UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended July 31, 2008

or

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

For the transition period from __________________ to __________________

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company 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 x

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

Class	Outstanding at September 2, 2008
Common Stock, no par value	73,278,668

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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
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)

	July 31,		October 31,
	2008		2007
ASSETS
Utility Plant, at original cost	$	3,032,451	$	2,894,514
Less accumulated depreciation		801,320		752,977
Utility plant, net		2,231,131		2,141,537
Other Physical Property, at cost (net of accumulated depreciation of $2,313 in 2008 and $2,197 in 2007)		903		1,007
Current Assets:
Cash and cash equivalents		4,853		7,515
Restricted cash		—		2,211
Trade accounts receivable (less allowance for doubtful accounts of $2,360 in 2008 and $544 in 2007)		126,586		97,625
Income taxes receivable		—		15,699
Other receivables		546		649
Unbilled utility revenues		2,948		24,121
Gas in storage		170,168		131,439
Gas purchase options, at fair value		3,221		13,725
Amounts due from customers		73,387		76,035
Prepayments		48,375		61,007
Other		4,666		5,318
Total current assets		434,750		435,344
Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities		103,012		95,193
Goodwill		48,852		48,852
Overfunded postretirement asset		45,646		36,256
Unamortized debt expense		10,093		10,565
Regulatory cost of removal asset		12,873		11,939
Other		39,231		39,625
Total investments, deferred charges and other assets		259,707		242,430
Total	$	2,926,491	$	2,820,318

See notes to condensed consolidated financial statements.

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	July 31,		October 31,
(In thousands)	2008		2007
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value - 175 shares authorized	$	—	$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 73,326 in 2008 and 74,208 in 2007		474,060		497,570
Paid-in capital		671		402
Retained earnings		446,477		379,682
Accumulated other comprehensive income		621		720
Total stockholders’ equity		921,829		878,374
Long-term debt		824,533		824,887
Total capitalization		1,746,362		1,703,261
Current Liabilities:
Notes payable		169,500		195,500
Trade accounts payable		151,766		97,156
Other accounts payable		23,558		46,411
Income taxes accrued		5,013		1,224
Accrued interest		11,662		21,811
Customers’ deposits		22,744		22,930
Deferred income taxes		25,841		16,422
General taxes accrued		13,455		18,980
Amounts due to customers		7,048		162
Other		4,948		3,915
Total current liabilities		435,535		424,511
Deferred Credits and Other Liabilities:
Deferred income taxes		303,409		267,479
Unamortized federal investment tax credits		2,708		2,983
Regulatory liability for postretirement benefits		12,456		13,876
Accumulated provision for postretirement benefits		18,038		17,469
Cost of removal obligations		371,399		351,738
Other		36,584		39,001
Total deferred credits and other liabilities		744,594		692,546
Commitments and Contingencies (Note 10)
Total	$	2,926,491	$	2,820,318

See notes to condensed consolidated financial statements.

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

	Three Months Ended						Nine Months Ended
	July 31						July 31
	2008			2007			2008			2007
Operating Revenues	$	354,709		$	224,442		$	1,777,357		$	1,433,262
Cost of Gas		277,689			149,284			1,312,031			989,892
Margin		77,020			75,158			465,326			443,370
Operating Expenses:
Operations and maintenance		49,738			52,849			155,598			159,938
Depreciation		23,581			22,432			69,179			66,038
General taxes		7,928			7,643			25,080			25,260
Income taxes		(6,846	)		(8,787	)		69,092			58,795
Total operating expenses		74,401			74,137			318,949			310,031
Operating Income		2,619			1,021			146,377			133,339
Other Income (Expense):
Income from equity method investments		4,278			5,849			30,730			34,989
Non-operating income		(87	)		253			541			437
Non-operating expense		(251	)		(181	)		(1,317	)		(559	)
Income taxes		(1,410	)		(2,151	)		(11,638	)		(13,481	)
Total other income (expense)		2,530			3,770			18,316			21,386
Utility Interest Charges		12,827			13,931			41,479			42,029
Net Income (Loss)	$	(7,678	)	$	(9,140	)	$	123,214		$	112,696
Average Shares of Common Stock:
Basic		73,368			73,938			73,355			74,304
Diluted		73,368			73,938			73,628			74,576
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.12	)	$	1.68		$	1.52
Diluted	$	(0.10	)	$	(0.12	)	$	1.67		$	1.51
Cash Dividends Per Share of Common Stock	$	0.26		$	0.25		$	0.77		$	0.74

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)

	Nine Months Ended
	July 31
	2008			2007
Cash Flows from Operating Activities:
Net income	$	123,214		$	112,696
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		72,504			69,563
Amortization of investment tax credits		(275	)		(342	)
Allowance for doubtful accounts		1,816			581
Gain on sale of land		(201	)		—
Earnings from equity method investments		(30,730	)		(34,989	)
Distributions of earnings from equity method investments		33,041			26,195
Deferred income taxes		45,413			29,443
Stock-based compensation expense		252			252
Change in assets and liabilities		9,091			11,341
Net cash provided by operating activities		254,125			214,740
Cash Flows from Investing Activities:
Utility construction expenditures		(140,952	)		(92,732	)
Allowance for funds used during construction		(3,473	)		(3,094	)
Contributions to equity method investments		(10,790	)		—
Distributions of capital from equity method investments		121			330
Proceeds from sale of land and buildings		2,043			—
(Increase) decrease in restricted cash		2,196			(743	)
Other		1,593			3,877
Net cash used in investing activities		(149,262	)		(92,362	)
Cash Flows from Financing Activities:
Decrease in notes payable		(26,000	)		(22,500	)
Expenses related to issuance of long-term debt		—			(5	)
Retirement of long-term debt		(354	)		—
Expenses related to expansion of the short-term facility		(106	)		—
Issuance of common stock through dividend reinvestment and employee stock plans		11,637			11,793
Repurchases of common stock		(36,228	)		(54,240	)
Dividends paid		(56,474	)		(55,041	)
Net cash used in financing activities		(107,525	)		(119,993	)
Net Increase (Decrease) in Cash and Cash Equivalents		(2,662	)		2,385
Cash and Cash Equivalents at Beginning of Period		7,515			8,886
Cash and Cash Equivalents at End of Period	$	4,853		$	11,271
Noncash Investing and Financing Activities:
Accrued construction expenditures	$	908		$	1,749
Guaranty		101			463

See notes to condensed consolidated financial statements.

