UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended January 31, 2005

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.

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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

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

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PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

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

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

3

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

See notes to condensed consolidated financial statements.

4

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

      See notes to condensed consolidated financial statements.

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

1. The condensed consolidated financial statements have not been audited. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2004 Annual Report.

2. 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, 2005 and October 31, 2004, and the results of operations and cash flows for the three and twelve months ended January 31, 2005 and 2004. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2005, 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.

3. We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery from or refund to utility customers in future periods. The amounts recorded as regulatory assets in the consolidated balance sheets as of January 31, 2005 and October 31, 2004, were $69.7 million and $65.1 million, respectively. The amounts recorded as regulatory liabilities in the consolidated balance sheets as of January 31, 2005 and October 31, 2004, were $295.6 million and $297.6 million, respectively.

4. All of our goodwill is attributable to the regulated utility segment. The balance in goodwill as of October 31, 2004 and January 31, 2005, and the changes for the three months ended January 31, 2005, are presented below.

5. Components of the net periodic benefit cost for our defined-benefit pension plans and other postretirement benefit plan for the three months and twelve months ended January 31, 2005 and 2004, are presented below.

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6. 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 and twelve months ended January 31, 2005 and 2004, is presented below.

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

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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 “Other Income (Expense)” section of 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 and the return on our investment in the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements for the year ended October 31, 2004.

Operations by segment for the three and twelve months ended January 31, 2005 and 2004, are presented below.

Reconciliations to the condensed consolidated statements of income for the three and twelve months ended January 31, 2005 and 2004, are presented below.

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8. 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 business is recorded in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the consolidated statements of income.

As of January 31, 2005, the amount of retained earnings that represented undistributed earnings of equity method investments was $28.5 million.

Cardinal Pipeline Company, L.L.C.

We own 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the North Carolina Utilities Commission (NCUC).

We have related party transactions with Cardinal as a transportation customer and we record in cost of gas the transportation costs charged by Cardinal. These gas costs for the three months and twelve months ended January 31, 2005 and 2004, are presented below.

We owed Cardinal $.4 million as of January 31, 2005 and 2004.

Summarized financial information provided to us by Cardinal for 100% of Cardinal as of and for the three months ended December 31, 2004 and 2003, is presented below.

Pine Needle LNG Company, L.L.C.

We own 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC).

We have related party transactions with Pine Needle as a customer and we record in cost of gas the storage

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costs charged by Pine Needle. These gas costs for the three months and twelve months ended January 31, 2005 and 2004, are presented below.

We owed Pine Needle $1 million as of January 31, 2005 and 2004.

Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of and for the three months ended December 31, 2004 and 2003, is presented below.

SouthStar Energy Services LLC

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. Under the terms of an amended and restated LLC operating agreement effective January 1, 2004, earnings and losses are allocated 25% to us and 75% to the other member. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia.

We have related party transactions with SouthStar which purchases wholesale gas supplies from us. Our operating revenues from these sales for the three months and twelve months ended December 31, 2004 and 2003, are presented below.

As of January 31, 2005, SouthStar owed us $.9 million.

Summarized financial information provided to us by SouthStar for 100% of SouthStar as of and for the three months ended December 31, 2004 and 2003, is provided below.

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9. We purchase natural gas for our regulated operations for resale under tariffs approved by the state regulatory commissions having jurisdiction over the service area where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas cost recovery mechanisms. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors risks in accordance with our risk management policies.

Through January 31, 2005, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of January 31, 2005, we had open forward positions for March 2005 through February 2006. The cost of these options and all other gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan approved by the Tennessee Regulatory Authority (TRA).

Through January 31, 2005, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of January 31, 2005, we had open forward positions for March through October 2005. The cost of these options is pre-approved for recovery from customers by the Public Service Commission of South Carolina (PSCSC), subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.

Through January 31, 2005, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of January 31, 2005, we had open forward positions for March through October 2005. Costs associated with our North Carolina hedging program are not pre-approved for recovery from customers by the NCUC but are treated as gas costs subject to the annual gas cost prudence review by the NCUC.

There is no income statement impact from the North Carolina and South Carolina hedging plans as all costs and related gain or loss amounts are passed through to customers under purchase gas adjustment (PGA) procedures and are recorded in amounts due from customers. We mark the derivative instruments to market with corresponding entries to these accounts. Receivables from customers for the costs of the hedging plans and the related mark-to-market adjustments were $5.8 million and $3.3 million as of January 31, 2005 and 2004, respectively.

