UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended January 31, 2009

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

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

Class		Outstanding at March 2, 2009
Common Stock, no par value		73,484,181

 

 

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

January 31, 2009

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1. Financial Statements			1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3. Quantitative and Qualitative Disclosures about Market Risk			37
Item 4. Controls and Procedures			39
Part II. Other Information
Item 1. Legal Proceedings			40
Item 1A. Risk Factors			40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 6. Exhibits			42
Signatures			43
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Part I. Financial Information

Item 1. Financial Statements

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

		January 31,				October 31,
		2009				2008
ASSETS
Utility Plant, at original cost		$	3,080,932			$	3,054,656
Less accumulated depreciation			830,962				813,822
Utility plant, net			2,249,970				2,240,834
Other Physical Property, at cost (net of accumulated depreciation of $2,388 in 2009 and $2,351 in 2008)			828				864
Current Assets:
Cash and cash equivalents			22,887				6,991
Restricted cash			1				—
Trade accounts receivable (less allowance for doubtful accounts of $2,894 in 2009 and $1,066 in 2008)			236,487				82,346
Income taxes receivable			—				731
Other receivables			358				393
Unbilled utility revenues			149,589				51,819
Gas in storage			192,284				190,275
Gas purchase options, at fair value			9,002				22,645
Amounts due from customers			206,128				181,745
Prepayments			4,607				79,831
Other			7,169				6,620
Total current assets			828,512				623,396
Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities			102,236				99,214
Goodwill			48,852				48,852
Marketable securities, at fair value			358				—
Overfunded postretirement asset			6,697				6,797
Regulatory asset for postretirement benefits			29,115				28,732
Gas purchase options, at fair value			9,298				32,434
Unamortized debt expense			9,750				9,915
Regulatory cost of removal asset			6,584				6,398
Other			38,928				40,965
Total investments, deferred charges and other assets			251,818				273,307
Total		$	3,331,128			$	3,138,401

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. Accounting Matters

     Unaudited Interim Financial Information

The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) are omitted in this interim report under these SEC rules and regulations. These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2008.

     Seasonality and Use of Estimates

In our opinion, the unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at January 31, 2009 and October 31, 2008, the results of operations for the three months ended January 31, 2009 and 2008, and cash flows for the three months ended January 31, 2009 and 2008. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2009 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 the consolidated financial statements in our Form 10-K for the year ended October 31, 2008. There were no significant changes to those accounting policies during the three months ended January 31, 2009 other than disclosed in Note 12 to the condensed consolidated financial statements in this Form 10-Q.

     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 and regulatory liabilities in the condensed consolidated balance sheets as of January 31, 2009 and October 31, 2008 are as follows.

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. For information on related party transactions, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

     Accounting Pronouncements

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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 became effective November 15, 2008. We adopted Statement 162 on the effective date, and it had no impact on our financial position, results of operations or cash flows.

In December 2008, FASB issued a staff position, FSP FAS 132(R)-1, that amended SFAS No. 132(R), “Employers’ Disclosures about Pension and Other Postretirement Benefits,” that requires additional disclosures about plan assets of defined benefit pension and other postretirement plans. This staff position requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by SFAS No. 157, “Fair Value Measurements.” FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since this staff position only requires additional disclosures about plan assets of defined benefit pension and other postretirement plans, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt FSP FAS 132(R)-1 during our fiscal year ending October 31, 2010.

2. Regulatory Matters

In August 2008, we filed testimony with the North Carolina Utilities Commission (NCUC) in support of our gas cost purchasing and accounting practices for the period ended May 31, 2008. A hearing was held in December 2008. On February 20, 2009, the NCUC issued an order approving our accounting of gas costs for the twelve months ended May 31, 2008 and found our gas purchasing polices and practices prudent during the review period.

In December 2008, we filed an annual report for the twelve months ended December 31, 2007 with the Tennessee Regulatory Authority (TRA) that reflects the transactions in the deferred gas cost account for the Actual Cost Adjustment mechanism. We are unable to determine the outcome of the proceeding at this time.

3. Earnings per Share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months ended January 31, 2009 and 2008 is presented below.