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

	Three Months						Nine Months
	Ended July 31						Ended July 31
	2008			2007			2008			2007
Net Income (Loss)	$	(7,678	)	$	(9,140	)	$	123,214		$	112,696
Other Comprehensive Income:
Unrealized gain from hedging activities of equity method investments, net of tax of $524 and $129 for the three months ended July 31, 2008 and 2007, respectively, and $994 and $212 for the nine months ended July 31, 2008 and 2007, respectively		814			199			1,552			329
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of ($263) and $42 for the three months ended July 31, 2008 and 2007, respectively, and ($1,059) and ($1,037) for the nine months ended July 31, 2008 and 2007, respectively		(411	)		65			(1,652	)		(1,617	)
Total Comprehensive Income (Loss)	$	(7,275	)	$	(8,876	)	$	123,114		$	111,408

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. We have prepared the unaudited consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) are omitted in this interim report under these SEC rules and regulations. 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, 2007.

     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 July 31, 2008 and October 31, 2007, the results of operations for the three months and nine months ended July 31, 2008 and 2007, and cash flows for the nine months ended July 31, 2008 and 2007. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 2008 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, 2007. There were no significant changes to those accounting policies during the nine months ended July 31, 2008 with the exception of changes related to the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes” (Statement 109), and Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FSP 48-1).

In June 2006, the FASB issued FIN 48 to clarify the accounting for uncertain tax positions in accordance with Statement 109, and in May 2007 issued FSP 48-1. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Additionally, FIN 48 provides guidance on derecognition, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. FSP 48-1 clarifies when a tax position is considered effectively settled under FIN 48. We adopted the provisions of FIN 48 on November 1, 2007. As a result of the implementation of FIN 48, there was no material impact on the consolidated financial statements and no adjustment to retained earnings. The amount of unrecognized tax benefits at November 1, 2007 was $.5 million, of which $.3 million would impact our

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effective income tax rate if recognized. We recorded $.1 million of interest related to unrecognized tax benefits. There are no material changes to the Company’s unrecognized tax benefits during the nine months ended July 31, 2008.

We recognize accrued interest and penalties related to unrecognized tax benefits in operating expenses in the condensed consolidated statements of operations, which is consistent with the recognition of these items in prior reporting periods.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to federal income tax examinations for tax years ending before and including October 31, 2005, and with few exceptions, state income tax examinations by tax authorities for years ended before and including October 31, 2003.

We do not currently anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

     Rate-Regulated Basis of Accounting

We follow 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 July 31, 2008 and October 31, 2007, were $132.2 million and $134 million, respectively. The amounts recorded as regulatory liabilities in the condensed consolidated balance sheets as of July 31, 2008 and October 31, 2007, were $397.7 million and $374 million, respectively.

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 6 for information on related party transactions.

     Accounting Pronouncements

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. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date.

• Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data.

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• Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options.

In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. 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 for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis. Accordingly, we will adopt Statement 157 for our fiscal year beginning November 1, 2008 with the exception of the application of the provision related to nonfinancial assets and liabilities. We believe the adoption of Statement 157 will not have a material impact on our financial position, results of operations or cash flows.

In April 2007, the FASB issued FSP FIN 39-1 to amend paragraph 3 of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). The FSP amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we are evaluating the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 for our fiscal year beginning November 1, 2008.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” (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 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to elect the option to measure any applicable financial assets or liabilities at fair value pursuant to the provisions of Statement 159.

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In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Statement 161 also amended SFAS 107, “Disclosures about Fair Value of Financial Instruments” (Statement 107), to clarify that derivative instruments are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is not expected to have a material impact on our financial position, results of operations, or cash flows. We will adopt Statement 161 on February 1, 2009.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature established by the FASB. Statement 162 will be effective sixty days following the SEC approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have any impact on our financial position, results of operations or cash flows. We will adopt Statement 162 when it becomes effective.

2. Regulatory Matters

In North Carolina and South Carolina, our recovery of gas costs is subject to annual gas cost review proceedings to determine the prudence of our gas purchases. We have been found prudent in all such past proceedings.

On August 1, 2008, we filed testimony in North Carolina in support of our gas cost purchasing practices for the period ending May 31, 2008. We anticipate the hearing on our application in the fourth calendar quarter of 2008. We are unable to determine the outcome of this proceeding at this time.

On August 20, 2008, the Public Service Commission of South Carolina (PSCSC) approved our purchased gas adjustments and found our gas purchasing policies to be prudent for the period covering the twelve months ended March 31, 2008.

On June 15, 2008, we filed with the PSCSC a cost and revenue study as permitted by the Natural Gas Rate Stabilization Act requesting a change in rates from those approved by the PSCSC in an order dated October 12, 2007. On September 2, 2008, we, the Office of Regulatory Staff and the South Carolina Energy Users Committee filed a settlement agreement with the PSCSC addressing our proposed rate changes. The settlement, if approved, will result in a $1.5 million annual decrease in margin based on a return on equity of 11.2%, effective November 1, 2008. The settlement is pending approval by the PSCSC. We are unable to determine the outcome of this proceeding at this time.

On March 31, 2008, we filed a general rate application with the North Carolina Utilities Commission (NCUC) requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $40.5 million, or 4% above the current annual revenues. On August 25, 2008, we

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and the Public Staff filed a settlement stipulation with the NCUC in which both parties agreed to an annual revenue increase of $15.7 million. All intervening parties are in agreement with the stipulation with the exception of the Attorney General’s office. In addition to the revenue increase, the stipulation also includes cost allocation and rate design changes under our existing rate schedules, permanent extension of the margin decoupling mechanism approved by the NCUC on an experimental basis in our last general rate proceeding in 2005, approval to implement energy conservation and efficiency programs of $1.3 million annually with appropriate cost recovery mechanisms, and changes to the existing service regulations and tariffs. These new settlement rates would become effective November 1, 2008, if approved by the NCUC. A hearing before the NCUC has been set for September 9, 2008. We cannot predict the outcome of the proceeding at this time.

We have filed an annual report for the twelve months ended December 31, 2006 with the Tennessee Regulatory Authority (TRA) that reflects the transactions in the deferred gas cost account for the Actual Gas Cost Adjustment mechanism. On June 10, 2008, the TRA staff filed its final audit report, with which we concurred. On August 7, 2008, the TRA issued an order adopting all findings from the staff audit. The order includes cost of gas adjustments for the calendar year 2006 review period. We do not expect a material margin impact from these gas cost adjustments.

3. 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 and nine months ended July 31, 2008 and 2007 is presented below.

	Three Months						Nine Months
In thousands except per share amounts	2008			2007			2008		2007
Net Income (Loss)	$	(7,678	)	$	(9,140	)	$	123,214	$	112,696
Average shares of common stock outstanding for basic earnings per share		73,368			73,938			73,355		74,304
Contingently issuable shares under:
Executive Long-Term Incentive Plan (LTIP) and Incentive Compensation Plan (ICP) *		—			—			273		272
Average shares of dilutive stock		73,368			73,938			73,628		74,576
Earnings (Loss) Per Share of Common Stock:
Basic		($0.10	)		($0.12	)	$	1.68	$	1.52
Diluted		($0.10	)		($0.12	)	$	1.67	$	1.51

* For the three months ended July 31, 2008 and 2007, the inclusion of 268 and 252 contingently issuable shares, respectively, would have been antidilutive.

