes our earnings from joint venture investments. Non-operating income is comprised of non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and other miscellaneous expenses.

The changes in Other Income (Expense) are not significant.

Utility Interest Charges

Utility interest charges increased $1.7 million for the three months ended January 31, 2007, compared with the similar period in 2006 primarily due to the following:

• $2.3 million increase in interest on long-term debt due to the issuance on June 20, 2006 of $200 million of insured quarterly notes due June 1, 2036.

• $.3 million increase in interest expense on regulatory treatment of certain components of deferred income taxes.

• $.7 million decrease due to an increase in the allowance for funds used during construction allocated to debt.

• $.3 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2007.

Our Business

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 1,016,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 62,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

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. We also regularly evaluate opportunities for obtaining natural gas supplies from different production regions and supply sources to maximize our natural gas portfolio

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flexibility and reliability, including the diversification of our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have a firm transportation contract pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. Due to regulatory delays impacting commencement of construction, we have only contracted for 40,000 of the total 120,000 dekatherms per day of capacity for the winter of 2006-2007 with the difference being covered by short-term firm winter arrangements. It is anticipated that the entire capacity will be available during the 2007-2008 winter. We have also executed an agreement with Hardy Storage Company, LLC for market-area storage capacity in West Virginia with an anticipated in-service date in April 2007.

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 6 to the condensed consolidated financial statements.

Our utility operations are regulated by the NCUC, PSCSC and the Tennessee Regulatory Authority as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated 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 and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution and transmission 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, which are generally applicable to companies doing business in the United States of America.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We maintain service offices in Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, 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.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially offset the impact of unusually cold or warm weather on bills rendered during the months of November through March for weather-sensitive customers. 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. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin per customer independent of both weather or other consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. The WNA mechanism remains in effect for our South Carolina and Tennessee operations.

We invest in joint ventures to complement or supplement income from our regulated utility operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate the project with a major

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factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding exiting joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

Financial Condition and Liquidity

To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. We believe that these sources will continue to allow us to meet our needs for working capital, construction expenditures, anticipated debt redemptions and dividend payments.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations resulting from such factors as weather, natural gas purchases and prices, gas inventory storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas in storage and the collection of amounts billed to customers during the peak heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, paying down short-term debt and decreases in receipts from customers.

During the peak heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The value of the gas can vary significantly from period to period due to volatility in the price of natural gas, which is a function of market fluctuations in the price of natural gas, along with our changing requirements for storage volumes. Our natural gas costs and amounts due to/from customers represent the difference between natural gas costs that we have paid to suppliers and amounts that we have collected from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections of gas costs under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their consumption. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Net cash provided by (used in) operating activities was $21.9 million and $(118.8) million for the three months ended January 31, 2007 and 2006, respectively. Net cash provided by operating activities reflects a $1.3 million decrease in net income for 2007, compared with 2006, as well as changes in working capital as described below:

• Trade accounts receivable and unbilled utility revenues decreased $211.6 million in the current period primarily due to the current winter period being 15% warmer than normal and 6% warmer than the similar prior period, and amounts billed to customers reflected lower gas costs in 2007 as compared with 2006. Volumes sold to residential and commercial customers decreased 2.5 million dekatherms as compared with the prior year period primarily due to the warmer weather.

• Amounts due to/from customers increased $27.3 million in the current period from the deferral of gas costs yet to be billed and collected from customers.

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• Gas in storage decreased $4.6 million in the current period primarily due to decreases in the average gas costs.

• Prepaid gas costs decreased $41.5 million in the current period as compared with a decrease of $48.2 million in the prior period. Under asset management agreements, prepaid gas costs during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until November 1, the beginning of the winter period.

• Trade accounts payable increased $50.9 million in the current period primarily due to gas purchases to meet customer demand during the winter months.

Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have had a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for weather-sensitive customers. The WNA in South Carolina and Tennessee generated charges to customers of $7.9 million in the three months ended January 31, 2007 and charges to customers of $5.1 million in the three months ended January 31, 2006. In Tennessee, adjustments are made directly to the customer’s bills. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or refund to all customers in the class. The CUT mechanism in North Carolina provides for any over- or under-collection of approved margin per customer that operates independently of both weather and consumption patterns of residential and commercial customers. The CUT mechanism provided margin of $19.5 million and $13.4 million in the three months ended January 31, 2007 and 2006, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the CUT.

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 not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary.

We have commission approval in North Carolina, South Carolina and Tennessee that places additional credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, such as price volatility, the availability of natural gas in relation to other energy forms, general economic conditions, weather, energy conservation and the ability to convert from natural gas to other energy sources. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with 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 a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. 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 and organizations. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

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Cash Flows from Investing Activities. Net cash used in investing activities was $30 million and $30.2 million for the three months ended January 31, 2007 and 2006, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the three months ended January 31, 2007, were $29.5 million as compared to $51.1 million in the similar prior period. The decrease was primarily due to several large projects in 2006, such as automated meter reading, certain revenue-producing projects in the districts and enterprise telephony that are now complete or nearing completion. Reimbursements from the bond fund decreased $8 million from 2006 as construction of gas infrastructure in eastern North Carolina is complete.