10. In connection with the sale in January 2004 of our propane interests, we received 37,244 common units of Energy Transfer Partners, LP. The market value of these units as of January 31, 2005, was reported in “Marketable securities” in the condensed consolidated balance sheets. On February 1, we sold 18,622 of the units and on February 2, we sold the remaining 18,622 units for total proceeds of $2.4 million. We will record a net gain after tax of $.9 million in our second quarter ending April 30, 2005.

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

Overview

Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments.

The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates that

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are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, dependable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers.

The non-utility activities segment consists of our equity method investments in joint venture, energy–related businesses that are involved, as of January 31, 2005, in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance and rates of return of these ventures against expectations.

Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are earned during the winter season. During warm winters or unevenly cold winters, heating customers may not use their gas furnaces at all or may significantly reduce their consumption of natural gas. Although we have weather normalization adjustment mechanisms (WNA) that are designed to protect a portion of revenues against warmer-than-normal weather, deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of unusually cold weather by reducing the amounts we can charge our customers.

In the past few years, there have been significant increases in the price of natural gas. The relationship between supply and demand has the greatest impact upon price. Although we believe there are sufficient supplies of natural gas to meet our customers’ needs, price increases, if continued, could shift our customers’ preference away from natural gas and toward a competing energy source, particularly in the industrial market. Price increases could also affect the consumption levels of our customers or make it more difficult for them to pay their bills. We continue to advocate the need for an effective national energy policy. We expect that the wholesale price of natural gas will remain volatile until there is a national policy that will allow a balancing of natural gas supply and demand. Access to domestic supplies that are unavailable due to governmental restrictions could alleviate the supply/demand imbalance for natural gas in the United States and restore wholesale prices to more reasonable, competitive levels.

Although we have been operating in a relatively low interest rate environment in the past few years for both short- and long-term debt financing, a rise in interest rates without the recognition of the higher cost of debt in our rates charged to customers could negatively affect earnings. The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas that could subject us to short-term interest rate risks.

Results of Operations

We will discuss the results of operations for the three months and twelve months ended January 31, 2005, compared with similar periods in 2004. Operating results for the three months ended January 31, 2005 and 2004, and the twelve months ended January 31, 2005, reflect the full effect of the acquisitions of NCNG and an equity interest in EasternNC on September 30, 2003.

Operating Revenues

Operating revenues were $680.6 million and $618.8 million for the three months ended January 31, 2005 and 2004, respectively. Operating revenues in 2005 increased $61.8 million compared with the similar prior period primarily due to the following increases.

•

$50.7 million from increased commodity gas costs passed through to customers.

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	•	$11.5 million from the WNA due to surcharges of $14.1 million in 2005 compared with surcharges of $2.6 million in 2004. As discussed in “Financial Condition and Liquidity” below, we have a WNA in all three states that is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin.
	•	$9.4 million from secondary market transactions.

These increases were partially offset by a decrease of $13.2 million due to a decrease in volumes delivered of 1.7 million dekatherms.

Operating revenues were $1,591.5 million and $1,346.1 million for the twelve months ended January 31, 2005 and 2004, respectively. Operating revenues in 2005 increased $245.4 million compared with the similar prior period primarily due to the following increases.

	•	$165.3 million from NCNG and EasternNC, which included twelve months activity for 2005 and four months activity for 2004. Of this increase, $134.9 million was from an increase in volumes delivered of 40.9 million dekatherms and $27.5 million was from non-volumetric billings, such as facilities charges, reconnect fees and late payment fees.
	•	$41.5 million from secondary market transactions.
	•	$25.1 million from increased commodity gas costs passed through to customers.
	•	$11.3 million from the WNA due to surcharges of $13.6 million in 2005 compared with surcharges of $2.3 million in 2004.
	•	$6.7 million from non-volumetric billings related to customer growth and to changes in rate design in Tennessee effective November 1, 2003.

These increases were partially offset by a decrease of $4.6 million due to a decrease in sales volumes of .7 million dekatherms, excluding NCNG and EasternNC activity.

Cost of Gas

Cost of gas was $477.9 million and $422.3 million for the three months ended January 31, 2005 and 2004, respectively. Cost of gas in 2005 increased $55.6 million compared with the similar prior period primarily due to the following increases.