4. Employee Benefit Plans

Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our defined contribution plans. These amendments apply to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, all of these amendments will apply to employees covered by the Nashville, Tennessee bargaining unit contract.

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Effective January 1, 2008, the defined benefit pension plan was amended to close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued in the future for existing employees. Employees hired prior to January 1, 2008 will continue to participate in the amended traditional defined benefit pension plan. The amendment does not affect any pension benefit earned as of December 31, 2007. For service earned after December 31, 2007, a consistent rate will be applied to each year of service so that employees accrue benefits more evenly. For service earned prior to January 1, 2008, the rate used in the formula to calculate an employee’s pension benefit is greater for the first twenty years of service than it is for the next fifteen years of service. Employees can be credited with up to a total of 35 years of service. When an employee leaves the company, his benefit payment will be calculated as the greater of the accrued benefit as of December 31, 2007 under the old formula plus the accrued benefit under the new formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the new formula.

Employees hired or rehired after December 31, 2007 will not participate in the amended traditional pension plan but will be participants in the new Money Purchase Pension (MPP) plan, a defined contribution plan. Under the MPP plan, we will annually deposit a percentage of each participant’s pay into an account of the MPP plan.

Effective January 1, 2008, we made changes to our 401(k) plans which are profit sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). Prior to January 1, 2008, we matched 50% of employee contributions up to the first 10% of pay contributed. Beginning January 1, 2008, employees are able to receive a company match of 100% up to the first 5% of pay contributed. Employees are still able to contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis, up to the Tax Code annual contribution limit. We automatically enroll all affected non-participating employees in the 401(k) plan as of January 1, 2008 at a 2% contribution rate unless the employee chooses not to participate by notifying our plan administrator. For employees who are automatically enrolled in the 401(k) plan, we will automatically increase their contributions by 1% each year to a maximum of 5% unless the employee chooses to opt out of the automatic increase by contacting our plan administrator. Employee contributions and match are automatically invested in a diversified portfolio of stocks and bonds. Employees may change their contribution rate and investments at any time.

We provide certain health care and life insurance benefits to eligible retirees under our OPEB plan. Employees are first eligible to retire and receive these benefits at age 55 with ten or more years of service after the age of 45. Effective January 1, 2008, new employees have to complete ten years of service after age 50 to be eligible for benefits, and no benefits will be provided to those employees after age 65 when they are automatically eligible for Medicare benefits to cover health costs.

Components of the net periodic benefit cost for our defined-benefit pension plans and our OPEB plan for the three months ended July 31, 2008 and 2007 are presented below.

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	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2008			2007			2008		2007		2008			2007
Service cost	$	1,400		$	2,575		$	7	$	15	$	304		$	330
Interest cost		2,886			2,987			69		69		489			471
Expected return on plan assets		(4,382	)		(3,931	)		—		—		(355	)		(318	)
Amortization of transition obligation		—			—			—		—		162			167
Amortization of prior service (credit) cost		(464	)		136			—		—		—			—
Amortization of actuarial loss		—			237			—		—		—			—
Total	$	(560	)	$	2,004		$	76	$	84	$	600		$	650

Components of the net periodic benefit cost for our defined-benefit pension plans and our OPEB plan for the nine months ended July 31, 2008 and 2007 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2008			2007			2008		2007		2008			2007
Service cost	$	5,726		$	8,452		$	20	$	45	$	938		$	991
Interest cost		8,556			9,560			208		207		1,508			1,412
Expected return on plan assets		(12,671	)		(12,669	)		—		—		(1,096	)		(953	)
Amortization of transition obligation		—			—			—		—		500			500
Amortization of prior service (credit) cost		(1,420	)		433			—		—		—			—
Amortization of actuarial loss		—			728			—		—		—			—
Total	$	191		$	6,504		$	228	$	252	$	1,850		$	1,950

We contributed $11 million to the qualified pension plan in June 2008, and anticipate that we will contribute $.6 million to the nonqualified pension plans and $2.7 million to the OPEB plan in 2008.

Because 2008 is the first year of the MPP plan, we have made no contributions to the plan to date. We anticipate contributions being made in December 2008 or January 2009.

5. 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 current 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 operations. Operations of the non-utility activities segment are included in the condensed consolidated statements of operations in “Income from equity method investments” and “Non-operating income.”

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We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on 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, 2007.

Operations by segment for the three months and nine months ended July 31, 2008 and 2007 are presented below.

	Regulated						Non-utility
	Utility						Activities						Total
In thousands	2008			2007			2008			2007			2008			2007
Three Months
Revenues from external customers	$	354,709		$	224,442		$	—		$	—		$	354,709		$	224,442
Margin		77,020			75,158			—			—			77,020			75,158
Operations and maintenance expenses		49,738			52,849			60			59			49,798			52,908
Income from equity method investments		—			—			4,278			5,849			4,278			5,849
Operating loss before income taxes		(4,227	)		(7,766	)		(34	)		(129	)		(4,261	)		(7,895	)
Income (loss) before income taxes		(17,250	)		(21,407	)		4,136			5,631			(13,114	)		(15,776	)
Nine Months
Revenues from external customers	$	1,777,357		$	1,433,262		$	—		$	—		$	1,777,357		$	1,433,262
Margin		465,326			443,370			—			—			465,326			443,370
Operations and maintenance expenses		155,598			159,938			128			230			155,726			160,168
Income from equity method investments		—			—			30,730			34,989			30,730			34,989
Operating income (loss) before income taxes		215,469			192,134			(237	)		(415	)		215,232			191,719
Income before income taxes		173,784			150,661			30,160			34,311			203,944			184,972

Reconciliations to the condensed consolidated statements of operations for the three months and nine months ended July 31, 2008 and 2007 are presented below.

	Three Months						Nine Months
In thousands	2008			2007			2008			2007
Operating Income:
Segment operating income (loss)	$	(4,261	)	$	(7,895	)	$	215,232		$	191,719
Utility income taxes		6,846			8,787			(69,092	)		(58,795	)
Non-utility activities		34			129			237			415
Operating income	$	2,619		$	1,021		$	146,377		$	133,339
Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(13,114	)	$	(15,776	)	$	203,944		$	184,972
Income taxes		5,436			6,636			(80,730	)		(72,276	)
Net income (loss)	$	(7,678	)	$	(9,140	)	$	123,214		$	112,696

6. 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

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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 NCUC. We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. These transportation costs for the three months and nine months ended July 31, 2008 and 2007 are presented below.

	Three Months				Nine Months
In thousands	2008		2007		2008		2007
Transportation Costs	$	1,035	$	1,181	$	3,081	$	3,465

As of July 31, 2008 and October 31, 2007, we owed Cardinal $.3 million.

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 (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. These gas storage costs for the three and nine months ended July 31, 2008 and 2007 are presented below.

