UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended July 31, 2007

or

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

For the transition period from                      to                     

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

 

(Exact name of registrant as specified in its charter)

4720 Piedmont Row Drive, Charlotte, North Carolina		28210
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

Class		Outstanding at September 4, 2007
Common Stock, no par value		74,068,474

 

 

TABLE OF CONTENTS

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,
		2007				2006
ASSETS
Utility Plant, at original cost		$	2,859,974			$	2,808,992
Less accumulated depreciation			743,062				733,682
Utility plant, net			2,116,912				2,075,310
Other Physical Property, at cost (net of accumulated depreciation of $2,157 in 2007 and $2,040 in 2006)			1,047				1,154
Current Assets:
Cash and cash equivalents			11,271				8,886
Restricted cash			743				—
Trade accounts receivable (less allowance for doubtful accounts of $1,820 in 2007 and $1,239 in 2006)			92,804				90,493
Income taxes receivable			12,667				30,849
Other receivables			174				160
Unbilled utility revenues			17,809				45,938
Gas in storage			143,788				138,183
Gas purchase options, at fair value			1,399				3,147
Amounts due from customers			82,368				89,635
Prepayments			60,126				62,356
Other			5,959				6,317
Total current assets			429,108				475,964
Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities			80,954				75,330
Goodwill			47,383				47,383
Unamortized debt expense			10,751				11,306
Regulatory cost of removal asset			13,040				12,086
Other			39,039				35,406
Total investments, deferred charges and other assets			191,167				181,511
Total		$	2,738,234			$	2,733,939

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

See notes to condensed consolidated financial statements.

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

1.

Unaudited Interim Financial Information.

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

     Seasonality and Use of Estimates.

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

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

     Significant Accounting Policies.

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

     Rate-Regulated Basis of Accounting.

We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. The amounts recorded as regulatory assets in the condensed consolidated balance sheets as of July 31, 2007 and October 31, 2006, were $139.8 million and $143.5 million, respectively. The amounts recorded as regulatory liabilities in the condensed consolidated balance sheets as of July 31, 2007 and October 31, 2006, were $354.4 million and $337 million, respectively.

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

     Recent Accounting Pronouncements.

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance

with SFAS 109, “Accounting for Income Taxes,” and in May 2007 issued Staff Position 48-1, “Definition of Settlement in FASB Interpretation No. 48,” (FSP 48-1). FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, 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. FIN 48 is effective the beginning of the first annual period beginning after December 15, 2006, and the guidance under FSP 48-1 should be applied upon the adoption of FIN 48. Accordingly, we will adopt FIN 48 and FSP 48-1 in our fiscal year 2008. We are currently assessing the impact FIN 48 may have on our consolidated financial statements; however, we believe the adoption of FIN 48 will not have a material impact on our financial position, results of operations or cash flows.

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

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

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

Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any amounts that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. In August 2007, we filed petitions with the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) requesting the ability to place certain defined benefit postretirement obligations related to the implementation of Statement 158 in a regulatory deferred account instead of accumulated other comprehensive income. Assuming regulatory treatment, if

Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7 million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could be substantially different depending on the discount rate, asset returns and plan population at that date.

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

2.

Regulatory Matters.

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

On May 31, 2007, we reached a settlement with the staff of the TRA and the Consumer Advocate Division of the Tennessee Attorney General’s Office, which, if approved by the TRA would modify our Tennessee Incentive Plan (TIP). The TIP settlement would clarify and simplify the calculation of allocated gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing ratio, maintain the current $1.6 million annual incentive cap on gains and losses under the TIP, improve the transparency of plan operations by specifying the request for proposal procedures for asset management transactions and provide for a triennial review of TIP operations by an independent consultant. The settlement was filed on June 4, 2007 with the TRA for approval.

On August 1, 2007, the NCUC approved our accounting for gas costs during the twelve months ended May 31, 2006, as adjusted by our agreement with the North Carolina Public Staff. We were deemed prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery.

In this same order, we are required to discontinue the accounting practice of capitalizing and amortizing storage demand charges, effective no later than November 1, 2007. This action will result in the accelerated recognition of $2.5 million of cost, net of tax, in the fourth quarter of 2007. In addition, we will not be capitalizing and amortizing demand charges during 2008.

There are also other accounting changes referenced in the same NCUC order including recording revenues and the cost of gas associated with secondary market sales as non-utility activities and recording supplier refunds of $1.7 million as restricted funds that will be invested in interest-bearing accounts for the benefit of customers.

On August 8, 2007, the NCUC scheduled a hearing for October 2, 2007 concerning our annual review of gas costs for the twelve months ended May 31, 2007.