4. Employee Benefit Plans

Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our 401(k) plans. These amendments applied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments apply to all employees, including those covered by the Nashville, Tennessee bargaining unit contract. The details of the changes to these plans are described in Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2008.

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the three months ended January 31, 2009 and 2008 are presented below.

We contributed $87,000 to the money purchase pension plan in February 2009. We anticipate that we will contribute the following amounts to our plans in 2009.

We have maintained two 401(k) plans that are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). Effective November 30, 2008, we merged the two plans into one plan.

We previously had a supplemental executive retirement plan (SERP) covering all officers at the vice president level and above. It provided supplemental retirement income as well as a life insurance benefit for officers to indirectly address the tax code limitations on qualified retirement plans. The level of insurance benefit and target retirement income benefits intended to be provided under the SERP depended upon the position of the officer. The SERP was funded by life insurance policies covering each officer, and the policy was owned exclusively by each officer.

On September 4, 2008, our Compensation Committee of the Board of Directors terminated the former SERP effective October 31, 2008 and replaced the supplemental retirement benefit with a non-qualified defined contribution restoration plan (DCR plan), effective January 1, 2009. The new plan is funded through a rabbi trust with a bank as the trustee. We will contribute 13% of total cash compensation (base salary, short-term incentive and MVP incentive) for each executive above the Internal Revenue Service compensation limit ($245,000 for 2009) to the DCR plan. An additional one-time contribution was made for all eligible officers in January 2009 equal to the greater of:

•

13% of base salary paid in November 2008 and December 2008 (to the extent that calendar year-to-date base salary exceeded the 2008 annual limit), or

•

Two monthly premiums (without adjustment for taxes) under the former SERP.

In addition, an opening balance that totaled $.3 million was established for four Vice Presidents to compensate them for the loss of benefits under the new plan. Participant contributions are not allowed. Vesting under the DCR plan is five-year cliff vesting, including service prior to adoption, of annual company contributions, and prospective five-year cliff vesting for the opening balances of the four Vice Presidents. If the officer severs employment before the expiration of the relevant five-year period, he or she receives nothing from that portion of the DCR plan. Participant-directed investment options are available to the officers. Distribution will occur upon separation of service or death. The insurance portion of the SERP benefit has been maintained in the form of new term life insurance.

Also on September 4, 2008, our Compensation Committee of the Board of Directors approved a voluntary deferred compensation plan, effective January 1, 2009, for the benefit of all officers, director-level employees and regional executives. This plan, known as the Voluntary Deferral Plan, is funded through a rabbi trust with a bank as the trustee.

There are no company contributions to the Voluntary Deferral Plan. Participants may contribute up to 50% of base salary with elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual incentive pay with elections made by April 30. Vesting is immediate through a rabbi trust with participant-directed investment options. Distributions can be made from the Voluntary Deferral Plan on a specified date that is at least two years from the date of deferral, on separation of service or upon death.

5. Business Segments

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

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

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on 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 in our Form 10-K for the year ended October 31, 2008.

Operations by segment for the three months ended January 31, 2009 and 2008 are presented below.

Reconciliations to the condensed consolidated statements of income for the three months ended January 31, 2009 and 2008 are presented below.

6. Equity Method Investments

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

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. For each period of the three months ended January 31, 2009 and 2008, these transportation costs and the amounts we owed Cardinal as of January 31, 2009 and October 31, 2008 are as follows.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For each period of the three months ended January 31, 2009 and 2008, these gas storage costs and the amounts we owed Pine Needle as of January 31, 2009 and October 31, 2008 are as follows.

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.

The SouthStar Restated Agreement includes a provision granting GNGC the option to purchase our ownership interest in SouthStar. Under the provision, GNGC has the option to purchase our entire 30% interest effective on January 1, 2010 provided they give us notice of their intent to exercise the option by November 1, 2009. If GNGC exercises its option, the purchase price would be based on the market value of SouthStar as defined in the Restated Agreement.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For each period of the three months ended January 31, 2009 and 2008, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2009 and October 31, 2008 are as follows.

Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia that is regulated by the FERC. Initial service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals, and final service levels are planned to commence on April 1, 2009.

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.