	•	$50.7 million from increased commodity gas costs.
	•	$9.9 million from secondary market transactions.

These increases were partially offset by a decrease of $9.6 million due to a decrease in volumes delivered of 1.7 million dekatherms.

Cost of gas was $1,097 million and $928.5 million for the twelve months ended January 31, 2005 and 2004, respectively. Cost of gas in 2005 increased $168.5 million compared with the similar prior period primarily due to the following increases.

	•	$102.3 million from NCNG and EasternNC, which included twelve months activity in 2005 and four months activity in 2004.
	•	$43.2 million from secondary market transactions.
	•	$25.1 million from increased commodity gas costs.

These increases were partially offset by a decrease of $3.3 million due to a decrease in volumes delivered of .7 million dekatherms, excluding NCNG and EasternNC activity.

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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 consolidated balance sheets.

In North Carolina and South Carolina, recoveries of gas costs are subject to annual gas cost recovery proceedings to determine the prudence of our gas purchases. We have been found prudent in all such past proceedings; however, there can be no guarantee that we will be found prudent in future proceedings.

Operations and Maintenance Expenses

Operations and maintenance expenses were $50.3 million and $49.7 million for the three months ended January 31, 2005 and 2004, respectively. Operations and maintenance expenses in 2005 increased $.6 million, or 1.2%.

Operations and maintenance expenses were $200.9 million and $163.3 million for the twelve months ended January 31, 2005 and 2004, respectively. Operations and maintenance expenses in 2005 increased $37.6 million compared with the similar prior period primarily due to the following increases.

	•	$16.6 million in payroll costs primarily due to merit increases, short-term incentive plans and the addition of NCNG employees for a full year in 2005 compared with only four months in 2004.
	•	$5.4 million in other corporate expenses primarily due to amortization of NCNG integration costs and the deferral in 2003 to a regulatory asset of EasternNC’s operations and maintenance costs that were expensed prior to September 30, 2003.
	•	$3.6 million in employee benefits expenses primarily due to pension and postretirement health care and life insurance costs.
	•	$3.2 million in outside labor primarily due to NCNG operations and increased costs of outsourced mainframe utilization.
	•	$2.3 million due to accrual of the projected benefit obligation for the Board of Director’s retirement plan.
	•	$2 million in outside consulting fees primarily due to business process improvement programs, the pipeline integrity management program and the integrated mapping project.
	•	$1.9 million in transportation expenses primarily due to NCNG operations.
	•	$1.8 million in utilities primarily due to NCNG operations and increased long distance telephone service.

These increases were partially offset by a decrease in the provision for uncollectibles of $1.8 million primarily due to improved collection activity, including recoveries of previously written off accounts.

Depreciation

Depreciation expense was $20.7 million and $20.5 million for the three months ended January 31, 2005 and 2004, respectively, and $82.6 million and $68.4 million for the twelve months ended January 31, 2005 and 2004, respectively. Depreciation expense in 2005 increased over similar prior periods primarily due to increases in plant in service, including a full year of depreciation expense on plant acquired from NCNG for the twelve months January 31, 2005, compared with only four months for the similar period in 2004. Due to the continued growth in our service areas and our commitment to capital expansion, we anticipate that depreciation expense will continue to increase.

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General Taxes

General taxes were $8.4 million and $6 million for the three months ended January 31, 2005 and 2004, respectively. General taxes in 2005 increased $2.4 million compared with the similar prior period primarily due to the following increases.

	•	$1.8 million in Tennessee property taxes as the expense in 2004 reflected the impact of a favorable court ruling that reduced assessed property values and the estimated tax accruals for prior periods.
	•	$.5 million in payroll taxes.

General taxes were $29.5 million and $24 million for the twelve months ended January 31, 2005 and 2004, respectively. General taxes increased $5.5 million compared with the similar prior period primarily due to the following increases.

	•	$2.4 million in property taxes from NCNG operations.
	•	$1.8 million in Tennessee property taxes discussed above.
	•	$1.5 million in payroll taxes.

Other Income (Expense)

Income from equity method investments was $5.8 million and $8.7 million for the three months ended January 31, 2005 and 2004, respectively. Income from equity investments decreased $2.9 million compared with the similar prior period primarily due a decrease in income from SouthStar of $1.2 million due to a one-time benefit recorded in 2004 of $2.5 million, and the absence of earnings from propane in 2005 due to the sale of our propane interest in January 2004.