During the three months ended January 31, 2006, the restrictions on cash totaling $13.1 million were removed in connection with implementing the NCUC order in a general rate proceeding. As ordered by the NCUC, such cash had been held in an expansion fund to extend natural gas service to unserved areas of the state.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. Gross utility construction expenditures totaling $144.8 million, primarily to serve customer growth, are budgeted for fiscal year 2007; however, we are not contractually obligated to expend capital until work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

Cash Flows from Financing Activities. Net cash provided by financing activities was $17.2 million and $171.6 million for the three months ended January 31, 2007 and 2006, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and employee stock plans, net of purchases under the common stock repurchase program. When required, we sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. As of January 31, 2007, our current assets were $616.4 million and our current liabilities were $517 million, primarily due to seasonal requirements as discussed above.

As of January 31, 2007, we had committed lines of credit under our senior credit facility effective April 24, 2006, of $350 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000 plus six basis points for any unused amount up to $350 million. Outstanding short-term borrowings increased from $170 million as of October 31, 2006, to $232.5 million as of January 31, 2007, primarily due to the purchase of shares under the ASR program, payments in January 2007 for interest on long-term debt and property taxes and payments to suppliers for the winter heating season. During the three months ended January 31, 2007, short-term borrowings ranged from $139.5 million to $280.5 million, and when borrowing, interest rates ranged from 5.57% to 5.6% (weighted average of 5.58%).

As of January 31, 2007, under our credit facility, we had available letters of credit of $5 million of which $1.4 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. As of January 31, 2007, unused lines of credit available under our senior credit facility, including the issuance of the letters of credit, totaled $116.1 million.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. 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

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customers may not be able to pay their gas bills on a timely basis.

During the three months ended January 31, 2007, we issued $4 million of common stock through dividend reinvestment and stock purchase plans. On November 7, 2006, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $26.6 million. On January 19, 2007, we settled the transaction and paid an additional $.8 million. Under the Common Stock Open Market Purchase Program, as described in Part II, Item 2, we paid $31.4 million during the three months ended January 31, 2007 for 1.2 million shares of common stock that are available for reissuance to these plans.

Through the ASR program, we may repurchase and subsequently retire up to approximately four million shares of common stock by no later than December 31, 2010, including the 1 million shares repurchased in April 2006 and the 1 million shares repurchased in November 2006. These shares are in addition to shares that are repurchased on a normal basis through the open market program.

We have paid quarterly dividends on our common stock since 1956. The amount of cash dividends that may be paid is restricted by provisions contained in certain note agreements under which long-term debt was issued. As of January 31, 2007, our retained earnings were not restricted. On March 7, 2007, the Board of Directors declared a quarterly dividend on common stock of $.25 per share, payable April 13 to shareholders of record at the close of business on March 23.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings.

The components of our total debt outstanding to our total capitalization as of January 31, 2007 and 2006, and October 31, 2006, are summarized in the table below.

	January 31					October 31					January 31
In thousands	2007		Percentage			2006		Percentage			2006		Percentage
Short-term debt	$	232,500		12	%	$	170,000		9	%	$	350,000		18	%
Current portion of long-term debt		—		0	%		—		0	%		35,000		2	%
Long-term debt		825,000		42	%		825,000		44	%		625,000		32	%
Total debt		1,057,500		54	%		995,000		53	%		1,010,000		52	%
Common stockholders’ equity		912,013		46	%		882,925		47	%		939,862		48	%
Total capitalization (including short-term debt)	$	1,969,513		100	%	$	1,877,925		100	%	$	1,949,862		100	%

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 a number of quantitative factors, including debt to total capitalization, operating cash flows relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. Rating agencies also consider qualitative factors, such as the consistency of our earnings over time, the quality of management and business strategy, the risks associated with our utility and non-utility businesses and the regulatory commissions that establish rates in the states where we operate.

As of January 31, 2007, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

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We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of January 31, 2007, we are in compliance with all default provisions.

Estimated Future Contractual Obligations

During the three months ended January 31, 2007, there were no material changes to our estimated future contractual obligations that were disclosed in our Form 10-K for the year ended October 31, 2006, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases that were discussed in Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2006.

Piedmont Energy Partners, Inc., a wholly-owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves levels of performance and credit risk that are not included on our condensed consolidated balance sheets. The possibility of having to perform on the guaranty is largely dependent upon the future operations of the joint venture, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 7 to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates

We prepare the condensed 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.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, goodwill and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of the critical accounting estimates presented in our Form 10-K for the year ended October 31, 2006, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Management has discussed these critical accounting estimates with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates since October 31, 2006.