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

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

For the three months ended January 31, 2009, we have made no equity contributions to fund construction expenditures. Upon completion of project construction, including any contingency wells if needed, the members intend to target a capitalization structure of 70% debt and 30% equity. After the satisfaction of certain conditions in the note purchase agreement, amounts outstanding under the interim notes will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur in May 2010. To the extent that more funding is needed, the members will evaluate funding options at that time.

We record a liability at fair value for this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changes, the fair value of the guaranty is adjusted accordingly through a quarterly evaluation. The details of the guaranty at January 31, 2009 and October 31, 2008 are as follows.

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For each period of the three months ended January 31, 2009 and 2008, our gas storage costs and the amounts we owed Hardy Storage as of January 31, 2009 and October 31, 2008 are as follows.

7. Financial Instruments and Risk Management

     Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. Based on the value of our positions in these brokerage accounts and the associated margin requirements, we may be required to deposit cash into these brokerage accounts.

In April 2007, the FASB issued a staff position, FSP FIN 39-1, to amend paragraph 3 of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in Statement 133. The FSP amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Accordingly, we have evaluated the impacts of the right to offset fair value amounts pursuant to amended paragraph 10 of FIN 39 for our fiscal year beginning November 1, 2008. Prior to the adoption of FSP FIN 39-1, our policy was to present our positions, exclusive of

any receivable or payable, with the same counterparty on a net basis. On November 1, 2008, we elected “not to net” fair value amounts for our derivative instruments or the fair value of the right to reclaim cash collateral under FSP FIN 39-1 and moved to a gross presentation.

We include amounts recognized for the right to reclaim cash collateral in our current assets and current liabilities. We had the right to reclaim cash collateral of $64.1 million and $67.3 million as of January 31, 2009 and October 31, 2008, respectively.

     Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (Statement 157). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels.

In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.

We adopted Statement 157 on November 1, 2008 for our financial assets and liabilities, which consist primarily of derivatives that we record on the consolidated balance sheets in accordance with Statement 133. The adoption of Statement 157 had no impact on our financial position, results of operations or cash flows. There was no cumulative effect adjustment to retained earnings as a result of the adoption. We will adopt Statement 157 for our nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis on November 1, 2009 and are currently evaluating the impact on our financial position, results of operations and cash flows.

The carrying amounts of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate fair value. In developing the fair value of our long-term debt, we use a discounted cash flow technique that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amounts and fair value of our long-term debt, including the current portion, are shown below.

We utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and

endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs into the following fair value hierarchy levels as set forth in Statement 157.

Level 1

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives and investments in marketable securities.

Level 2

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly corroborated or observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. We obtain market price data from multiple sources in order to value our Level 2 transactions, and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include non-exchange-traded derivative instruments such as over-the-counter (OTC) options and long-term debt.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customer’s needs. We do not have any material financial assets or liabilities classified as Level 3.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2009. As required by Statement 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration with the fair value hierarchy levels.

The determination of the fair values incorporates various factors required under Statement 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), and the impact of our nonperformance risk on our liabilities.

Our utility segment derivative instruments are utilized in accordance with programs approved or filed with the NCUC, the Public Service Commission of South Carolina (PSCSC) and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net costs and the gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our purchased gas adjustment (PGA) procedures. In accordance with Statement 71, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” or “Amounts due from customers” in our condensed consolidated balance sheets. These derivative instruments include exchange-traded and OTC derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. OTC derivative contracts are valued using broker or dealer quotation services or market transactions in either the listed or OTC markets and are classified within Level 2.

Through January 31, 2009, we purchased and sold financial options for natural gas for our Tennessee gas supply portfolio. As of January 31, 2009, we had forward positions for March 2009 through November 2010. The costs of these options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our Tennessee Incentive Plan (TIP) approved by the TRA.

Through January 31, 2009, we purchased and sold financial options for natural gas for our South Carolina gas supply portfolio. As of January 31, 2009, we had forward positions for March 2009 through November 2010. The costs of these options are pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC.

Through January 31, 2009, we purchased and sold financial options for natural gas for our North Carolina gas supply portfolio. As of January 31, 2009, we had forward positions for March 2009 through November 2010. Costs associated with our North Carolina hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC.