In August 2007, we filed petitions with the NCUC, the PSCSC and the TRA requesting the ability to place certain defined benefit postretirement obligations related to the implementation of Statement 158 in a deferred account instead of accumulated other comprehensive income.

On June 15, 2007, we filed with the PSCSC a cost and revenue study as permitted by the Natural Gas Rate Stabilization Act requesting no change in margin. On August 31, 2007, 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 $2.5 million annual decrease in margin based on a return of equity of 11.2%, effective November 1, 2007. The settlement is pending approval by the PSCSC. We are unable to determine the outcome of this proceeding at this time.

3.

Accelerated Share Repurchase Program.

On March 30, 2007, we entered into an accelerated share repurchase (ASR) agreement where we purchased 850,000 shares of our common stock from an investment bank at the closing price that day of $26.38 per share. The settlement and retirement of those shares occurred on April 2, 2007. Total consideration paid to purchase the shares of $22.5 million, including $25,500 in commissions and structuring fees, was recorded in “Stockholders’ equity” as a reduction in “Common stock.”

As part of the accelerated share repurchase, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 50 trading days. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 850,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price was higher than the March 30, 2007 closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price for the shares purchased was lower than the March 30, 2007 closing price. At settlement on May 23, 2007, we paid cash of $.4 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction in “Common stock.” The $.4 million was the difference between the investment bank’s weighted average purchase price of $26.8459 and the March 30, 2007 closing price of $26.38 per share multiplied by 850,000 shares.

4.

Earnings Per Share.

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months and nine months ended July 31, 2007 and 2006 is presented below.

5.

Employee Benefit Plans.

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

Components of the net periodic benefit cost for our pension plans and our OPEB plan for the nine months ended July 31, 2007 and 2006 are presented below.

In July 2007, we contributed the amount we had estimated of $16.5 million to the qualified pension plan. Of the estimated 2007 contribution of $.6 million to the nonqualified pension plans, we have paid $.5 million through July 31, 2007. We estimate that we will contribute $3 million to the OPEB plan in 2007.

6.

Business Segments.

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

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

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, 2006.

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

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

7.

Equity Method Investments.

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

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the 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 gas costs for the three months and nine months ended July 31, 2007 and 2006 are presented below.

		Three Months								Nine Months
In thousands		2007				2006				2007				2006
Transportation Costs		$	1,181			$	1,181			$	3,465			$	3,504

As of July 31, 2007 and October 31, 2006, we owed Cardinal $.4 million and $.1 million, respectively.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns and operates an interstate liquefied natural gas storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. These gas costs for the three months and nine months ended July 31, 2007 and 2006 are presented below.

		Three Months								Nine Months
In thousands		2007				2006				2007				2006
Storage Costs		$	2,764			$	3,240			$	8,962			$	9,463

As of July 31, 2007 and October 31, 2006, we owed Pine Needle $.9 million and $1.1 million, respectively.

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement (Restated Agreement), earnings and losses are allocated 25% to us and 75% to the other member, Georgia Natural Gas Company (GNGC), a subsidiary of AGL Resources, Inc., with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States, with most of its business being conducted in the unregulated retail gas market in Georgia. We have related party transactions as a wholesale gas supplier 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, 2007 and 2006 are presented below.

		Three Months								Nine Months
In thousands		2007				2006				2007				2006
Operating Revenues		$	2,849			$	3,015			$	6,432			$	18,928

As of July 31, 2007 and October 31, 2006, SouthStar owed us $.8 million.

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

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

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

Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly-owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. The other owner is Columbia Hardy Corporation, a subsidiary of Columbia Gas Transmission Corporation (Columbia Gas), 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. Service to customers began April 1, 2007 in the initial service phase, and Hardy Storage continues to pursue construction related to subsequent phases of the project. 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. After the satisfaction of certain conditions in the note purchase agreement, the two members of Hardy Storage will pay off 30% of the construction financing with their equity contributions and the remaining 70% debt will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur in late spring to late summer of 2008. In April 2007, Columbia Gas contributed assets valued at $12.9 million as a portion of its share of the 30% equity contributions. On August 1, 2007, we contributed $2.8 million as a portion of our share of the 30% equity contributions. On September 4, 2007, we contributed an additional $8.8 million. By November 1, 2007, the members will have contributed their entire

equity commitment in cash and contributed assets, which will be used to pay off the equity bridge facility at that time.

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

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

We are recording a liability at fair value for this guaranty based on the probability of project failure applied to our 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, 2007, $135.7 million was outstanding under the construction loan, and we have recorded a guaranty liability of $1.4 million.

We have related party transactions as a customer of Hardy Storage beginning in April 2007, and we record in cost of gas the storage costs charged to us by Hardy Storage. These gas costs for the three months and nine months ended July 31, 2007 and 2006 are presented below.