	Three Months				Nine Months
In thousands	2008		2007		2008		2007
Gas Storage Costs	$	3,022	$	2,764	$	8,493	$	8,962

As of July 31, 2008 and October 31, 2007, we owed Pine Needle $1 million and $.9 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 being conducted 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. Our operating revenues from these sales for the three months and nine months ended July 31, 2008 and 2007 are presented below.

	Three Months				Nine Months
In thousands	2008		2007		2008		2007
Operating Revenues	$	4,826	$	2,849	$	11,055	$	6,432

As of July 31, 2008 and October 31, 2007, SouthStar owed us $1.7 million.

The SouthStar Restated Agreement includes a provision granting three options to GNGC to purchase

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our ownership interest in SouthStar. By November 1, 2007, with the option effective on January 1, 2008 (2008 option), GNGC had 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. GNGC did not exercise the 2008 option. If GNGC exercises the 2009 option, we, at our discretion, may cause GNGC to purchase our entire ownership interest at that time.

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 owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC. Phase one service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals, and Phase II service levels began on April 1, 2008. Hardy Storage is now in the final stages of project construction.

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. As of July 31, 2008, $123.4 million remains outstanding on the interim notes.

For the nine months ended July 31, 2008, we made equity contributions of $10.8 million to fund additional construction expenditures, with our equity contributions as of that date totaling $23.7 million. Upon completion of project construction, including any contingency wells if needed, the members intend to target a capitalization structure of 70% debt and 30% equity. After the satisfaction of certain conditions in the note purchase agreement, amounts outstanding under the interim notes will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur May 2010. To the extent that more funding is needed, the members will evaluate funding options at that time.

The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. Our 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 for contingency wells, 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 interest in Hardy Storage.

We record 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.

As of July 31, 2008, with $123.4 million outstanding under the construction financing, we have recorded a guaranty liability of $1.2 million.

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We have related party transactions as a customer of Hardy Storage and record in cost of gas the Hardy storage costs charged to us. These gas storage costs for the three and nine months ended July 31, 2008 and 2007 are presented below.

	Three Months				Nine Months
In thousands	2008		2007		2008		2007
Gas Storage Costs	$	2,326	$	2,520	$	6,898	$	3,318

As of July 31, 2008 and October 31, 2007, we owed $.8 million for Hardy Storage services.

7. Financial Instruments

We have a syndicated five-year revolving credit facility with aggregate commitments totaling $450 million that may be increased up to $600 million, and that includes annual renewal options and letters of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million, of which $1.9 million and $1.5 million were issued and outstanding at July 31, 2008 and October 31, 2007, respectively. These letters of credit are used to guarantee claims from self-insurance under our general liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from .15% to .35%, based on our credit ratings.

As of July 31, 2008 and October 31, 2007, outstanding short-term borrowings under the credit facility as included in “Notes payable” in the condensed consolidated balance sheets were $169.5 million and $195.5 million, respectively. During the three months ended July 31, 2008, short-term borrowings ranged from $29.5 million to $219 million, and interest rates ranged from 2.63% to 2.98% (weighted average of 2.73%). During the nine months ended July 31, 2008, short-term borrowings ranged from $9 million to $353 million, and interest rates ranged from 2.63% to 5.51% (weighted average of 3.97%). 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 52% at July 31, 2008.

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through purchased gas cost adjustment (PGA) procedures. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. Our risk management policies allow us to use financial instruments to hedge risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide increased price stability for our customers. We have a management-level Energy Risk Management Committee that monitors compliance with our risk management policies.

Through July 31, 2008, we purchased and sold financial options for natural gas for our Tennessee gas supply portfolio. As of July 31, 2008, we had forward positions for November 2008 through March 2009. The cost of these options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our Tennessee Incentive Plan (TIP) approved by the TRA.

Through July 31, 2008, we purchased and sold financial options for natural gas for our South Carolina gas supply portfolio. As of July 31, 2008, we had forward positions for September 2008 through June 2010. The costs of these options are pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas cost hedging plan approved by the PSCSC.

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Through July 31, 2008, we purchased and sold financial options for natural gas for our North Carolina gas supply portfolio. As of July 31, 2008, we had forward positions for September 2008 through June 2010. Costs associated with our North Carolina hedging program are not pre-approved by the NCUC but are treated as gas costs subject to annual gas cost review proceedings by the NCUC.

Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due to customers or amounts due from customers in accordance with Statement 71. We mark the derivative instruments to market with a corresponding entry to “Amounts due to customers” or “Amounts due from customers.” Accordingly, there is no earnings impact of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives. As of July 31, 2008 and October 31, 2007, the total fair value of gas purchase options included in the consolidated balance sheets was $3.2 million and $13.7 million, respectively.

8. Termination Benefits

During 2007, we began implementing additional organizational changes under our business process improvement program to streamline business processes, capture operational and organizational efficiencies and improve customer service. As a part of this effort, we began initiating changes in our customer payment and collection processes, including no longer accepting customer payments in our business offices and streamlining our district operations. We also further consolidated our call centers. Collections of delinquent accounts will be consolidated in our central business office. These initiatives continue to be phased in during 2008.

We have accrued costs in connection with these initiatives in the form of severance benefits to employees who will be either voluntarily or involuntarily severed. These benefits are under existing arrangements and are accounted for in accordance with SFAS No. 112, “Employers’ Accounting for Postemployment Benefits.” All costs are included in the regulated utility segment in operations and maintenance expenses in the condensed consolidated statements of operations.

We accrued $3.6 million during the year ended October 31, 2007 and paid $2.2 million for the year ended October 31, 2007. For the nine months ended July 31, 2008, we adjusted the accrual downward by $.2 million and paid $.7 million. The liability as of July 31, 2008 and October 31, 2007 was $.5 million and $1.4 million, respectively.

9. Share-Based Payments

Under the LTIP and the ICP, approved by the Company’s shareholders on March 3, 2006, the Board of Directors has awarded units to eligible officers and other participants. Depending upon the level of performance 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 level be achieved in order for any award to be distributed. For the three months and nine months ended July 31, 2008, we recorded compensation expense for the LTIP and ICP of $1.2 million and $3.5 million, respectively. For the three months and nine months ended July 31, 2007, we recorded compensation expense for the LTIP and ICP of $9,300 and $2.1 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 July 31, 2008 and October 31, 2007, we have accrued $7.6 million and $6.2 million for these

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

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. We recorded compensation expense under this grant of $84,100 for the three months ended July 31, 2008 and 2007, and $252,400 for the nine months ended July 31, 2008 and 2007. We are recording compensation under the ICP on the straight-line method.

10. Commitments and Contingent Liabilities

     Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to sixteen years. The time periods for gas supply contracts range from one to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the condensed consolidated statements of operations as part of gas purchases and included in cost of gas.

     Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases.