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide increased price stability for our customers. Accordingly, there is no earnings impact of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives.

Trading securities include assets in a trust established for our deferred compensation plans and are included in “Marketable securities, at fair value” in the condensed consolidated balance sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

     Risk Management

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy. In addition, we have an Energy Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

8. Debt Instruments

During the three months ended January 31, 2009, we paid $.4 million to noteholders of the 6.25% insured quarterly notes. These notes have a redemption right upon the death of the owner of the notes, within specified limitations.

We have a syndicated five-year revolving credit facility with aggregate commitments totaling $450 million to meet working capital needs. This facility may be increased up to $600 million and includes annual renewal options and letters of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million, of which $2.4 million and $1.9 million were issued and outstanding at January 31, 2009 and October 31, 2008, respectively. These letters of credit are used to guarantee claims from self-insurance under our general liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from .15% to .35%, based on our credit ratings.

On October 27 and 29, 2008, we entered into two short-term credit facilities with banks for unsecured commitments totaling $75 million expiring on December 1, 2008. On December 1, 2008, these commitments were extended to December 3, 2008. Advances under each short-term facility bore interest at a rate based on the 30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings. We entered into these short-term facilities to provide lines of credit above the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements, including support for our gas supply procurement program as well as general corporate needs.

Effective December 3, 2008, we entered into a syndicated seasonal credit facility with aggregate commitments totaling $150 million. Advances under this seasonal facility bear interest at a rate based on the 30-day LIBOR rate plus from .75% to 1.75%, based on our credit ratings. Any borrowings under this agreement are due by March 31, 2009. We entered into this facility to provide lines of credit in addition to the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements and general corporate needs. This seasonal credit facility replaced the two short-term credit facilities with banks for unsecured commitments totaling $75 million that expired on December 3, 2008 as discussed above.

As of January 31, 2009 and October 31, 2008, outstanding short-term borrowings under our syndicated credit facility as included in “Notes payable” in the condensed consolidated balance sheets were $445 million and $406.5 million, respectively. As of January 31, 2009, outstanding short-term borrowings under our seasonal credit facility as included in “Notes payable” in the condensed consolidated balance sheets were $3 million. During the three months ended January 31, 2009, short-term borrowings ranged from $362 million to $556.5 million, and interest rates ranged from .58% to 2.84% (weighted average of 1.26%). Our credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 57% at January 31, 2009.

9.

Restructuring and Other Termination Benefits

In 2007, we implemented organizational changes under our business process improvement program to streamline business processes, capture operational and organizational efficiencies and improve customer service. As a part of this effort, we began initiating changes in our customer payment and collection processes, including no longer accepting customer payments in our business offices and streamlining our district operations. We also further consolidated our call centers. Collections of delinquent accounts have been consolidated in our central business office.

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

A reconciliation of activity to the liability as of January 31, 2009 is as follows.

10. Employee Share-Based Plans

Under Board of Directors approved incentive compensation plans, eligible officers and other participants are awarded units depending upon the level of performance achieved by Piedmont during multi-year performance periods. Distribution of those awards may be made in the form of shares of common stock and cash withheld for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed.

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2009 and 2008, and the amounts recorded as liabilities as of January 31, 2009 and October 31, 2008 are presented below.

		Three Months
In thousands		2009				2008
Compensation expense		$	(154	)		$	1,327

The accrual of compensation expense 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.

Also under our incentive compensation plan, 65,000 restricted shares of our common stock with a value at the date of grant of $1.7 million were granted to our President and Chief Executive Officer on September 1, 2006. During the vesting period, any dividends paid on these shares are accrued and converted into additional shares at the closing price on the date of the dividend payment. The restricted shares and any additional shares accrued through dividends will vest over a five-year period only if he is an employee on each vesting date. We recorded compensation expense under this grant of $84,100 for the three months ended January 31, 2009 and 2008. We are recording compensation on the straight-line method.

Shares of common stock to be issued under the incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

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 fifteen years. The time periods for gas supply contracts range from one to four years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas

storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the condensed consolidated statements of income as part of gas purchases and included in cost of gas.