		Three Months								Nine Months
In thousands		2007				2006				2007				2006
Storage Costs		$	2,520			$	—			$	3,318			$	—

As of July 31, 2007, we owed Hardy Storage $.9 million.

8.

Financial Instruments.

We have a syndicated five-year revolving credit facility with aggregate commitments totaling $350 million, that may be increased up to $600 million, and that includes annual renewal options. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $350 million. The facility provides a line of credit for letters of credit up to $5 million of which $1.5 million was issued and outstanding. The credit facility bears interest based on the 30-day LIBOR rate plus from .15% to .35%, based on our credit ratings. At July 31, 2007 and October 31, 2006, outstanding short-term borrowings of $147.5 million and $170 million were recorded in “Notes payable” in the condensed consolidated balance sheets, respectively. During the three months ended July 31, 2007, short-term borrowings ranged from zero to $157 million, and when borrowing under the facility, the actual interest rate for all borrowings and the weighted average interest rate was 5.57%. During the nine months ended July 31, 2007, short-term borrowings ranged from zero to $280.5 million, and when borrowing, interest rates ranged from 5.57% to 5.6% (weighted average of 5.58%). Our credit facility’s financial covenants require us to maintain a ratio of total debt outstanding, including letters of credit and guarantees of debt, to total capitalization of no greater than 70%, and our actual ratio was 52% at July 31, 2007.

We have purchased and sold financial derivative instruments for natural gas in all three states for our gas

purchase portfolios. The prudently incurred gains or losses on financial derivatives utilized in the regulated utility segment are included in our rates to customers. Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due customers in accordance with Statement 71. Accordingly, there is no earnings impact on the regulated utility segment from the use of these financial derivatives. The fair value of gas purchase options decreased from $3.1 million as of October 31, 2006 to $1.4 million as of July 31, 2007, primarily due to options being exercised or options expiring during the period and options being replaced with options having lower market values.

9.

Share-Based Payments.

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

Under our ICP, 65,000 restricted shares of our common stock with a value at the date of grant of $1.7 million were granted to our Chairman, 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 three-year period to five-year period only if he is an employee on each vesting date. For the three months and nine months ended July 31, 2007, we have recorded compensation expense under this grant of $.1 million and $.3 million, respectively. We are recording compensation under the ICP on the straight-line method.

Under the Executive Long-Term Incentive Plan (LTIP) and ICP, the Board of Directors has awarded performance units to eligible officers and other participants. Depending upon the 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 minimum threshold performances be achieved in order for any award to be distributed. For the three months and nine months ended July 31, 2007, we recorded compensation expense for the LTIP and ICP of $.1 million and $2.3 million, respectively, including compensation on the restricted share award above. 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, 2007 and October 31, 2006, we have accrued $7 million and $11.4 million for these 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.

10.

Termination Benefits.

We continued additional organizational changes under our business process improvement program during our third quarter. As a part of this effort, we are initiating changes in our customer payment and collection processes, including no longer accepting customer payments in our business offices and closing some of these office locations. We also continue to consolidate call centers and streamline our district operations. These new initiatives will be phased in through 2010 and may be accelerated and completed earlier.

We will be increasing the number and availability of public payment centers which are more conveniently located to meet our customers’ needs. Collections of delinquent accounts will be consolidated in our central business office.

We have accrued costs in connection with these initiatives in the form of one-time severance benefits to

employees who will be either voluntarily or involuntarily severed. 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 quarter ended July 31, 2007 and paid $.7 million in the period. The liability as of July 31, 2007 was $2.9 million.

11.

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 seventeen years. The time periods for gas supply contracts range from one to three years. The time periods for the telecommunications and technology contracts providing maintenance fees for hardware and software applications, usage fees, local and long-distance data costs, frame relay, cell phone and pager usage fees range from one to five 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 established by the FERC in order to maintain the ability 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 consolidated statement 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 litigation in the normal course of business.

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. We have owned, leased or operated thirteen manufactured gas plant (MGP) sites. We entered into a settlement with a third party with respect to nine 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, in anticipation of an impending sale. 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. We also have liability for any third-party claims for personal injury, death, property damage and diminution of property value or natural resources related to a MGP site connected with our acquisition of North Carolina Natural Gas Corporation.

Of the 13 MGP sites, we have accrued an estimated liability for the remaining four sites. As part of a

voluntary agreement with the North Carolina Department of Environment and Natural Resources (NCDENR), we started the initial steps for remediating the Hickory, North Carolina MGP site. In order to formalize the remediation process, the NCDENR sent us a letter requesting the initiation of a remedial investigation of this site. Because we no longer own the property, access to the property had to be obtained from the current owner, and the initial file search and survey have been completed. Due to the delays of obtaining access to the site, we have delayed the initial remediation investigation. Once completed, we will submit our findings to the NCDENR. The limited site assessment report prepared in 1994 concluded that gas plant residuals remaining on the Hickory site are thought to be mostly contained within two former tar separators associated with the site’s operations.