     Legal

We have only routine immaterial litigation in the normal course of business.

     Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general liability policies. We had $1.9 million in letters of credit that were issued and outstanding at July 31, 2008. Additional information concerning letters of credit is included in Note 7.

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     Environmental Matters

Our three state regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.

Several years ago, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount, charged to the estimated environmental liability, that released us from any investigation and remediation liability. On one of these nine properties, we performed additional clean-up activities, including the removal of an underground storage tank. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. Three other MGP sites that we also have owned, leased or operated were not included in the settlement. In addition to these sites, we acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with our acquisition in 2002 of certain assets and liabilities of North Carolina Gas Services, a division of NUI Utilities, Inc.

In connection with our 2003 acquisition of North Carolina Natural Gas Corporation (NCNG), several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the cost of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. We know of no such pending or threatened claims.

In October 2003, in connection with a 2003 NCNG general rate case proceeding, the NCUC ordered an environmental regulatory liability of $3.5 million be established for refund to customers over the three-year period beginning November 1, 2003. This liability resulted from a payment made to NCNG by its insurers prior to our acquisition of NCNG. As a part of the 2005 general rate case proceeding discussed in Note 3 of our Form 10-K for the year ended October 31, 2007, the NCUC ordered a new three-year amortization period for the unamortized balance as of June 30, 2005, beginning November 1, 2005.

Further evaluations of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

Additional information concerning commitments and contingencies is set forth in Note 7 of our Form 10-K for the year ended October 31, 2007.

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:

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• Regulatory issues affecting us and those from whom we purchase natural gas transportation and storage service, 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.

• 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 or to tariff rates that are at lower per-unit margins than that customer’s existing rate.

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

• The capital-intensive nature of our business. In order to maintain 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.

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• 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.

Overview

Piedmont Natural Gas Company is an energy services company whose principal business is 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 96% 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 nine months ended July 31, 2008, 85% 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

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impact of colder-than-normal weather by reducing the amounts we can charge our customers. In North Carolina, a margin decoupling mechanism, known as the Customer Utilization Tracker (CUT), provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. For further information, see discussion of these mechanisms in “Our Business” and “Financial Condition and Liquidity” below.

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. In January 2008, we began receiving firm, long-term transportation contract service from Midwestern Gas Transmission Company (Midwestern) that provides access to Canadian and Rocky Mountain gas supplies and the Chicago hub, primarily to serve our Tennessee markets. In April 2007, we began receiving firm, long-term market area storage service from Hardy Storage, a storage facility in West Virginia.

As part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand, we intend to design, construct, own and operate a LNG peak storage facility in Robeson County, North Carolina with the capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand. The LNG facility will be a part of our regulated utility segment and is planned to be in service for the 2012-2013 winter heating season.

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. 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 profitable 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. We remain focused on implementing and improving our underlying business processes and cost structures.

We seek to maintain a long-term debt-to-capitalization ratio within a range of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

While we have seen a decline in customer growth in our new construction residential market during this fiscal year, we have experienced a slight increase in residential new customer conversions over the same year-to-date period of 2007. We do not anticipate that this decline in our customer growth rate will have a significant effect on our financial results for the year. We, as one of the five founding members of the Council for Responsible Energy, are leading the effort to promote natural gas and inform consumers about the environmental benefits of using natural gas directly in their homes and business for the most efficient use of natural gas. This positions us, now and into the future, as the source of an environmentally responsible energy choice for our customers.

Results of Operations

We reported a net loss of $7.7 million for the three months ended July 31, 2008, as compared to a net loss of $9.1 million for the same period in 2007. The following table sets forth a comparison of the components of our statements of operations for the three months ended July 31, 2008, as compared with the three months ended July 31, 2007.

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										Percent
	Three Months Ended July 31									Increase
In thousands, except per share amounts	2008			2007			Change			(Decrease)
Operating Revenues	$	354,709		$	224,442		$	130,267			58.0	%
Cost of Gas		277,689			149,284			128,405			86.0	%
Margin		77,020			75,158			1,862			2.5	%
Operating Expenses		74,401			74,137			264			0.4	%
Operating Income		2,619			1,021			1,598			156.5	%
Other Income (Expense)		2,530			3,770			(1,240	)		(32.9	)%
Utility Interest Charges		12,827			13,931			(1,104	)		(7.9	)%
Net Loss	$	(7,678	)	$	(9,140	)	$	1,462			16.0	%
Average Shares of Common Stock:
Basic		73,368			73,938			(570	)		(0.8	)%
Diluted		73,368			73,938			(570	)		(0.8	)%
Loss Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.12	)	$	0.02			16.7	%
Diluted	$	(0.10	)	$	(0.12	)	$	0.02			16.7	%

We reported net income of $123.2 million for the nine months ended July 31, 2008, as compared to $112.7 million for the same period in 2007. The following table sets forth a comparison of the components of our statements of operations for the nine months ended July 31, 2008, as compared with the nine months ended July 31, 2007.

								Percent
	Nine Months Ended July 31							Increase
In thousands, except per share amounts	2008		2007		Change			(Decrease)
Operating Revenues	$	1,777,357	$	1,433,262	$	344,095			24.0	%
Cost of Gas		1,312,031		989,892		322,139			32.5	%
Margin		465,326		443,370		21,956			5.0	%
Operating Expenses		318,949		310,031		8,918			2.9	%
Operating Income		146,377		133,339		13,038			9.8	%
Other Income (Expense)		18,316		21,386		(3,070	)		(14.4	)%
Utility Interest Charges		41,479		42,029		(550	)		(1.3	)%
Net Income	$	123,214	$	112,696	$	10,518			9.3	%
Average Shares of Common Stock:
Basic		73,355		74,304		(949	)		(1.3	)%
Diluted		73,628		74,576		(948	)		(1.3	)%
Earnings Per Share of Common Stock:
Basic	$	1.68	$	1.52	$	0.16			10.5	%
Diluted	$	1.67	$	1.51	$	0.16			10.6	%

Key statistics are shown in the table below for the three months ended July 31, 2008 and 2007.