Leases

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

Legal

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

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general liability policies. We had $2.4 million in letters of credit that were issued and outstanding at January 31, 2009. Additional information concerning letters of credit is included in Note 7 to the condensed consolidated financial statements in this Form 10-Q.

Environmental Matters

Our three 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.

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid $5.3 million, charged to the estimated environmental liability, that released us from any investigation and remediation liability. 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. 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.

There are three other MGP sites located in Hickory, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI Utilities, Inc.

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

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

During 2008, through the normal course of an on-going business review, one of our operating districts was found to have coatings on their pipelines containing asbestos. We have taken action to educate employees on the hazards of asbestos and to implement procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. We continue to determine the impacts and related costs to us, if any, and the impact to employees and contractors, if any.

Additional information concerning commitments and contingencies is set forth in Note 6 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2008.

Other

We have been in discussions with FERC’s Office of Enforcement (OE) regarding certain instances of possible non-compliance with FERC’s capacity release regulations regarding posting and bidding requirements for short-term releases. We have provided relevant information to FERC OE Staff and are cooperating with FERC in its investigation. We are continuing to meet with FERC’s OE staff to resolve this matter. We are unable to predict the outcome of the investigation at this time; however, we do not believe this matter will have a material effect on our results of operations.

12.

Adjustment of Statement of Cash Flows and Balance Sheet for the Adoption of FSP FIN 39-1

In April 2007, the FASB issued FSP FIN 39-1 to amend FIN 39, “Offsetting of Amounts Related to Certain Contracts.” Prior to the adoption of FSP FIN 39-1, our policy has been to present our positions, exclusive of any receivable or payable, with the same counterparty on a net basis. On November 1, 2008, we elected “not to net” fair value amounts for our derivative instruments or the fair value of the right to reclaim cash collateral under FSP FIN 39-1 and moved to a gross presentation.

The following table reflects the adjustments on our condensed consolidated balance sheet and condensed consolidated statement of cash flows as a result of the change from the net to the gross method.

			we expect this competitive environment to continue. We must be able to adapt to the changing environments and the competition.
	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.
	•		Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.
	•		The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.
	•		Access to capital markets. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets or our financial condition could affect access to and cost of capital.
	•		Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.
	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.
	•		Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.
	•		Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.
	•		Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities, and could affect our reported earnings or increase our liabilities.
	•		Changes in tax law and regulations. New tax law and regulations may be passed that could affect our reported earnings or increase our liabilities. Producers, marketers and pipelines are subject to changes in tax laws and regulations that increase our exposure to supply and price fluctuations.

•

Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

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.

Executive Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation 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.

In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.

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

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated segment include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. For the three months ended January 31, 2009, 93% 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. For further information on business segments, see Note 5 to the condensed

consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

Our utility operations are regulated by the NCUC, the PSCSC and the TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also 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 purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA.

We continually assess the nature of our business and explore alternatives in our core business of traditional regulated utility service. 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 from different supply regions to diversify our natural gas portfolio.

We are seeing the impacts of the economic recession in our market area with a decline in customer growth in our new construction market and continued customer conservation practices. We are also experiencing a decline in margin in our commercial and industrial markets from lower energy consumption related to company closings and reduced production and business activities. We continue to pursue customer growth opportunities, including residential customer conversions, in our service areas. A further weakening of the economy in our service areas could result in a greater decline in customer additions and energy consumption which could adversely affect our revenues or restrict our future growth.

We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on our current growth projections. Our current growth projections indicate that we may need to resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the project when needed to meet future customer requirements.

Our current customer growth projections for fiscal 2009 are gross customer additions in the range of 1-1.5% and an increase of .5-1% in the number of net customers billed. This compares to fiscal year 2008 gross and net customer increases of approximately 2%

Under current economic conditions, it may become more difficult for customers to pay their gas bills, leading to slower collections and higher-than-normal levels of accounts receivable and ultimately increasing the non-gas bad debt expense. With a slower turnover of accounts receivable, our level of borrowings could increase in order to meet our working capital needs.

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

We 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.