In addition, we have performed a more extensive investigation of our MGP site located in Nashville to determine if the accrued amounts are sufficient to cover the clean up of that site. Based on the results of this study, we believe that an adjustment is necessary to cover additional clean up of the site. This adjustment is necessary based on some contamination found outside the gasholder in the location of a boiler and pump house. The clean up of the additional contamination is expected to cost approximately $500,000. In accordance with the deferral accounting authorized by our regulatory commissions, we have adjusted the regulatory asset and the estimated liability for this additional amount.

Further evaluation or remediation of these MGP 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, cash flows or results of operations.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general liability policies.

Additional information concerning commitments and contingencies is set forth in Note 7 and “Financial Condition and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Form 10-K for the year ended October 31, 2006.

12. Subsequent Events.

In August 2007, we requested authorization from the NCUC and the PSCSC to defer certain settlement charges that we may be required to recognize under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (Statement 88) as a result of lump sum distributions from our pension plans in our current fiscal year. These charges may, but at this point are not certain to, accrue as a result of Statement 88’s requirement to recognize in earnings the pro rata portion of the percentage reduction in our long-term projected benefit obligations resulting from defined benefit distributions in excess of limits specified by Statement 88. These settlement charges will not change our ultimate liability under our pension plan, but current recognition of these charges, if required by Statement 88, will have an impact of $3.5 million pre-tax or more on our fourth quarter 2007 earnings. The liability for which deferral is sought in this petition and the amount of such liability are not fixed at this time and are dependent upon a number of variables, such as the total amount of lump sum settlement distributions made during Piedmont’s current fiscal year, and the prevailing discount rate and asset value of Piedmont’s postretirement obligations at October 31, 2007. We are unable to determine the outcome of this petition at this time.

such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.

	•		Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.
	•		Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.
	•		Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.
	•		Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and we assume such risks as an equity investor.

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Form 10-K for the year ended October 31, 2006.

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 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers. For the nine months ended July 31, 2007, 81% of our earnings before taxes came from our regulated utility segment.

The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and

intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.

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

The majority of our natural gas supplies come from the Gulf Coast region. We believe that diversification of our supply portfolio is in our customers’ best interest. We have a firm, long-term transportation contract pending with Midwestern Gas Transmission Company for additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies and the Chicago hub, primarily to serve our Tennessee markets. It is anticipated that the Midwestern capacity will be available during the 2007-2008 winter. We have also executed an agreement with Hardy Storage Company, LLC for firm, long-term market-area storage capacity in West Virginia that began its initial phase service in April 2007.

Our 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 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.

As part of our ongoing effort to improve business processes and customer service, and capture operational and organizational efficiencies, we are in the process of standardizing our customer payment and collection processes, consolidating call centers and streamlining business operations.

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.

Results of Operations

We reported a net loss of $9.1 million for the three months ended July 31, 2007 compared to a net loss of $12.4 million for the similar period in 2006. The following table sets forth a comparison of the components of our income statement for the three months ended July 31, 2007 as compared with the three months ended July 31, 2006.

We reported net income of $112.7 million for the nine months ended July 31, 2007 compared to net income of $103.4 million for the similar period in 2006. The following table sets forth a comparison of the components of our income statement for the nine months ended July 31, 2007 as compared with the nine months ended July 31, 2006.

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

Gas Deliveries, Customers, Weather Statistics and Number of Employees
		Three Months Ended												Percent
		July 31												Increase
Gas Sales and Deliveries in Dekatherms (in thousands)		2007				2006				Variance				(Decrease)
Sales Volumes			11,948				11,640				308				2.6	%
Transportation Volumes			24,320				26,329				(2,009	)			(7.6	)%
Throughput			36,268				37,969				(1,701	)			(4.5	)%
Secondary Market Volumes			8,034				10,367				(2,333	)			(22.5	)%
Customers Billed (at period end)			924,105				905,802				18,303				2.0	%
Gross Customer Additions			7,102				7,934				(832	)			(10.5	)%
Degree Days
Actual			46				76				(30	)			(39.5	)%
Normal			52				52				—				—	%
Percent colder (warmer) than normal			(11.5	)%			46.2	%			n/a				n/a
Number of Employees (at period end)			1,901				2,086				(185	)			(8.9	)%

Key operating statistics are shown in the table below for the nine months ended July 31, 2007 and 2006.

Gas Deliveries, Customers, Weather Statistics and Number of Employees
		Nine Months Ended												Percent
		July 31												Increase
Gas Sales and Deliveries in Dekatherms (in thousands)		2007				2006				Variance				(Decrease)
Sales Volumes			95,117				90,611				4,506				5.0	%
Transportation Volumes			67,760				65,864				1,896				2.9	%
Throughput			162,877				156,475				6,402				4.1	%
Secondary Market Volumes			26,623				30,120				(3,497	)			(11.6	)%
Customers Billed (at period end)			924,105				905,802				18,303				2.0	%
Gross Customer Additions			22,859				25,157				(2,298	)			(9.1	)%
Degree Days
Actual			2,869				2,929				(60	)			(2.0	)%
Normal			3,174				3,173				1				—	%
Percent colder (warmer) than normal			(9.6	)%			(7.7	)%			n/a				n/a
Number of Employees (at period end)			1,901				2,086				(185	)			(8.9	)%

Operating Revenues

Operating revenues decreased $13.4 million for the three months ended July 31, 2007 compared with the similar period in 2006 due to the following decreases:

	•		$12.1 million from lower revenues from secondary market transactions. Secondary market transactions consist of off-system sales and capacity release arrangements.
	•		$9.4 million from lower commodity gas costs passed through to sales customers.

These decreases were partially offset by the following increases:

	•		$4.1 million from increased volumes delivered to transportation customers.
	•		$3.7 million from increased volumes delivered to sales customers related to non-commodity components in rates.
	•		$2.4 million from increased volumes delivered to sales customers related to commodity costs.
	•		$.7 million higher revenues under the CUT mechanism. As discussed in “Financial Condition and Liquidity” below, the CUT mechanism became effective November 1, 2005 in North Carolina to

offset the impact of conservation and colder-than-normal or warmer-than-normal weather on residential and commercial customer margin.

Operating revenues decreased $209.2 million for the nine months ended July 31, 2007 compared with the similar period in 2006 due to the following decreases:

	•		$205.9 million from lower commodity gas costs passed through to sales customers.
	•		$58.6 million lower revenues from secondary market transactions.
	•		$5.8 million lower revenues under the CUT mechanism.

These decreases were partially offset by the following increases:

	•		$25.8 million from increased volumes to sales customers related to non-commodity components in rates.
	•		$15.9 million from increased volumes delivered to sales customers related to commodity costs.
	•		$11.4 million from increased volumes delivered to transportation customers.
	•		$5 million related to non-commodity components in rates.
	•		$1.3 million from revenues under the WNA in South Carolina and Tennessee.

Cost of Gas

Cost of gas decreased $15.6 million for the three months ended July 31, 2007 compared with the similar period in 2006 primarily due to the following decreases:

	•		$11.2 million from lower commodity gas costs in secondary market activity.
	•		$9.4 million from lower commodity gas costs passed through to sales customers.

These decreases were partially offset by an increase of $2.4 million from increased volumes delivered to sales customers.

Cost of gas decreased $216.2 million for the nine months ended July 31, 2007 compared with the similar period in 2006 primarily due to a decrease of $205.9 million from lower commodity gas costs passed through to sales customers.

Under purchased gas adjustments (PGA) procedures in all three states, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of natural 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 $2.2 million for the three months ended July 31, 2007 and $7 million for the nine months ended July 31, 2007 compared with the similar periods in 2006 primarily due to growth in our residential, commercial and power-generation customer base. The increase in the nine-month period was partially offset by $1.5 million of gas cost accounting adjustments related to lost and unaccounted for gas and interest charges related to natural gas purchases and $.8 million due to the timing of annual adjustments under the CUT settlement.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas

costs for upstream capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity gas costs, which account for approximately 69% of revenues for the nine months ended July 31, 2007. The wholesale commodity gas costs are passed through to customers in rates on a dollar-for-dollar basis.

Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this document or in our Form 10-K for the year ended October 31, 2006. These include WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization in South Carolina, secondary market activity in North Carolina and South Carolina, TIP in Tennessee, CUT in North Carolina, negotiated loss treatment in all three jurisdictions and the collection of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity related to North Carolina and South Carolina, with 75% credited to customers through the PGA mechanism.

Operations and Maintenance Expenses

Operations and maintenance expenses increased $.4 million for the three months ended July 31, 2007 compared with the similar period in 2006 primarily due to the following increases:

	•		$1.2 million in outside services primarily due to increased telephony services.
	•		$1.1 million in employee benefits primarily due to pension costs and adjustments in group insurance expense.

These increases were partially offset by the following decreases:

	•		$1.3 million in payroll primarily related to the management restructuring program in 2006, including impacts on short-term and long-term incentive plan accruals.
	•		$.7 million in the provision for uncollectibles primarily due to an adjustment to the allowance for doubtful accounts.

Operations and maintenance expenses decreased $5.4 million for the nine months ended July 31, 2007 compared with the similar period in 2006 primarily due to the following decreases:

	•		$8.3 million in payroll primarily related to the management restructuring program in 2006, including impacts on short-term and long-term incentive plan accruals.
	•		$1 million in transportation costs primarily due to fewer vehicles being used as a result of our automated meter reading initiative.

These decreases were offset by the following increases:

	•		$2.1 million in employee benefits primarily due to pension and postretirement health care costs and adjustments in group insurance expense.
	•		$1.8 million in outside services primarily due to increased telephony services.

Depreciation

Depreciation expense for the three months and nine months ended July 31, 2007 was comparable with the similar prior periods.

General Taxes

General taxes decreased $.8 million for the three months ended July 31, 2007 as compared with the similar period in 2006 primarily due to decreases in property taxes and payroll taxes, partially offset by an increase in gross receipts taxes. General taxes for the nine months ended July 31, 2007 were comparable with the similar prior period.

Other Income (Expense)

Income from equity method investments includes our earnings from joint venture investments. Income from equity method investments increased $3.8 million and $7 million for the three months and nine months ended July 31, 2007 compared with the similar periods in 2006. These increases were primarily due to increased earnings from SouthStar of $2 million and from Hardy Storage of $2 million, offset by decreased earnings from Pine Needle of $.2 million for the three months ended July 31, 2007, and increased earnings from SouthStar of $4.9 million and from Hardy Storage of $2.6 million, partially offset by decreased earnings from Pine Needle of $.4 million for the nine months ended July 31, 2007. Non-operating income is comprised of non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and other miscellaneous expenses. The changes in non-operating income and non-operating expense are not significant.

Utility Interest Charges

Utility interest charges increased $.9 million for the three months ended July 31, 2007 compared with the similar period in 2006 primarily due to the following increases:

	•		$.9 million in interest on long-term debt due to the issuance on June 20, 2006 of $200 million of insured quarterly notes due June 1, 2036, which was partially offset by the retirement on July 30, 2006 of $35 million of senior notes.
	•		$.4 million due to a decrease in the allowance for funds used during construction allocated to debt.
	•		$.3 million in interest expense on regulatory treatment of certain components of deferred income taxes.
	•		$.3 million in net interest expense on amounts due to/from customers due to lower net receivables in the current period.

These increases were partially offset by the following decreases:

•

$1.2 million in interest on short-term debt due to lower balances outstanding in the current period.

Utility interest charges increased $3.5 million for the nine months ended July 31, 2007 compared with the similar period in 2006 primarily due to the following increases:

	•		$5.5 million in interest on long-term debt due to the issuance on June 20, 2006 of $200 million of insured quarterly notes due June 1, 2036, which was partially offset by the retirement on July 30, 2006 of $35 million of senior notes.
	•		$1.1 million in interest expense on regulatory treatment of certain components of deferred income taxes.

These increases were partially offset by the following decreases:

	•		$2.7 million in interest on short-term debt due to lower balances outstanding in the current period.
	•		$.5 million due to an increase in the allowance for funds used during construction allocated to debt.
	•		$.2 million in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

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 1,016,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 62,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

We continually assess the nature of our business and explore alternatives in our core business of 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 through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have a firm, long-term transportation contract pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies and the Chicago hub, primarily to serve our Tennessee markets. We anticipate the Midwestern capacity will be available during the 2007-2008 winter. We have also executed an agreement with Hardy Storage Company, LLC for firm, long-term market-area storage capacity in West Virginia that began its initial service in April 2007.

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

Our utility operations are regulated by the NCUC, PSCSC and the 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 and safety of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

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

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. In North

Carolina, the CUT provides for the recovery of our approved margin per customer independent of both weather or other consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection. 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 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 WNA.

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 venture by having management representation on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding exiting joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

Financial Condition and Liquidity

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

Cash Flows from Operating Activities . The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations resulting from such factors as weather, natural gas purchases and prices, 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 peak heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, paying down short-term debt and decreases in receipts from customers.

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

Cash flows from operations are impacted by weather, which affects natural 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. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Net cash provided by operating activities was $214.7 million and $103.8 million for the nine months ended July 31, 2007 and 2006, respectively. Net cash provided by operating activities reflects a $9.3 million increase in net income for 2007 compared with 2006, along with changes in working capital as described below:

	•		Trade accounts receivable and unbilled utility revenues increased cash flow $25.2 million in the current period and $31.6 million in the prior period. Trade accounts receivable increased $2.9 million in the current period due to an increase in volumes delivered of 2.9 million dekatherms, which were offset by lower gas costs passed through to customers.
	•		Prepayments increased cash flow $2.2 million in the current period and $12.2 million in the prior period primarily due to prepaid gas costs. Prepaid gas costs increased primarily due to a large injection of gas in July 2007, which did not occur until August 2006 in the prior year.
	•		Trade accounts payable increased cash flow $5.2 million in the current period as compared with a decrease in cash flow of $113 million in the prior period. Trade accounts payable, including accounts payable for construction work in progress, increased by $3.5 million in the current period primarily due to an increase in gas purchases.
	•		Amounts due to/from customers increased cash flow $7.3 million in the current period as compared with a decrease in cash flow of $23 million in the prior period. Net amounts due to/from customers decreased $7.3 million in the current period due to the recovery of gas costs deferred in the prior period.
	•		Refundable income taxes decreased cash flow $18.2 million in the current period as compared to an increase in cash flow of $5.8 million in the prior period due to the application of refundable income taxes to later periods.
	•		Income taxes accrued increased cash flow $.4 million in the current period as compared with a decrease in cash flow of $6.2 million in the prior period due to changes in the components of taxable income.
	•		Gas in storage decreased cash flow $5.6 million in the current period as compared with an increase in cash flow of $31.7 million in the prior period primarily due to injection of gas into new gas storage contract services facilities.
	•		Gas purchase options, at fair value, increased cash flow $1.7 million in the current period as compared with an increase in cash flow of $7.9 million in the prior period due to decreases in the market values of financial derivatives.

Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have 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 $5.8 million in the nine months ended July 31, 2007 and charges to customers of $4.5 million in the nine months ended July 31, 2006. In Tennessee, adjustments are made directly to the customer’s bills. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or refund to all customers in the class. The CUT mechanism in North Carolina provides for any over- or under-collection of approved margin per customer that operates independently of both weather and consumption patterns of residential and commercial customers. The CUT mechanism provided margin of $23.9 million and $29.3 million in the nine months ended July 31, 2007 and 2006, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the CUT.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure

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

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

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

In an effort to keep customer rates competitive by holding down operations and maintenance costs and as part of an ongoing effort aimed at improving business processes, capturing operational and organizational efficiencies and improving customer service, we are in the process of standardizing our customer payment and collection processes, consolidating call centers and streamlining business operations. We estimate termination benefits to employees of labor costs of $3.6 million over the next four years in this business process improvement initiative.

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.

Cash Flows from Investing Activities . Net cash used in investing activities was $92.4 million and $115.6 million for the nine months ended July 31, 2007 and 2006, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the nine months ended July 31, 2007 were $92.7 million as compared to $147 million in the similar prior period. The decrease was primarily due to several large projects in 2006, such as automated meter reading, certain revenue-producing projects in our service area and enterprise telephony that are now complete or nearing completion. Reimbursements from the bond fund decreased $16 million from 2006 as construction of gas infrastructure in eastern North Carolina is complete.

During the nine months ended July 31, 2007, transfers of $.7 million were recorded as restricted funds and placed in escrow under the provisions of orders of the NCUC. During the nine months ended July 31, 2006, the restrictions on cash totaling $13.1 million were removed in connection with implementing the NCUC order in our last general rate proceeding. The cash was previously held in an expansion fund to extend natural gas service to unserved areas of the state.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. Gross utility construction expenditures totaling $144.8 million, primarily to serve customer growth, are

budgeted for fiscal year 2007; however, we are not contractually obligated to expend capital until work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

We anticipate contributing $26.3 million to Hardy Storage Company, LLC, a joint venture investee of one of our non-utility subsidiaries, by November 1, 2007. This is the date on which the interim notes and revolving equity bridge will be converted to a mortgage-style note.

Cash Flows from Financing Activities . Net cash provided by (used in) financing activities was $(120) million and $13.3 million for the nine months ended July 31, 2007 and 2006, respectively. Funds are primarily used in paying down outstanding short-term borrowings, the repurchase of common stock under the common stock repurchase program, net of the issuance of common stock through dividend reinvestment and employee stock plans, and the payment of quarterly dividends on our common stock. 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 sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. As of July 31, 2007, our current assets were $429.1 million and our current liabilities were $350 million, primarily due to seasonal requirements as discussed above.

As of July 31, 2007, we had committed lines of credit under our senior credit facility effective April 24, 2006 of $350 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000 plus six basis points for any unused amount up to $350 million. Outstanding short-term borrowings decreased from $170 million as of October 31, 2006 to $147.5 million as of July 31, 2007, primarily due to collections from customers and reductions in working capital needs. During the nine months ended July 31, 2007, short-term borrowings ranged from zero to $280.5 million, and when we borrowed under the facility, interest rates ranged from 5.57% to 5.6% (weighted average of 5.58%).

As of July 31, 2007, we had $5 million available for letters of credit under our credit facility of which $1.5 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, 2007, unused lines of credit available under our senior credit facility, including the issuance of the letters of credit, totaled $201 million.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high, we may incur more short-term debt to pay for natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

During the nine months ended July 31, 2007, we issued $11.8 million of common stock through dividend reinvestment and stock purchase plans. On November 7, 2006, through an ASR agreement, we repurchased and retired 1 million shares of common stock for $26.6 million. On January 19, 2007, we settled the transaction and paid an additional $.8 million. On April 2, 2007, through an ASR agreement, we repurchased and retired 850,000 shares of common stock for $22.5 million. On May 23, 2007, we settled the transaction and paid an additional $.4 million. Under the Common Stock Open Market Purchase Program, as described in Part II, Item 2, we paid $54.2 million during the nine months ended July 31, 2007 for 2 million shares of common stock that are available for reissuance under these plans.

Through the ASR program, we may repurchase and subsequently retire up to approximately four million

shares of common stock by no later than December 31, 2010, including the one million shares repurchased in April 2006, the one million shares repurchased in November 2006 and the 850,000 shares repurchased in March 2007. These shares are in addition to shares that are repurchased on a normal basis through the open market program. We anticipate that we will initiate another repurchase of up to one million shares in November 2007.

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, 2007, our retained earnings were not restricted. On September 7, 2007, the Board of Directors declared a quarterly dividend on common stock of $.25 per share, payable October 15, 2007 to shareholders of record at the close of business on September 24, 2007.

Our long-term targeted capitalization ratio is 45% to 50% in long-term debt and 50% to 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, 2007, our long-term capitalization consisted of 48% in long-term debt and 52% in common equity.

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

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flows relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. Rating agencies also consider qualitative factors, such as the consistency of our earnings over time, the quality of management and business strategy, the risks associated with our utility and non-utility businesses and the regulatory commissions that establish rates in the states where we operate.

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

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

Estimated Future Contractual Obligations

During the three months ended July 31, 2007, there were no material changes to our estimated future contractual obligations that were disclosed in our Form 10-K for the year ended October 31, 2006, in

“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” other than a commitment to fund our 50% share of 30% of the construction financing of the Hardy Storage project with equity contributions, of which our commitment was $12.9 million as of July 31, 2007. For further information on this commitment, see Note 7 to the condensed consolidated financial statements.

Off-Balance Sheet Arrangements

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

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

Critical Accounting Policies and Estimates

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

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

Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), to clarify the accounting for uncertain tax positions in accordance with SFAS 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. This interpretation is effective the beginning of the first annual period beginning after December 15, 2006. On May 2, 2007, the FASB issued Staff Position (FSP) No. FIN 48-1, “Definition of Settlement in FIN 48,” to clarify when a tax position is considered settled under FIN 48. The guidance in FSP No. FIN 48-1 should be applied upon adoption of FIN 48. Accordingly, we will adopt FIN 48 and FSP No. FIN 48-1 in our fiscal year 2008. We are currently assessing the impact

FIN 48 may have on our consolidated financial statements; however, we believe the adoption of FIN 48 will not have a material impact on our financial position, results of operations or cash flows.

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

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

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

Based on a preliminary assessment of prior regulatory treatment of postretirement benefits, management believes that regulatory asset or liability treatment will be afforded to any amounts that would otherwise be recorded in accumulated OCI resulting from the implementation of Statement 158. In August 2007, we filed a petition with the NCUC, the PSCSC and the TRA requesting the ability to place certain defined benefit postretirement obligations related to the implementation of Statement 158 in a regulatory deferred account instead of accumulated other comprehensive income. Assuming regulatory treatment, if Statement 158 had been adopted for the fiscal year ended October 31, 2006, the effect on the consolidated balance sheets would have been the recognition of $25.6 million as a regulatory asset, $16.7 million of deferred income taxes, $14.6 million decrease to prepaid pension and $27.7 million increase in accrued postretirement benefits. The actual impact at October 31, 2007 could be substantially different depending on the discount rate, asset returns and plan population at that date.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (Statement 159). Statement 159 provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Interest Rate Risk

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

As of July 31, 2007, we had $147.5 million of short-term debt outstanding under our credit facility at a weighted average interest rate of 5.57%. 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 $.1 million during the three months ended July 31, 2007 and $.8 million during the nine months ended July 31, 2007.

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

Commodity Price Risk

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

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

Item 4. Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and

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

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

reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares. The additional four million shares are referred to as our accelerated share repurchase program and have an expiration date of December 31, 2010.

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

Item 6. Exhibits