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended									Percent
	July 31									Increase
Gas Sales and Deliveries in Dekatherms (in thousands)	2008			2007			Variance			(Decrease)
Sales Volumes		11,228			11,948			(720	)		(6.0	)%
Transportation Volumes		27,703			24,320			3,383			13.9	%
Throughput		38,931			36,268			2,663			7.3	%
Secondary Market Volumes		13,246			8,034			5,212			64.9	%
Customers Billed (at period end)		943,294			924,105			19,189			2.1	%
Gross Customer Additions		4,111			7,102			(2,991	)		(42.1	)%
Degree Days
Actual		35			46			(11	)		(23.9	)%
Normal		53			52			1			1.9	%
Percent warmer than normal		(34.0	)%		(11.5	)%		n/a			n/a
Number of Employees (at period end)		1,846			1,901			(55	)		(2.9	)%

Key statistics are shown in the table below for the nine months ended July 31, 2008 and 2007.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Nine Months Ended									Percent
	July 31									Increase
Gas Sales and Deliveries in Dekatherms (in thousands)	2008			2007			Variance			(Decrease)
Sales Volumes		95,293			95,117			176			0.2	%
Transportation Volumes		70,654			67,760			2,894			4.3	%
Throughput		165,947			162,877			3,070			1.9	%
Secondary Market Volumes		45,383			26,623			18,760			70.5	%
Customers Billed (at period end)		943,294			924,105			19,189			2.1	%
Gross Customer Additions		15,755			22,859			(7,104	)		(31.1	)%
Degree Days
Actual		2,953			2,869			84			2.9	%
Normal		3,148			3,174			(26	)		(0.8	)%
Percent warmer than normal		(6.2	)%		(9.6	)%		n/a			n/a
Number of Employees (at period end)		1,846			1,901			(55	)		(2.9	)%

Operating Revenues

Operating revenues increased $130.3 million for the three months ended July 31, 2008, compared with the same period in 2007 primarily due to the following increases:

• $102.8 million from revenues in secondary market transactions due to increased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

• $30 million from increased commodity gas costs passed through to sales customers.

• $3.2 million related to commission-approved adjustments to rate components.

These increases were partially offset by the following decrease:

• $5.2 million of commodity gas costs from lower volumes to sales customers due to

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conservation and weather.

Operating revenues increased $344.1 million for the nine months ended July 31, 2008, compared with the same period in 2007 primarily due to the following increases:

• $241.9 million from revenues in secondary market transactions due to increased activity and gas costs.

• $68 million from increased commodity gas costs passed through to sales customers.

• $26.2 million related to commission-approved adjustments to rate components.

• $3.4 million increased revenues under the CUT mechanism. As discussed in “Financial Condition and Liquidity,” the CUT mechanism in North Carolina adjusts for variations in residential and commercial use per customer including those due to conservation and weather.

Cost of Gas

Cost of gas increased $128.4 million for the three months ended July 31, 2008, compared with the same period in 2007 primarily due to the following increases:

• $102.1 million from commodity gas costs in secondary market transactions.

• $30 million from increased commodity gas costs passed through to sales customers.

• $1.7 million from adjustments to fixed and commodity gas cost recovery.

These increases were partially offset by the following decrease:

• $5.2 million of commodity gas costs from lower volumes to sales customers due to conservation and weather.

Cost of gas increased $322.1 million for the nine months ended July 31, 2008, compared with the same period in 2007 primarily due to the following increases:

• $240 million from commodity gas costs in secondary market transactions due to increased activity and gas costs.

• $68 million from increased commodity gas costs passed through to sales customers.

• $9.6 million from adjustments to fixed and commodity cost recovery.

Under PGA procedures in all three states, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are added to or deducted from cost of gas and included in “Amounts due from customers” or “Amounts due to customers” in the condensed consolidated balance sheets.

Margin

Margin increased $1.9 million for the three months ended July 31, 2008, compared with the same period in 2007, primarily due to growth in our residential and commercial customer base and secondary marketing, partially offset by $.5 million from the regulatory ruling that discontinued the capitalizing and amortizing of storage demand charges effective November 1, 2007.

Margin increased $22 million for the nine months ended July 31, 2008, compared with the same period in 2007, primarily due to the following increases:

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• $8.9 million from period to period net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to gas cost accounting reviews.

• $8.8 million from growth in our residential and commercial customer base.

• $1.9 million from secondary market activity.

• $1 million from the regulatory ruling that discontinued the capitalizing and amortizing of storage demand charges effective November 1, 2007.

• $.8 million from growth in our power generation customer base.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity prices and transportation and storage costs, which account for approximately 74% of revenues.

Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2007. These include WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization in South Carolina, secondary market activity in North Carolina and South Carolina, TIP in Tennessee, CUT in North Carolina and negotiated loss treatment and the collection of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans. All of our secondary market transactions are part of our regulatory gas supply arrangements.

Operations and Maintenance Expenses

Operations and maintenance expenses decreased $3.1 million for the three months ended July 31, 2008, compared with the same period in 2007 primarily due to the following decreases:

• $2 million in payroll expense primarily due to the 2007 accrual of severance benefits related to the continuing business process improvement initiative, net of the impact of incentive plan accruals and fewer employees.

• $1.2 million in employee benefits expense primarily due to reductions in pension expense resulting from changes in plan design and fewer employees.

• $.6 million in risk insurance expense primarily due to accruals recorded in 2007.

These decreases were partially offset by the following increase:

• $.9 million in contract labor primarily due to telecom and financial, gas accounting and compliance systems.

Operations and maintenance expenses decreased $4.3 million for the nine months ended July 31, 2008, compared with the same period in 2007 primarily due to the following decreases:

• $7.4 million in employee benefits expense due to reductions in pension expense resulting from changes in plan design and fewer employees and lower group insurance expense from fewer employees and lower claims expense.

• $1.5 million in payroll expense primarily due to the 2007 accrual of severance benefits related to the continuing business process improvement initiative, net of the impact of incentive plan accruals and fewer employees.

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These decreases were partially offset by the following increases:

• $3.7 million in contract labor primarily due to telecom and financial, gas accounting and compliance systems.

• $.8 million in utilities primarily due to increased charges for measurement systems.

• $.6 million in advertising.

Depreciation

Depreciation expense increased $1.1 million and $3.1 million for the three months and nine months ended July 31, 2008 compared with the same period in 2007, respectively, primarily due to increases in plant in service.

General Taxes

General taxes were comparable for the three months and nine months ended July 31, 2008 as compared with the same periods in 2007.

Other Income (Expense)

Income from equity method investments decreased $1.6 million for the three months ended July 31, 2008 as compared with the same period in 2007 primarily due to the following:

• $1.1 million in earnings from Hardy Storage primarily due to higher operations and maintenance expenses, depreciation and general taxes.

• $.3 million in earnings from SouthStar primarily due to warmer weather.

Income from equity method investments decreased $4.3 million for the nine months ended July 31, 2008 as compared with the same period in 2007 primarily due to the following changes:

• $4.6 million decrease in earnings from SouthStar related to rising commodity prices, price lags, reduced opportunities from the management of storage and transportation assets, a Georgia Public Service Commission consent agreement related to retail pricing and a loss on weather derivatives.

• $.7 million increase in earnings from Hardy Storage primarily due to phase one service commencing in April 2007, partially offset by higher operations and maintenance expenses, depreciation and general taxes.

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. In our second quarter of 2008, we contributed $.5 million to the Piedmont Natural Gas Foundation. Other changes were not significant.

Utility Interest Charges

Utility interest charges decreased $1.1 million for the three months ended July 31, 2008 compared with the same period in 2007 primarily due to the following decreases:

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

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	debt.
•	$.3 million in net interest expense on amounts due to/from customers due to lower net receivables in the current period.

Utility interest charges decreased $.6 million for the nine months ended July 31, 2008 compared with the same period in 2007 primarily due to the following decreases:

• $.4 million in interest expense on regulatory treatment of certain components of deferred income taxes.

• $.4 million due to an increase in the allowance for funds used during construction allocated to debt.

Our Business

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million 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 in our core business to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional opportunities and challenges 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 flexibility and reliability, including the diversification of our supply portfolio away from the Gulf Coast region. In January 2008, we began receiving 120,000 dekatherms per day of firm, long-term transportation service from Midwestern that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. In April 2007, we began receiving firm, long-term market-area storage service from Hardy Storage in West Virginia that provides 39,100 dekatherms per day of withdrawal service for the winter of 2007-2008. Hardy Storage withdrawal capabilities will increase over three phases. Phase 1 (2007-2008 heating season) began at 57% of capacity, phase 2 (2008-2009 heating season) began April 1, 2008 at 85% of capacity, and phase 3 (2009-2010 heating season) is planned at 100% of capacity. We have a 50% equity interest in this project which is more fully discussed in Note 6 to the condensed consolidated financial statements.

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 5 to the condensed consolidated financial statements.

Our utility operations are regulated by the NCUC, PSCSC and the TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also 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, safety and security 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

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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 provide service to 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. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered during the months of November through March for residential and commercial 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 margin decoupling mechanism or the WNA.

Greenhouse gas emissions have emerged as an important public policy topic with a number of legislative and regulatory proposals being in various phases of discussion. We are actively participating in and monitoring these proposals and discussions because they could impact our business either directly or indirectly. We cannot predict the outcome of any of these proposals at this time.

We invest in joint ventures to complement or supplement income from our regulated utility operations. If an opportunity aligns with our overall business strategies and allows us to leverage the strengths of our markets along with our core abilities, we analyze and evaluate the project with a major 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 ventures by having management representatives on the governing board of the ventures. We monitor actual performance against expectations. Decisions regarding exiting joint ventures would be based on many factors, including performance results and continued alignment with our business strategies.

The earnings from our investment in SouthStar may fluctuate significantly from period to period as a result of weather, volatility in natural gas pricing and mark-to-market or lower-of-cost-or-market inventory valuation impacts and other unanticipated events.

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, investments in joint ventures, anticipated debt redemptions and dividend payments.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash

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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, natural gas 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 winter 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 winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural 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. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in amounts due to/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 from customers 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 heating bills. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Our customers’ heating costs could be significantly impacted by increases in the cost of gas for the 2008-2009 winter heating season as compared to the prior year. As a result, we may incur additional bad debt expense during the winter heating season, as well as increased customer conservation. If wholesale gas prices remain high, we may incur more short-term debt to pay for gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms will help mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $254.1 million and $214.7 million for the nine months ended July 31, 2008 and 2007, respectively. Net cash provided by operating activities reflects a $10.5 million increase in net income for 2008, compared with 2007. The effect of changes in working capital on net cash provided by operating activities are described below:

• Trade accounts receivable and unbilled utility revenues increased $9.6 million in the current period primarily due to amounts billed to customers reflected higher gas costs in 2008 as compared with 2007 and weather in the current period being 3% colder than the same prior period. Volumes sold to residential and commercial customers increased .1 million dekatherms as compared with the same prior period primarily due to the colder weather and customer growth. Total throughput increased 3.1 million dekatherms as compared with the same prior period.

• Net amounts due from customers decreased $9.5 million in the current period primarily due to the recovery of deferred gas costs.

• Gas in storage increased $38.7 million in the current period primarily due to a higher average cost of gas in storage as well as prepaid inventories becoming available for use.

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• Prepaid gas costs decreased $12.3 million in the current period primarily due to the gas becoming available for sale as noted above. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the winter heating season.

• Trade accounts payable increased $55.5 million in the current period primarily due to gas purchases to meet customer demand during the winter months.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder-than-normal or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated charges to customers of $6.8 million and $5.8 million in the nine months ended July 31, 2008 and 2007, respectively. In Tennessee, adjustments are made directly to the customers’ 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 margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The CUT mechanism provided margin of $27.3 million and $23.9 million in the nine months ended July 31, 2008 and 2007, 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 state regulatory 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, including price, availability, general economic conditions, weather, energy conservation and efficiency programs and competing 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 $149.3 million and $92.4 million for the nine months ended July 31, 2008 and 2007, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the nine months ended July 31, 2008, were $141 million as compared to $92.7 million in the same prior period. The increase was primarily due to system infrastructure investments.

During the nine months ended July 31, 2008, restrictions on cash totaling $2.2 million were removed with NCUC approval in October 2007 to liquidate all certificates of deposit and similar investments that held any supplier refunds due to customers and transfer these funds upon maturity to the North Carolina all customers deferred account.

During the nine months ended July 31, 2008, we contributed $10.8 million to Hardy Storage, a joint venture investee of one of our non-utility subsidiaries, as part of our equity contribution for construction of a FERC regulated interstate storage facility.

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 $168.5 million, primarily to serve customer growth, are budgeted for fiscal year 2008; however, we are not contractually obligated to expend capital until work is completed. Even though we are seeing a slower pace of customer growth in our service territory due to the downturn in the housing market, 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.

As part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand growth, we intend to design, construct, own and operate a LNG peak storage facility as a regulated utility project in Robeson County, North Carolina with the capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand. The LNG facility is planned to be in service for the 2012-2013 winter heating season. Preliminary estimates place the cost of the facility in the $300 to $350 million range, with approximately $6 million to be incurred in fiscal year 2008.

Cash Flows from Financing Activities. Net cash used in financing activities was $107.5 million and $120 million for the nine months ended July 31, 2008 and 2007, 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. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term borrowings, to repurchase common stock under the common stock repurchase program, and to pay quarterly dividends on our common stock. As of July 31, 2008, our current assets were $434.8 million and our current liabilities were $435.5 million, primarily due to seasonal requirements as discussed above.

As of July 31, 2008, we had committed lines of credit under our senior credit facility of $450 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 $450 million. Outstanding short-term borrowings decreased from $195.5 million as of October 31, 2007 to $169.5 million as of July 31, 2008, primarily due to the collections of amounts that have been billed to customers during the winter months, partially offset by the purchase of shares under the accelerated share repurchase (ASR) program, payments for interest on long-term debt and property taxes and payments to suppliers for the winter heating season. During the nine months ended July 31, 2008, short-term borrowings ranged from $9 million to $353 million, and

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interest rates ranged from 2.63% to 5.51% (weighted average of 3.97%).

As of July 31, 2008, under our credit facility, we had available letters of credit of $5 million of which $1.9 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. As of July 31, 2008, unused lines of credit available under our senior credit facility, including the issuance of the letters of credit, totaled $278.6 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. With higher wholesale gas prices, we may incur more short-term debt to pay for natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

We anticipate issuing up to $125 million in long-term debt in our 2009 fiscal year for general operating purposes. The timing of this issuance has not yet been determined.

During the nine months ended July 31, 2008, we issued $11.6 million of common stock through dividend reinvestment and stock purchase plans. On November 2, 2007, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $24.8 million. On January 15, 2008, we settled the transaction and paid an additional $1.3 million. Under the Common Stock Open Market Purchase Program, as described in Part II, Item 2 of this Form 10-Q, we paid $36.2 million during the nine months ended July 31, 2008 for 1.4 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. Through the ASR, we have repurchased 3,850,000 shares as follows: one million shares repurchased in April 2006, one million shares repurchased in November 2006, 850,000 shares repurchased in March 2007 and one million shares repurchased on November 2, 2007. 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 July 31, 2008, our retained earnings were not restricted. On September 4, 2008, the Board of Directors declared a quarterly dividend on common stock of $.26 per share, payable October 15, 2008 to shareholders of record at the close of business on September 25, 2008.

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. As of July 31, 2008, our capitalization consisted of 47% in long-term debt and 53% in common equity.

The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of July 31, 2008 and 2007, and October 31, 2007, are summarized in the table below.

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	July 31					October 31					July 31
In thousands	2008		Percentage			2007		Percentage			2007		Percentage
Short-term debt	$	169,500		9	%	$	195,500		10	%	$	147,500		8	%
Long-term debt		824,533		43	%		824,887		44	%		825,000		44	%
Total debt		994,033		52	%		1,020,387		54	%		972,500		52	%
Common stockholders’ equity		921,829		48	%		878,374		46	%		900,437		48	%
Total capitalization	$	1,915,862		100	%	$	1,898,761		100	%	$	1,872,937		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, corporate governance 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 July 31, 2008, 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.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of July 31, 2008, we are in compliance with all default provisions.

Estimated Future Contractual Obligations

During the three months ended July 31, 2008, there were no material changes, including those under FIN 48, to our estimated future contractual obligations that were disclosed in our Form 10-K for the year ended October 31, 2007, 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, 2007.

Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million and $1.3 million as of July 31, 2008 and October 31, 2007, respectively. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 6 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

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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, 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, 2007, 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, 2007.

Recent Accounting Pronouncements

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. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date.

• Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, through corroboration with observable data.

• Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

Under Statement 157, we anticipate fair value measurements would be disclosed by level for gas purchase options.

In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. 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 for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis. Accordingly, we will adopt Statement 157 for our fiscal year beginning November 1, 2008 with the exception of the application of the provision related to nonfinancial assets and liabilities. We believe the adoption of Statement 157 will not have a material

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impact on our financial position, results of operations or cash flows.

In April 2007, the FASB issued FSP FIN 39-1 to amend paragraph 3 of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). The FSP amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. Accordingly, we are evaluating the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 for our fiscal year beginning November 1, 2008.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (Statement 141(R)). Statement 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date at fair value. Statement 141(R) changes the accounting for business combinations in various areas, including contingency consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, changes in the acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. We will apply the provisions of Statement 141(R) to any acquisitions we may complete after November 1, 2009.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” (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 for our fiscal year beginning November 1, 2008. We have evaluated Statement 159, and we do not intend to elect the option to measure any applicable financial assets or liabilities at fair value pursuant to the provisions of Statement 159.

In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends Statement 133, by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities, but does not change the scope or accounting under Statement 133 and its related interpretations. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Statement 161 also amended SFAS 107, “Disclosures about Fair Value of Financial Instruments” (Statement 107), to clarify that derivative instruments are subject to Statement 107’s concentration-of-credit-risk disclosures. Statement 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. Since Statement 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is not expected to have a material impact on our financial position, results of operations,

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or cash flows. We will adopt Statement 161 on February 1, 2009.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 was issued to include the GAAP hierarchy in the accounting literature established by the FASB. Statement 162 will be effective sixty days following the SEC approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect this statement to have any impact on our financial position, results of operations or cash flows. We will adopt Statement 162 when it becomes effective.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including credit risk related to the creditworthiness of our suppliers as well as from our customers, commodity supply and price risk, interest rate risk and weather risk. We seek to identify, assess, monitor and manage market risk, credit risk and interest rate risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures. In recognition of changes in the energy business, our risk management policies and procedures are subject to ongoing review.

We hold all financial instruments discussed in this item for purposes other than trading.

Credit Risk

We enter into contracts with third parties to buy and sell natural gas for the purpose of maximizing the value of our long-term capacity and storage assets. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. The policy specifies limits on the contract amount and duration based on the counterparty’s credit rating. The policy is also designed to mitigate credit risks through a requirement for credit enhancements that include letters of credit or parent guaranties. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We have limited exposure to the risk of non-payment of utility bills by certain customers. In North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year that exceed the gas cost portion included in base rates is recovered through PGA procedures. To manage this customer credit risk, we evaluate credit quality and payment history and may require cash deposits from those customers that do not satisfy our predetermined credit standards. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term borrowings. As of July 31, 2008, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

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

As of July 31, 2008, we had $169.5 million of short-term debt outstanding under our credit facility at a weighted average interest rate of 2.71%. 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 $.2 million during the three months ended July 31, 2008 and $1.6 million during the nine months ended July 31, 2008.

Commodity Price Risk

We face commodity price risk associated with the purchase of natural gas. Due to cost-based rate regulation in our utility operations, our prudently incurred purchased gas costs and the prudently incurred costs of hedging the price of our gas supplies are passed on to customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize the New York Mercantile Exchange (NYMEX) exchange-traded instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval.

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues collected are driven by volumes sold. The current rates associated with these volumes are based on an assumption of normal weather. In these states, this risk is mitigated by WNA mechanisms that offset the impact of colder-than-normal or warmer-than-normal weather. In North Carolina, we manage our weather risk through a margin decoupling mechanism that allows us to recover our approved margin independent of volumes sold.

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.

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 and that such information is accumulated and communicated to our management, including our Chief Executive

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Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

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 third quarter of fiscal 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

We have only routine litigation in the normal course of business.

Item 1A. Risk Factors

During the nine months ended July 31, 2008, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2007.

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 July 31, 2008.

					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								3,498,074
05/01/08 - 05/31/08		56,000	$	26.58		56,000		3,442,074
06/01/08 - 06/30/08		90,000	$	26.73		90,000		3,352,074
07/01/08 - 07/31/08		122,000	$	25.94		122,000		3,230,074
Total		268,000	$	26.34		268,000

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.

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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 July 31, 2008, 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	September 8, 2008	/s/ David J. Dzuricky
		David J. Dzuricky Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Date	September 8, 2008	/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 July 31, 2008

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