We will continue our efforts to promote natural gas and to inform consumers about the environmental benefits of using natural gas directly in their homes and business for the most efficient use of natural gas. This positions us, now and into the future, as the source of an environmentally responsible energy choice for our customers.

We remain focused on implementing and improving our underlying business processes while at the same time monitoring economic and other ongoing developments in order to ensure that our operations and business plan stay in step with these developments.

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 our core competencies. We analyze and evaluate potential projects 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 our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies. For further information, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

Results of Operations

We reported net income of $80.9 million for the three months ended January 31, 2009 as compared to $82.3 million for the same period in 2008. The following table sets forth a comparison of the components of our condensed consolidated statements of income for the three months ended January 31, 2009 as compared with the three months ended January 31, 2008.

Key statistics are shown in the table below for the three months ended January 31, 2009 and 2008.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

Operating Revenues

Operating revenues decreased $8.8 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$37.1 million from revenues in secondary market transactions due to decreased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.
	•		$21.1 million from decreased revenues under the margin decoupling mechanism. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer including those due to conservation and weather.
	•		$6.8 million from decreased revenues under the WNA in South Carolina and Tennessee.
	•		$1.4 million from a decrease in volumes delivered to transportation customers other than power generation.

These decreases were partially offset by the following increases:

	•		$33.6 million primarily from increased commodity and demand costs passed through to sales customers.
	•		$25.4 million of commodity gas costs from higher volume deliveries to sales customers.

Cost of Gas

Cost of gas decreased $2.5 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to the following decrease:

•

$38.2 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

This decrease was partially offset by the following increases:

	•		$25.4 million of commodity gas costs from higher volume deliveries to sales customers.
	•		$9 million from increased commodity and demand costs passed through to sales customers.

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

Margin

Margin decreased $6.3 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$5.8 million from net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews in the prior year.
	•		$2.5 million from commercial customers from conservation practices and the impact of the economic downturn.
	•		$2.4 million from decreased volumes delivered to industrial customers due to the impact of the economic downturn.

These decreases were partially offset by the following increases:

	•		$3.4 million from growth in our residential customer base.
	•		$1.2 million from the timing of asset management payments, partially offset by reduced margins from monthly capacity release and off-system sales transactions.
	•		$.8 million from conservation programs in the prior year.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity prices and resulting gas costs which are currently 58% of revenues and transportation and storage costs which are currently 4% of revenues.

Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2008. 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, margin decoupling mechanism in North Carolina and negotiated loss treatment and the collection of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Operations and Maintenance Expenses

Operations and maintenance expenses decreased $1.9 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to decreases in payroll due to lower short-term and long-term incentive plan accruals and fewer employees.

Depreciation

Depreciation expense increased $1.4 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to increases in plant in service.

General Taxes

General taxes were comparable for the three months ended January 31, 2009 as compared with the same period in 2008.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, non-operating income, charitable contributions, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of other miscellaneous expenses.

The primary changes to Other Income (Expense) were in income from equity method investments and non-operating income discussed below. All other changes were insignificant.

Income from equity method investments increased $1.1 million for the three months ended January 31, 2009 as compared with the same period in 2008 primarily due to the following:

	•		$1.6 million increase in earnings from SouthStar primarily due to higher retail margins and lower operating costs, partially offset by lower of cost or market inventory adjustments.
	•		$.5 million decrease in earnings from Hardy Storage primarily due to higher operations and maintenance expenses, property taxes and amortization of deferred interest on financing fees.

Non-operating income decreased $.5 million for the three months ended January 31, 2009 as compared with the same period in 2008 primarily due to a $.3 million write off of a community economic development loan.

Utility Interest Charges

Utility interest charges decreased $2.1 million for the three months ended January 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$1.7 million in interest on short-term debt primarily due to the average interest rate of the current period being 350 basis points lower than the prior year period even though borrowings were higher in the current period.
	•		$.8 million in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

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 access our short-term credit facilities to finance our working capital needs and growth. Although the credit markets tightened in the latter half of 2008, we believe that these sources, including amounts available to us under our existing and seasonal facilities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions and dividend payments.