Income from equity method investments was $24.5 million and $22.9 million for the twelve months ended January 31, 2005 and 2004, respectively. Income from equity investments in 2005 increased $1.6 million compared with the similar prior period primarily due to increases in earnings from SouthStar of $3.4 million and Pine Needle of $.4 million, partially offset by the absence of earnings from propane due to the sale in January 2004.

The sale of our propane interest resulted in an estimated gain of $5.1 million in January 2004, adjusted downward by $.4 million in the quarter ended April 30, 2004, based on actual data becoming available.

The equity portion of the allowance for funds used during construction (AFUDC) for the three months and twelve months ended January 31, 2005, decreased slightly compared with similar prior periods. AFUDC is allocated between equity and debt based on actual amounts computed and the ratio of construction work in progress to average short-term borrowings.

Non-operating income is comprised of merchandising, service work, subsidiary operations, interest income and other miscellaneous income. Changes in non-operating income were not material.

Charitable contributions were $.1 million and $.2 million for the three months ended January 31, 2005 and 2004, respectively, and $9 million and $.7 million for the twelve months ended January 31, 2005 and 2004, respectively. Contributions for the twelve months ended January 31, 2005, increased $8.3 million compared with the similar prior period primarily due to the initial funding of $7 million to the charitable foundation established in October 2004.

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Utility Interest Charges

Utility interest charges were $11.8 million and $11.2 million for the three months ended January 31, 2005 and 2004, respectively. Utility interest charges in 2005 increased $.6 million compared with the similar prior period primarily due to the following.

	•	$1.4 million increase in interest on long-term debt due to higher balances outstanding as a result of the permanent financing of the NCNG and EasternNC acquisitions.
	•	$.3 million increase in interest on Tennessee property taxes recorded in the prior year related to the court ruling as noted above in general taxes.
	•	$.6 million decrease in interest on amounts due to/from customers due to higher average net receivables in the current period as compared with the similar prior period.
	•	$.5 million decrease in interest on short-term debt primarily due to the repayment of the commercial paper program in December 2004.

Utility interest charges were $48 million and $41.1 million for the twelve months ended January 31, 2005 and 2004, respectively. Utility interest charges in 2005 increased $6.9 million compared with the similar prior period primarily due to the following.

	•	$8 million increase in interest on long-term debt due to higher balances outstanding, including amounts due to the permanent financing of the NCNG and EasternNC acquisitions.
	•	$.8 million increase in interest in connection with the Internal Revenue Service audit of our federal income tax return for the year ended October 31, 2001.
	•	$1.3 million decrease in interest on amounts due to/from customers due to significantly higher average net receivables in 2005 compared with average net payables in 2004.
	•	$1.3 million decrease in interest on short-term debt, primarily due to the repayment of commercial paper in December 2004.

Our Business

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 960,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 60,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including, as of January 31, 2005, unregulated retail natural gas marketing, interstate natural gas storage, intrastate natural gas transportation and regulated natural gas distribution. We also sell residential and commercial gas appliances in Tennessee.

Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of NCNG from Progress Energy, Inc. (Progress), for $417.5 million in cash plus $32.4 million for estimated working capital. We paid an additional $.3 million for actual working capital in our second quarter ended April 30, 2004. NCNG, a regulated natural gas distribution company, served 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. NCNG was merged into Piedmont immediately following the closing.

We also purchased for $7.5 million in cash Progress’ equity interest in EasternNC. EasternNC is a regulated utility that has a certificate of public convenience and necessity to provide natural gas service to 14 counties in eastern North Carolina that previously were not served with natural gas. Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. We are obligated to purchase additional authorized but unissued shares of such

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preferred stock for $14.4 million.

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 7 to the consolidated financial statements.

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 availability of and the prices paid for the interstate transportation of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, that are generally applicable to companies doing business in the United States of America.

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

We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us. For further information, see “Results of Operations” above and Note 9 to the condensed consolidated financial statements.

We invest in joint ventures to complement or supplement income from utility operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate the project with a major factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We make only those investments that are approved by the Board of Directors. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance and rates of return against expectations and make periodic reports to the Board. Decisions regarding exiting joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

Financial Condition and Liquidity

We believe we have access to adequate resources to meet our needs for working capital, construction expenditures, debt redemptions and dividend payments over the next 12 months. These resources include net cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and bank lines of credit.

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 such factors as weather, natural gas prices, collections from customers, natural gas purchases and gas inventory storage activity. 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 have positive cash flows from the sale of flowing gas and gas in storage and the collection of amounts billed to customers. This cash is used to reduce short-term debt to zero during much

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of our second and third quarters. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. Cash requirements generally increase during our third and fourth quarters due to increases in natural gas purchases for storage and decreases in collections from customers.

Net cash provided by (used in) operating activities was $(20.9) million and $60.1 million for the three months ended January 31, 2005 and 2004, respectively, and $73.5 million and $121.8 million for the twelve months ended January 31, 2005 and 2004, respectively. The primary factor that impacts our cash flows from operations is weather. Warmer weather can lead to lower total margin from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but extremely cold weather may lead to conservation by customers in order to reduce their consumption. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements. For the three months ended January 31, 2005 and 2004, 86% of our total sales and transportation revenues were from residential and commercial customers. For the twelve months ended January 31, 2005 and 2004, 80% and 85%, respectively, of our total sales and transportation revenues were from residential and commercial customers. Volumes of natural gas sold to both residential and commercial customers are weather-sensitive.

Our regulatory commissions approve rates that are designed to give us the opportunity to generate revenues, assuming normal weather, to cover our gas costs and fixed and variable non-gas costs and to earn a fair return for our shareholders. We have a WNA in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for weather-sensitive customers. Weather for the three months ended January 31, 2005, was 9% warmer than normal, compared with 3% warmer than normal for the same period in 2004. The WNA generated surcharges to customers of $14.1 million in the three months ended January 31, 2005, compared with surcharges of $2.6 million in the similar prior period. In North Carolina and Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account for subsequent collection from or disbursement to all customers in the class. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is minimal based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our supply needs if necessary.

The regulated utility faces competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products, such as electricity, fuel oil and propane, and the relative prices of those products. The most significant product competition is with electricity for space heating, water heating and cooking. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced billings and gas purchases.

In the industrial market, many of our customers have the capability of burning a fuel other than natural gas, fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With the imbalance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. The

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price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

Cash Flows from Investing Activities. Net cash provided by (used in) investing activities was $(22.7) million and $23.1 million for the three months ended January 31, 2005 and 2004, respectively, and $(82.3) million and $(477.2) million for the twelve months ended January 31, 2005 and 2004, respectively. The net cash used in investing activities for the three and twelve months ended January 31, 2005, and the three months ended January 31, 2004, was primarily for utility construction expenditures. Net cash used in investing activities for the twelve months ended January 31, 2004, was primarily for the acquisitions of NCNG and EasternNC. As expenditures are made in EasternNC’s service territory, reimbursement requests are made to the State of North Carolina under orders issued by the NCUC granting EasternNC a total of $188.3 million of bond funds. Such funds are available to pay for the uneconomic portion of the construction of a natural gas distribution infrastructure in the eastern part of the state. For further information about the bond fund, see “Gas Supply and Regulatory Proceedings” below.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. We have budgeted $157.4 million for utility construction expenditures for fiscal 2005. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecast.

We are in the process of selling our corporate office building located in Charlotte, North Carolina. We have negotiated a ten-year lease with renewable options for space in a building that is currently under construction and anticipated to be ready for occupancy in late 2005. The lease payments for the ten-year term range from $3 million to $3.4 million annually. Depending upon the sale terms and the occupancy date of the new office space, we may lease back our current office building prior to occupancy of the new office space.

Pending various governmental approvals, we intend to jointly develop an underground interstate natural gas storage facility in West Virginia with Columbia Hardy Corporation, a subsidiary of Columbia Gas Transmission Corporation. Total project capital expenditures are estimated at $100 to $110 million over a five-year period, of which our share is $50 to $55 million.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $63.4 million and $(69.8) million for the three months ended January 31, 2005 and 2004, respectively, and $9.6 million and $365.6 million for the twelve months ended January 31, 2005 and 2004, respectively. Funds are generally provided from bank borrowings and the issuance of Common Stock through dividend reinvestment and employee stock plans. When required, we sell Common Stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. As of January 31, 2005, our current assets were $564.3 million and our current liabilities were $484.1 million.

Under committed bank lines of credit totaling $200 million, outstanding short-term borrowings during the three months ended January 31, 2005, ranged from $95 million to $229.5 million, with interest rates from 2.11% to 3.04%. As of January 31, 2005, we had additional uncommitted lines of credit totaling $103 million on a no fee and as needed, if available, basis.

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

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due to the relationship between domestic supply and demand. If wholesale gas prices remain high, we may incur more short-term debt to pay for natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

Under our Common Stock Open Market Purchase Program, effective September 1, 2004, we utilize a broker to repurchase shares on the open market. Such shares are then cancelled and become authorized but unissued shares available for issuance to the Long-Term Incentive Plan and to dividend reinvestment and stock purchase plans.

We have paid quarterly dividends on our Common Stock since 1956. The amount of cash dividends that may be paid is restricted by provisions contained in certain note agreements under which long-term debt was issued. None of our retained earnings were restricted as of January 31, 2005.

As of January 31, 2005, our capitalization consisted of 42% in long-term debt and 58% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

As of January 31, 2005, 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. Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings.

We are subject to default provisions related to our long-term debt and short-term bank lines of credit. Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of January 31, 2005, we are in compliance with all default provisions.

Estimated Future Contractual Obligations

There were no material changes to our estimated future contractual obligations outside the ordinary course of business during the three months ended January 31, 2005.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases that are discussed in Note 7 to the consolidated financial statements in our Form 10-K for 2004.

Critical Accounting Policies and Estimates

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

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, goodwill and pension and postretirement benefits to be our critical

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accounting estimates. Management and our independent auditors have discussed the development and selection of the critical accounting estimates presented in our Form 10-K for the year ended October 31, 2004, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates since October 31, 2004.

Gas Supply and Regulatory Proceedings

In 1998, the North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act of 1998, which provided for the issuance of $200 million of general obligation bonds of the state for the purpose of providing grants, loans or other financing for the cost of constructing natural gas facilities in unserved areas of the state.

EasternNC is franchised to provide natural gas service to 14 counties in the eastern-most part of North Carolina. These counties historically have not been able to obtain gas service because of the relatively small population of the counties and the resulting uneconomic feasibility of providing service. The NCUC has issued orders granting $188.3 million of the bond fund to EasternNC for construction of natural gas facilities in the 14 counties. During the three months ended January 31, 2005, we filed for reimbursement of $14.1 million from the bond fund and received $11.8 million for previous requests. As of January 31, 2005, there was $18.8 million remaining of the bond funds allocated to EasternNC. As of January 31, 2005 and 2004, we had receivables of $5.9 million from the bond fund recorded in “Receivables” in the consolidated balance sheets.

Recent Developments

On February 1, 2005, we and the other owner of EasternNC executed a Stock Purchase Agreement whereby they will sell all of their shares of common stock of, and assign all of their rights and obligations in, EasternNC. Closing of the transaction is scheduled to occur three business days after all of the following conditions are met:

	•	Approval by Piedmont’s Board of Directors.
	•	Consideration of $1.00 paid by Piedmont to the other owner.
	•	Approval of the acquisition and merger by the NCUC.
	•	Approval by the NCUC to roll-in and combine the rate structure of EasternNC into Piedmont’s rate structure on terms and conditions acceptable to Piedmont.

On February 16, 2005, the Natural Gas Rate Stabilization Act of 2005 became effective in South Carolina. The law provides a mechanism for the regular, periodic and more frequent (annual) adjustment of rates which will encourage investment by natural gas utilities, such as Piedmont, enhance economic development efforts, reduce the cost of rate adjustment proceedings and result in smaller rate increases to customers. If the utility elects, the annual filing will provide that the utility’s cost of equity will remain within a 50-basis points band above or below the current allowed cost of capital. We expect to rely on this new law and file for a rate adjustment to reset rates effective November 1, 2005, the beginning of our 2006 fiscal year.

On February 28, 2005, we filed a letter of intent with the NCUC advising that Piedmont, our NCNG division and EasternNC intend to file a general rate application with the NCUC on or about April 1. New rates will be proposed to be effective November 1, 2005.

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Forward-Looking Statements

Documents we file with the Securities and Exchange Commission (SEC) may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. Forward-looking statements concern, among others, plans, objectives, proposed capital expenditures and future events or performance. These statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include:

	•	Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We are impacted by regulation of the NCUC, the PSCSC and the TRA. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated by the FERC and the NCUC, respectively.
	•	Residential, commercial and industrial growth in our service areas. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country.
	•	Deregulation, unanticipated impacts of regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies and we expect this highly competitive environment to continue.
	•	The potential loss of large-volume industrial customers due to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins.
	•	Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.
	•	The capital-intensive nature of our business. In order to maintain our historic growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our internally generated cash flows are not adequate to finance the full cost of this construction. As a result, we must fund a portion of our cash needs through borrowings.
	•	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. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging activities to reduce price volatility for our customers.
	•	Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild or severe weather, either during the winter period or the summer period, can have a significant impact on the demand for and the cost of natural gas.
	•	Changes in environmental and safety regulations and the cost of compliance.
	•	Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses and we assume such risks as an equity investor.

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All of these factors are difficult to predict and many are beyond our control. Accordingly, while we believe the assumptions underlying these forward-looking statements to be reasonable, there can be no assurance that these statements will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words “anticipate,” “believe,” “seek,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could” or “may” are intended to identify forward-looking statements.

Factors relating to regulation and management are also described or incorporated by reference in our Annual Report on Form 10-K, as well as information included in, or incorporated by reference from, future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in this report. There may also be other factors besides those described above or incorporated by reference in this report or in the Form 10-K that could cause actual conditions, events or results to differ from those in the forward-looking statements.

Forward-looking statements reflect our current expectations only as of the date they are made. We assume no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations. Please reference our web site at www.piedmontng.com for current information. Our filings on Form 10-K, Form 10-Q and Form 8-K are available at no cost on our web site on the same day the report is filed with the SEC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We hold all financial instruments discussed below for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Exposure to interest rate changes relates to both short- and long-term debt. Exposure to gas cost variations relates to the wholesale supply, demand and price of natural gas.

Interest Rate Risk

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

As of January 31, 2005, we had $189.5 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 2.81%. The carrying amount of our short-term debt approximates fair value. During the three months ended January 31, 2005, short-term debt ranged from $95 million to $229.5 million, with interest rates from 2.11% to 3.04%.

Information as of January 31, 2005, about our long-term debt that is sensitive to changes in interest rates is presented below.

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Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various duration for the forward sale and purchase of a portion of our natural gas requirements. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers and financial price-hedging instruments. Due to cost-based rate regulation in our utility operations, we have limited financial exposure to changes in commodity prices as substantially all changes in purchased gas costs and the costs of hedging our gas supplies are passed on to customers through PGA mechanisms.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Item 2 of this Form 10-Q.

Item 4. Controls and Procedures

As of January 31, 2005, management, including the Chairman, President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. Such disclosure controls and procedure are designed to ensure that all information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on our evaluation process, the Chief Executive Officer and the Chief Financial Officer have concluded that our disclosure controls and procedures are effective. Since the evaluation was completed, there have been no significant changes in internal controls or other factors that could significantly affect those controls.

Part II. Other Information

Item 1. Legal Proceedings

We have only routine litigation in the normal course of business and do not expect the outcomes to have any material impact on our financial position or results of operations.

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

a)	None.
b)	None.
c)	Issuer Purchases of Equity Securities.

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The following table provides information with respect to repurchases of our Common Stock during the quarter ended January 31, 2005.

In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorizes the repurchase of up to three million of currently outstanding shares of Common Stock. The program was implemented on September 1, 2004.

Item 3. Defaults Upon Senior Securities

None.

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

We held our Annual Meeting of Shareholders on March 4, 2005, to elect four directors and to ratify the selection of independent auditors. The record date for determining the shareholders entitled to receive notice of and to vote at the meeting was January 12, 2005. We solicited proxies for the meeting according to section 14(a) of the Securities and Exchange Act of 1934. There was no solicitation in opposition to management’s solicitations.

Shareholders elected all of the nominees for director as listed in the proxy statement by the following votes:

Directors John W. Harris, Aubrey B. Harwell, Jr., and David E. Shi will continue in office until 2006. Directors Jerry W. Amos, D. Hayes Clement and Thomas E. Skains will continue in office until 2007. Shareholders ratified the selection by the Board of Directors of the firm of Deloitte & Touche LLP as

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independent auditors for the fiscal year ending October 31, 2005, by the following vote:

Item 5. Other Information

(a) None.

(b) There have been no changes to the procedures by which security holders may recommend nominees to our Board of Directors.

Item 6. Exhibits

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SIGNATURES

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

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