Recent Accounting Pronouncements

In June 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement,

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classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. This interpretation is effective the beginning of the first annual period beginning after December 15, 2006. Accordingly, we will adopt FIN 48 in our fiscal year 2008. We are currently assessing the impact FIN 48 may have on our consolidated financial statements; however, we believe the adoption of FIN 48 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Statement 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under Statement 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with earlier application encouraged. Accordingly, we will adopt Statement 157 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (Statement 158). Statement 158 requires an employer to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare and other postretirement plans in the financial statements by recognizing in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status rather than only disclosing the funded status in the footnotes to the financial statements. Statement 158 requires employers to recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Under Statement 158, gains and losses, prior service costs and credits, and any remaining transition amounts that have not yet been recognized through net periodic benefit cost will be recognized in accumulated other comprehensive income (OCI), net of tax effects, until they are amortized as a component of net periodic cost. Statement 158 also requires that the company measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year. We are already in compliance with this requirement as our pension plans’ measurement dates are already the same as our fiscal year end date.

The requirement to recognize the funded status of a benefit plan and the related disclosure requirements initially will apply as of the end of the fiscal year ending after December 15, 2006. Accordingly, we will adopt the funded status portion of Statement 158 as of October 31, 2007. We believe the adoption of Statement 158 will not have a material effect on our financial position, results of operations or cash flows.

Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any amounts that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. We intend to meet with our regulators in fiscal year 2007 to discuss the regulatory accounting and rate treatment of the impact of the adoption of Statement 158. Assuming regulatory treatment, if Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7 million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could be substantially different depending on the discount rate, asset returns and plan population at that date.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (Statement 159). Statement 159 provides companies with an option to report selected

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financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although Statement 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. Statement 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has elected also to apply Statement 157 early. Accordingly, we will adopt Statement 159 no later than our first fiscal quarter in 2009. We believe the adoption of Statement 159 will not have a material impact on our financial position, results of operations or cash flows.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We hold all financial instruments discussed in this item for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Our exposure to interest rate changes relates primarily to short-term debt. We are exposed to interest rate changes to long-term debt when we are in the market to issue long-term debt. As of January 31, 2007, all of our long-term debt was issued at fixed rates. Exposure to gas cost variations relates to the wholesale supply, demand and price of natural gas.

Interest Rate Risk

We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period depending upon many factors, including 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 January 31, 2007, we had $232.5 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 5.58%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1.7 million during the three months ended January 31, 2007.

As of January 31, 2007, all of our long-term debt was at fixed interest rates and, therefore, not subject to interest rate risk.

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various durations for the forward sale and purchase of a portion of our natural gas requirements. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. Due to cost-based rate regulation in our utility operations, we recover prudently incurred purchased gas costs, and the costs of hedging our gas supplies are passed on to customers through PGA procedures.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 2 of this Form 10-Q.

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Item 4. Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-Q. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-Q, our disclosure controls and procedures were effective in that they provide reasonable assurances that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the first quarter of fiscal 2007 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

From time to time, we conduct business with unaffiliated third party marketers who act as agents for various industrial customers of ours or who purchase natural gas directly for their own account. We previously had such an arrangement with NGD, which filed a voluntary bankruptcy petition on January 20, 2006. The bankruptcy trustee for this petition claimed that certain amounts paid by NGD to us for gas supply constituted preference payments, and sought their return. We disputed these claims and vigorously defended our position on the matter. In October 2006, we agreed to settle with the NGD bankruptcy trustee in order to avoid protracted litigation and the expense thereof. During the fourth quarter, we recorded our estimated liability under the settlement. In January 2007, the bankruptcy court approved the settlement. The settlement did not have a material adverse impact on our financial position, results of operations or cash flows.

Otherwise, we have only routine litigation in the normal course of business.

Item 1A. Risk Factors

During the three months ended January 31, 2007, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2006.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     c) Issuer Purchases of Equity Securities.

          The following table provides information with respect to purchases of common stock under the Common Stock Open Market Purchase Program during the three months ended January 31, 2007.

					Total Number of		Maximum Number
	Total Number				Shares Purchased		of Shares That May
	of Shares		Average Price		as Part of Publicly		Yet be Purchased
Period	Purchased		Paid Per Share		Announced Program		Under the Program
Beginning of the period								6,612,074
11/1/06 — 11/30/06		1,000,000	$	27.44		1,000,000		5,612,074
12/1/06 — 12/31/06		—	$	—		—		5,612,074
01/1/07 — 01/31/07		150,000	$	26.35		150,000		5,462,074
Total		1,150,000	$	27.30		1,150,000

The Common Stock Open Market Purchase Program was announced on June 4, 2004, to purchase up to three million shares of common stock for reissuance under our dividend reinvestment, stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares are referred to as our accelerated share repurchase program and have an expiration date of December 31, 2010.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments” except out of net earnings available for restricted payments. As of January 31, 2007, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits

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.

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SIGNATURES

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

Piedmont Natural Gas Company, Inc.  

(Registrant) 

Date March 9, 2007	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date March 9, 2007	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller (Principal Accounting Officer)

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Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended January 31, 2007

Exhibits

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