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

During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary

significantly from period to period due to volatility in the price of natural gas, which is a function of market fluctuations in the price of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to/from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

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

Because of the economic recession, we may incur additional bad debt expense during the winter heating season, as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs, since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, will significantly mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $20.8 million and $.3 million for the three months ended January 31, 2009 and 2008, respectively. Net cash provided by operating activities reflects a $1.4 million decrease in net income for 2009 compared with 2008. The effect of changes in working capital on net cash provided by operating activities is described below:

	•		Trade accounts receivable and unbilled utility revenues increased $253.7 million in the current period primarily due to increased amounts billed to customers in 2009 as compared with 2008 due to higher volumes delivered. Volumes sold to residential and commercial customers increased 4.5 million dekatherms as compared with the same prior period primarily due to weather that was 11% colder. Total throughput increased 4 million dekatherms as compared with the same prior period.
	•		Net amounts due from customers increased $22 million primarily resulting from realized and unrealized market impacts on hedging activities, partially offset by decreases for gas cost differences deferred and the impact of the decrease in amounts recorded under the margin decoupling mechanism.
	•		Gas in storage increased $2 million in the current period primarily due to prepaid inventories becoming available for use which increased the levels of gas in storage. The volumes of gas in storage are at a higher average cost than the prior year.
	•		Prepaid gas costs decreased $77.4 million in the current period primarily due to gas becoming available for sale as noted above. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the winter heating season.
	•		Trade accounts payable increased $37.6 million in the current period primarily due to gas purchases to meet customer demand during the winter months.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- 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 credits to customers of $1.7 million and charges of $5.1 million in the three months ended January 31, 2009 and 2008, respectively. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in a deferred account for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism reduced margin by $6.9 million and increased margin by $14.2 million in the three months ended January 31, 2009 and 2008, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.

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

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide 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.

In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and operations and maintenance cost management programs to capture operational efficiencies while improving customer service.

Cash Flows from Investing Activities . Net cash used in investing activities was $30.4 million and $42.7 million for the three months ended January 31, 2009 and 2008, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the three months ended January 31, 2009 were $29.9 million as compared to $34.6 million in the same prior period primarily due to lower system infrastructure investments related to system strengthening and customer growth.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $176 million are forecasted for 2009, a reduction of $70 million, including $54 million for the deferral of the Robeson LNG storage project and $16 million for the deferral of pipeline infrastructure to serve new gas fired power generation markets in North Carolina. Our original 2009 budget was $246 million. We are not contractually obligated to expend capital until the work is completed.

Cash Flows from Financing Activities . Net cash provided by financing activities was $25.6 million and $52.6 million for the three months ended January 31, 2009 and 2008, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and employee stock plans, net of purchases under the common stock repurchase program. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of January 31, 2009, our current assets were $828.5 million and our current liabilities were $836.6 million primarily due to seasonal requirements as discussed above.

As of January 31, 2009, we had committed lines of credit under our syndicated credit facility of $450 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. We had a syndicated seasonal credit facility with aggregate commitments totaling $150 million. Outstanding short-term borrowings increased from $406.5 million as of October 31, 2008 to $448 million as of January 31, 2009 primarily due to our gas procurement programs. During the three months ended January 31, 2009, short-term borrowings ranged from $362 million to $556.5 million, and interest rates ranged from .58% to 2.84% (weighted average of 1.26%).

As of January 31, 2009, under our syndicated credit facility, we had available letters of credit of $5 million of which $2.4 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. As of January 31, 2009, unused lines of credit available under our syndicated credit facility and the seasonal credit facility, including the issuance of the letters of credit, totaled $149.6 million.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies and hedging transactions 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 fluctuate.

Due to the economic downturn and lower customer growth projections, we have delayed the Robeson County LNG project, as well as other capital expenditures as mentioned above. At this time, we do not anticipate issuing long-term debt in 2009. However, we will continue to monitor customer growth trends in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt.

During the three months ended January 31, 2009, we issued $3.6 million of common stock through dividend reinvestment and stock purchase plans. From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 of this Form 10-Q. We also have an accelerated share repurchase (ASR) program for purchasing shares of common stock that are in addition to shares that are repurchased on a normal basis through the open market program. Through the ASR program, we have repurchased 3,850,000 shares of the four million shares of common stock authorized under the ASR program and have 150,000 shares remaining. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional 4 million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated. The total number of shares available for repurchase under the combined plans is 7,010,074. In our second or third quarter of 2009, we intend to repurchase shares of common stock through the use of a broker under an ASR agreement. Such shares will be cancelled and become authorized but unissued shares available for issuance under our dividend reinvestment, employee stock purchase and incentive compensation plans.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of January 31, 2009, our retained earnings were not restricted. On March 6, 2009, the Board of Directors declared a quarterly dividend on common stock of $.27 per share, payable April 15, 2009 to shareholders of record at the close of business on March 25, 2009.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. As of January 31, 2009, our capitalization, including current maturities of long-term debt, consisted of 46% in long-term debt and 54% in common equity.

The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of January 31, 2009 and 2008, and October 31, 2008, 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, capital expenditures, operating cash flow coverage of interest and pension liabilities and funding status. Rating agencies also consider qualitative factors, such as the consistency of our earnings over time, the quality of management, corporate governance and business strategy, the risks associated with our utility and non-utility businesses and the regulatory commissions that establish rates in the states where we operate.

As of January 31, 2009, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of January 31, 2009, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended January 31, 2009, 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, 2008, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases and letters of credit that were discussed in Note 6 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2008 and the credit extended by our counterparty in OTC derivative contracts as discussed in Note 7 to the condensed consolidated financial statements in this Form 10-Q.

Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our condensed consolidated balance sheets. We have recorded an estimated liability of $1.2 million as of January 31, 2009 and October 31, 2008, respectively. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

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, 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, 2008, 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, 2008.

Recent Accounting Pronouncements

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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (Statement 162). Statement 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 became effective November 15, 2008. We adopted Statement 162 on the effective date, and it had no impact on our financial position, results of operations or cash flows.

In December 2008, FASB issued a staff position, FSP FAS 132(R)-1, that amended SFAS No. 132(R), “Employers’ Disclosures about Pension and Other Postretirement Benefits,” that requires additional disclosures about plan assets of defined benefit pension and other postretirement plans. This staff position requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by SFAS No. 157, “Fair Value Measurements.” FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since this staff position only requires additional disclosures about plan assets of defined benefit pension and other postretirement plans, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt FSP FAS 132(R)-1 during our fiscal year ending October 31, 2010.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage market risk and credit risk in accordance with defined policies and procedures

under an Enterprise Risk Management Policy and with the direction of the Risk Management Advisory Committee. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures.

We hold all financial instruments discussed below for purposes other than trading.

Credit Risk

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

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy any supply or demand contractual obligations that were incurred while under the management of this third party.

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

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of January 31, 2009, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

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

As of January 31, 2009, we had $448 million of short-term debt outstanding under our syndicated credit facility and seasonal credit facility at a weighted average interest rate of 1.26%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in

the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1.1 million during the three months ended January 31, 2009.

Commodity Price Risk

We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. As such, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.

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

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. Costs have never been disallowed in any jurisdiction.

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. In these states, this risk is mitigated by WNA mechanisms that are designed to offset the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets. In North Carolina, we manage our weather risk through a margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.

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

Item 4. Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-Q. Based on such evaluation, the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer concluded that, as of

the end of the period covered by this Form 10-Q, our disclosure controls and procedures were effective in that they provide reasonable assurances that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the first quarter of fiscal 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of January 31, 2009, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits

SIGNATURES

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

		Piedmont Natural Gas Company, Inc.   (Registrant)

Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended January 31, 2009

Exhibits

10.1		Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as of December 8, 2008, effective November 1, 2008
10.2		Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan, dated as of December 8, 2008, effective January 1, 2009
10.3		Credit Agreement dated as of December 3, 2008 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, and the Other Lenders Party Thereto
10.4		Amended and Restated Revolving Credit Facility dated December 1, 2008 between Piedmont Natural Gas Company, Inc. and Bank of America, N.A.
10.5		Amended and Restated Revolving Credit Facility dated December 1, 2008 between Piedmont Natural Gas Company, Inc. and Branch Banking and Trust Company
31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer