UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended January 31, 2004

or

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 Securities Exchange Act of 1934).
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.

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

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

See notes to consolidated financial statements.

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

See notes to consolidated financial statements.

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

     See notes to consolidated financial statements.

4

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

See notes to consolidated financial statements.

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

1.		Independent auditors have not audited the consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2003 Annual Report.
2.		In our opinion, the unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at January 31, 2004 and October 31, 2003, and the results of operations and cash flows for the three months and twelve months ended January 31, 2004 and 2003.
		We make estimates and assumptions when preparing financial statements. Those estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from our 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 have capitalized 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 refunds to utility customers in future periods.
4.		All of our goodwill is attributable to the regulated utility segment. The following presents the balance in goodwill as of October 31, 2003 and January 31, 2004, and the changes for the three months ended January 31, 2004.

		The purchase price allocation adjustment is primarily due to an increase in the liability for pension restoration and deferred director’s fees based on additional information obtained subsequent to the initial purchase price allocation.
		We are in the process of evaluating and measuring certain assets acquired and liabilities assumed in the acquisition, primarily working capital. The allocation of the purchase price is subject to refinement according to terms specified in the stock purchase agreement and is expected to be completed in fiscal 2004.
5.		Our business is seasonal in nature. The results of operations for the three-month period ended January 31, 2004, do not necessarily reflect the results to be expected for the full year.

6.

We compute basic earnings per share using the weighted average number of shares of Common Stock

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	outstanding during the period. A reconciliation of basic and diluted earnings per share is presented below:

7.		Based on products and services, regulatory environments and our corporate organization and business decision-making activities, we have two reportable business segments, regulated utility and non-utility activities. Operations of our regulated utility segment are conducted by the parent company and by EasternNC. Operations of our non-utility activities segment comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Energy Company and Piedmont Propane Company.
		Operations of the regulated utility segment are reflected in operating income in the consolidated statements of income. Operations of the non-utility activities segment are included in “Other Income (Expense)” in the consolidated statements of income in either “Non-utility activities, at equity” or “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 income from non-utility activities, at equity, and investment in non-utility activities, at equity. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in our audited financial statements for the year ended October 31, 2003.
		Operations by segment for the three months ended January 31, 2004 and 2003, are presented below:

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A reconciliation of operating income and net income in the consolidated financial statements for the three months ended January 31, 2004 and 2003, is presented below:

     A reconciliation of consolidated assets in the consolidated financial statements as of January 31, 2004 and October 31, 2003, is presented below:

8.

The consolidated financial statements include the accounts of a wholly owned subsidiary of Piedmont Natural Gas Company, Piedmont Energy Partners, Inc. (PEP). PEP is a holding company for certain other wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. These subsidiaries include Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company, Piedmont Propane Company and Piedmont Energy Company. Our ownership interest in each entity is recorded in “Investments in non-utility activities, at equity” in the consolidated balance sheets. Earnings or losses from equity investments are recorded in “Non-utility activities, at equity” in “Other Income (Expense)” in the consolidated statements of income. On November 6, 2003, Piedmont Greenbrier Pipeline Company, LLC, a wholly owned subsidiary of Piedmont Natural Gas Company, sold its equity interest in the proposed Greenbrier interstate natural gas pipeline to the other member of the venture at its book value of $9.2 million.

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		As of January 31, 2004, the amount of our retained earnings that represented undistributed earnings of 50% or less owned entities accounted for by the equity method was $23.7 million.
		Piedmont Intrastate Pipeline Company
		Piedmont Intrastate Pipeline Company owns 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 at rates approved by the NCUC. We record in cost of gas the transportation costs charged by Cardinal. These gas costs were $1.2 million and $.4 for the three months ended January 31, 2004 and 2003, respectively, and $2.5 million and $1.5 million for the twelve months ended January 31, 2004 and 2003, respectively. We owed Cardinal $.4 million and $.1 million at January 31, 2004 and 2003, respectively.
		Summarized unaudited financial information provided to us by Cardinal for 100% of Cardinal for its fiscal quarters ended December 31, 2003 and 2002, is presented below.

		Piedmont Interstate Pipeline Company
		Piedmont Interstate Pipeline Company owns 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 at rates approved by the FERC. We record in cost of gas the storage costs charged by Pine Needle. These gas costs were $3.1 million and $2.7 million for the three months ended January 31, 2004 and 2003, respectively, and $11 million and $10.8 million for the twelve months ended January 31, 2004 and 2003, respectively. We owed Pine Needle $1 million and $.9 million at January 31, 2004 and 2003, respectively.
		Summarized unaudited financial information provided to us by Pine Needle for 100% of Pine Needle for its fiscal quarters ended December 31, 2003 and 2002, is presented below.

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		Piedmont Propane Company
		Prior to January 20, 2004, Piedmont Propane Company owned 20.69% of the membership interests in US Propane, L.P. US Propane owned all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage Propane), a marketer of propane through a nationwide retail distribution network.
		On January 20, 2004, we, along with the other members of US Propane, completed the sale of US Propane’s general and limited partnership interests in Heritage Propane for $130 million. Our share of the proceeds was $26.9 million. We recognized a pre-tax gain of $5.1 million on the sale in the three months ended January 31, 2004. In connection with the sale, US Propane retained approximately 180,000 common units of Heritage Propane for ultimate distribution to US Propane’s members.
		Summarized unaudited financial information for Heritage Propane for 100% of Heritage Propane for its fiscal quarters ended November 30, 2003 and 2002 is presented below.

		Piedmont Energy Company
		Piedmont Energy Company owns 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. 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.
		The Operating Policy of SouthStar contains a provision for the disproportionate sharing of earnings in excess of a threshold per annum, cumulative pre-tax return of 17%. Prior to December 31, 2003, we recognized as equity earnings only the amounts that we believed had been earned as the calculation methodologies and interpretations of the Operating Policy that impact the members’ disproportionate earnings sharing percentages had not been agreed to by the members. On December 31, 2003, we entered into an agreement in principle with the other member of SouthStar that addressed a number of matters under the LLC Agreement and the Operating Policy, including the resolution of certain disproportionate sharing issues. Based on this agreement in principle and consistent with the understandings reached by the members that are yet to be documented, we recorded an increase in pre-tax earnings from SouthStar of $2.5 million in the three months ended January 31, 2004.
		We have related party transactions with SouthStar for purchases of wholesale gas supplies from us. Our operating revenues totaled zero and $.5 million for the three months ended January 31, 2004 and 2003, respectively, and $.4 million and $9.6 million for the twelve months ended January 31, 2004 and 2003, respectively. As of January 31, 2004, and 2003, SouthStar owed us $16,300 and $327,000, respectively.
		Summarized unaudited financial information provided to us by SouthStar for 100% of SouthStar for its fiscal quarters ended December 31, 2003 and 2002, 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 adjustment (PGA) procedures. We structure the pricing, quantity and term provisions of our gas supply contracts to maximize flexibility and minimize cost and risk for our customers. We have a management-level Energy Risk Management Committee that monitors compliance with our risk management policies.
		Through January 31, 2004, we had purchased and sold financial options for natural gas for our Tennessee gas purchase portfolio. As of January 31, 2004, we had forward positions through March 2004. 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, 2004, we had purchased and sold financial options for natural gas for our South Carolina gas purchase portfolio. As of January 31, 2004, we had forward positions for March 2004 through October 2004. The costs of these options are pre-approved by the Public Service Commission of South Carolina (PSCSC) for recovery from customers subject to our following the provisions of the gas cost hedging plan approved by the PSCSC.
		Through January 31, 2004, we had purchased and sold financial options for natural gas for our North Carolina gas purchase portfolio. As of January 31, 2004, we had forward positions for March 2004 through October 2004. Costs associated with our North Carolina hedging program are not pre-approved 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 of the North Carolina and South Carolina programs as all costs and related gain or loss amounts are passed through to customers under PGA procedures and are recorded in “Refunds due customers,” a regulatory liability. We mark the derivative instruments to market with a corresponding entry to “Refunds due customers.” As of January 31, 2004, the amount in “Refunds due customers” of $14.3 million is net of $3.3 million due from customers for the costs of the North Carolina and South Carolina hedging programs and the related mark-to-market adjustments.

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 North Carolina, South Carolina and Tennessee. Our subsidiaries are invested in joint venture, energy-related businesses. For the three months ended January 31, 2004, net income was $74.6 million, or $2.18 per diluted share, compared with $58

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million, or $1.74 per diluted share, for the same period last year. Operating results for the current three-month period reflect the first full quarter effect of the acquisitions of NCNG and a 50% interest in EasternNC on September 30, 2003. Results for the three months ended January 31, 2003, include a one-time, non-recurring benefit of $.17 per share due to a change in the way we record revenues and cost of gas on volumes delivered but not yet billed.

Our utility operations are weather sensitive. Weather in our service area during the current quarter was 3% warmer than normal and 11% warmer than in the prior year quarter. System throughput increased from 63.6 million dekatherms to 73.5 million dekatherms due to the acquisitions of NCNG and a 50% interest in EasternNC and continued customer growth. Operations and maintenance expenses increased primarily due to higher payroll, pension and other employee benefit costs from the addition of NCNG and the provision for uncollectibles.

Other income for the current quarter was $8.5 million compared with $2.7 million in the prior year quarter primarily due to a one-time pre-tax benefit of $2.5 million ($.04 per share) from the resolution of certain disproportionate sharing issues between the members of SouthStar and a one-time pre-tax gain of $5.1 million ($.09 per share) from the sale of our interest in Heritage Propane Partners, L.P. (Heritage Propane).

Results of Operations

We will discuss the results of operations for the three months and twelve months ended January 31, 2004, compared with similar periods in 2003.

Operating Revenues

Operating revenues were $618.8 million and $493.5 million in the three months ended January 31, 2004 and 2003, respectively. Operating revenues in 2004 increased $125.3 million compared with the similar prior period primarily due to the following increases:

	•		$109.1 million from volumes to NCNG customers.
	•		$65.3 million due to increased wholesale gas prices charged to customers.
	•		$12.8 million from weather normalization adjustment mechanisms (WNA) due to surcharges of $3.6 million in 2004 compared with refunds of $9.2 million in 2003, excluding the impact of WNA for NCNG. 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.
	•		$5.2 million from increased customer rates and charges and changes in rate design in Tennessee effective November 1, 2003.
	•		$.6 million in other revenues primarily from late payments and reconnection fees.

These increases were partially offset by the following decreases.

	•		$64 million due to a decrease in sales volumes of 8 million dekatherms, excluding the impact of NCNG.
	•		$3.5 million from secondary market transactions.

Operating revenues were $1,346.1 million and $1,036.8 million in the twelve months ended January 31,

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2004 and 2003, respectively. Operating revenues in 2004 increased $309.3 million compared with the similar prior period primarily due to the following increases:

	•		$183.2 million due to increased wholesale gas prices charged to customers.
	•		$128.8 million from volumes to NCNG customers.
	•		$5.1 million from the WNA due to surcharges of $3.2 million in 2004 compared with refunds of $1.9 million in 2003.
	•		$49.8 million from secondary market transactions.
	•		$23.5 million from increased customer rates and charges and changes in rate design effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.
	•		$2 million in other revenues primarily from late payments and reconnection fees.

These increases were partially offset by a decrease in revenues of $87.9 million due to a decrease in sales volumes of 12.1 million dekatherms, excluding the impact of NCNG.

Cost of Gas

Cost of gas was $422.3 million and $331.8 million in the three months ended January 31, 2004 and 2003, respectively. Cost of gas in 2004 increased $90.5 million compared with the similar prior period primarily due to the following increases:

	•		$69 million from volumes to NCNG customers.
	•		$65.3 million due to increased wholesale gas prices charged to customers.

These increases were partially offset by the following decreases.

	•		$42 million due to a decrease in sales volumes of 8 million dekatherms, excluding the impact of NCNG.
	•		Decrease of $2.9 million from secondary market transactions.

Cost of gas was $928.5 million and $662.5 million in the twelve months ended January 31, 2004 and 2003, respectively. Cost of gas in 2004 increased $266 million compared with the similar prior period primarily due to the following increases:

	•		$183.2 million due to increased wholesale gas prices charged to customers.
	•		$88.7 million from volumes to NCNG customers.
	•		$49.4 million from secondary market transactions.
	•		$5.7 million from regulatory adjustments.

These increases were partially offset by a decrease of $58.8 million due to a decrease in sales volumes of 12.1 million dekatherms, excluding the impact of NCNG.

Margin (Operating Revenues less Cost of Gas)

Margin was $196.5 million and $161.7 million in the three months ended January 31, 2004 and 2003, respectively. Margin in 2004 increased $34.8 million compared with the similar prior period due to the following increases.

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	•		$40.7 million due to the acquisitions of NCNG and an equity interest in EasternNC.
	•		$12.8 million from the WNA.

These increases were partially offset by the following decreases.

	•		$18 million due to a decrease in sales and transportation volumes of 9.1 million dekatherms, excluding the impact of NCNG.
	•		$.7 million from secondary market transactions.

Margin was $417.7 million and $374.3 million in the twelve months ended January 31, 2004 and 2003, respectively. Margin in 2004 increased $43.4 million compared with the similar prior period due to the following increases.

	•		$47 million due to the acquisitions of NCNG and an equity interest in EasternNC.
	•		$23.5 million from increased customer rates and charges, including changes in rate design, effective November 1, 2002, in North Carolina and South Carolina and effective November 1, 2003, in Tennessee.
	•		$5.1 million from the WNA.
	•		$2 million in other revenues primarily from late payments and reconnection fees.

These increases were partially offset by the following decreases.

	•		$27.5 million due to a decrease in sales and transportation volumes of 12 million dekatherms, excluding the impact of NCNG.
	•		$5.7 million from the allocation of gas costs between jurisdictions and capitalization of demand costs.
	•		$.4 million from secondary market transactions.

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 “Refunds due customers” in the consolidated balance sheets. In North Carolina and South Carolina, recovery of gas costs is subject to findings made in 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. Annual prudence reviews were eliminated in Tennessee when the incentive plan was established in 1996. This plan established an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark rates, together with income from marketing transportation and storage capacity in the secondary market.

Operations and Maintenance Expenses

Operations and maintenance expenses were $49.7 million and $38.5 million in the three months ended January 31, 2004 and 2003, respectively. Operations and maintenance expenses for 2004 increased $11.2 million compared with the similar prior period primarily for the reasons listed below.

•

Increase of $6.3 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases and accrual of the short-term incentive plan.

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	•		Increase of $.7 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices.
	•		Increase of $1.5 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from the acquisition of NCNG.
	•		Increase of $.6 million in transportation expense primarily due to the acquisitions of NCNG and EasternNC.
	•		Increase of $.5 million in other corporate expense primarily related to bank fees and amortization of NCNG integration costs.
	•		Increase of $.9 million in outside labor costs primarily due to the acquisition of NCNG and pipeline locating expenses.

Operations and maintenance expenses were $163.3 million and $138.2 million in the twelve months ended January 31, 2004 and 2003, respectively. Operations and maintenance expenses in 2004 increased $25.1 million compared with the similar prior period primarily for the reasons listed below.

	•		Increase of $13.8 million in payroll primarily due to the addition of employees from the acquisition of NCNG, merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, accruals of the short-term and long-term incentive plans and severance paid to NCNG employees not acquired.
	•		Increase of $5.4 million in employee benefits expense primarily due to increases in pension and postretirement healthcare and life insurance costs, including the impact of the addition of employees from NCNG.
	•		Increase of $2.3 million in the provision for uncollectibles primarily due to charge-offs of higher gas bills due to higher gas prices.
	•		Increase of $1.4 million in risk insurance due to higher premiums and the impact of the NCNG acquisition.
	•		Increase of $1.2 million in outside labor primarily related to pipeline locating services, building services and computer services.
	•		Increase of $1.2 million in transportation expense due to the NCNG acquisition.
	•		Decrease of $2.7 million due to the deferral of operations and maintenance expenses of EasternNC that were expensed prior to September 30, 2003. As ordered by the NCUC, these expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper.

Depreciation

Depreciation expense was $20.5 million and $15.3 million in the three months ended January 31, 2004 and 2003, respectively, and $68.4 million and $58.7 million in the twelve months ended January 31, 2004 and 2003, respectively. Depreciation expense in 2004 increased over similar prior periods primarily due to increases in plant in service, including depreciation expense on plant acquired from NCNG and EasternNC. Due to the continued growth in our service areas, our commitment to capital expansion and a full year of depreciation expense in 2004 on plant acquired from NCNG and EasternNC, we anticipate that depreciation expense will continue to increase.

General Taxes

General taxes were $6 million and $6.4 million in the three months ended January 31, 2004 and 2003,

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respectively. General taxes in 2004 decreased $.4 million compared with the similar prior period primarily for the reasons listed below.

	•		Decrease of $1.8 million in Tennessee property taxes as a result of a favorable court ruling.
	•		Increase of $.8 million in property taxes in other states.
	•		Decrease of $.2 million in Tennessee gross receipts taxes.
	•		Increase of $.7 million in payroll taxes.

General taxes were $24 million and $25 million in the twelve months ended January 31, 2004 and 2003, respectively. General taxes decreased $1 million compared with the similar prior period primarily for the reasons listed below.

	•		Decrease of $1.8 million in Tennessee property taxes as noted above.
	•		Increase of $1.2 million in payroll taxes.
	•		Decrease of $.2 million in use tax from an audit in the prior period.
	•		Decrease of $.1 million in franchise taxes.
	•		Decrease of $.1 million in excise taxes on company use gas.

Other Income (Expense)

Income from equity investments was $8.7 million and $3.8 million in the three months ended January 31, 2004 and 2003, respectively. Income from equity investments increased $4.9 million compared with the similar prior period primarily due to increases in earnings from SouthStar of $4.3 million, including a one-time benefit of $2.5 million, and from US Propane of $.5 million.

Income from equity investments was $22.9 million and $14.9 million in the twelve months ended January 31, 2004 and 2003, respectively. Income from equity investments in 2004 increased $8 million compared with the similar prior period primarily due to increases in earnings from SouthStar of $5.2 million and from US Propane of $2.8 million.

Gain on sale of equity investments of $5.1 million in the three months and twelve months ended January 31, 2004, resulted from the sale of our interest in Heritage Propane.

The equity portion of the allowance for funds used during construction (AFUDC) in the three months ended January 31, 2004, increased slightly and in the twelve months ended January 31, 2004, decreased slightly compared with similar prior periods. AFUDC is allocated between equity and debt based on the ratio of construction work in progress to average short-term borrowings.

Non-operating income is comprised of merchandising, jobbing and compressed natural gas operations, the non-equity portion of activities of the subsidiaries, interest income and other miscellaneous income.

Non-operating expense is composed of charitable contributions and other miscellaneous expenses.

Utility Interest Charges

Utility interest charges were $11.2 million and $10.3 million in the three months ended January 31, 2004 and 2003, respectively. Utility interest charges in 2004 increased $.9 million compared with the similar prior period primarily for the reasons listed below.

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	•		Increase of $1.1 million in interest on short-term debt due to the commercial paper issued to temporarily finance the acquisitions of NCNG and an equity interest in EasternNC.
	•		Increase of $.5 million in interest on long-term debt due to higher amounts of debt outstanding.
	•		Decrease of $.8 million in interest on refunds due customers due to lower balances outstanding.

Utility interest charges were $41.1 million and $40.4 million in the twelve months ended January 31, 2004 and 2003, respectively. Utility interest charges in 2004 increased $.7 million compared with the similar prior period primarily for the reasons listed below.

	•		Increase of $2.2 million in interest on short-term debt due to the commercial paper issued to temporarily finance the acquisitions of NCNG and an equity interest in EasternNC.
	•		Decrease of $.1 million in the portion of AFUDC attributable to borrowed funds.
	•		Decrease of $1.4 million in interest on refunds due customers due to lower balances outstanding.

Our Business

Piedmont Natural Gas, which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 940,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee, including 60,000 customers served by municipalities who are our wholesale customers. Our subsidiaries are invested in joint venture, energy-related businesses, including 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.

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

Our utility operations are subject to regulation 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 subject to regulation 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 and maintenance 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.

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 Note 9 to the consolidated financial statements.

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

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area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.

Financial Condition and Liquidity

We finance current cash requirements primarily from operating cash flows and short-term borrowings. During the three months ended January 31, 2004, outstanding short-term borrowings under committed bank lines of credit totaling $200 million ranged from $83.5 million to $174 million, and interest rates ranged from 1.47% to 1.61%. As of January 31, 2004, we had additional uncommitted lines of credit totaling $68 million on a no fee and as needed, if available, basis.

To provide for the temporary financing of our acquisitions of NCNG and the equity interest in EasternNC, we had a $450 million commercial paper program. During the three months ended January 31, 2004, we sold long-term debt and common stock and used the net proceeds of $372.3 million to repay a portion of the outstanding commercial paper. The balance of the outstanding commercial paper was repaid from internally generated cash and the program was terminated.

Our utility operations are weather sensitive. 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 our customers in order to reduce their consumption. Weather outside the normal range of temperatures can impact operating cash flows, thereby altering the need for short-term borrowings to meet current cash requirements. During the twelve months ended January 31, 2004, 52% of our sales and transportation revenues were from residential customers and 33% were from commercial customers, both of which are weather sensitive.

Our regulatory commissions approve rates that are designed to produce revenues to cover our gas costs and our fixed and variable non-gas costs assuming normal weather. In addition, we have WNA in all three states that partially offset 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, 2004, was 3% warmer than normal, compared with 9% colder than normal for the same period in 2003. The WNA generated charges to customers of $2.6 million for the three months ended January 31, 2004, and credits to customers of $9.2 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 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 regulated utility faces competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products and the relative prices of those products. The most significant product competition occurs between natural gas and 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 end user. This could negatively impact our liquidity if customer growth slows or if customers conserve.

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

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the price of natural gas. With the growing imbalance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the market price of natural gas in the future. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted either positively or negatively as a result of alternate fuel decisions by industrial customers.

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 additional customer demand during cold weather 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 fluctuate for the next several years due to the growing imbalance 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.

We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. On December 19, 2003, we sold $200 million of medium-term notes and used the net proceeds of $198.2 million to redeem commercial paper issued in connection with funding the acquisitions of NCNG and an equity interest in EasternNC. On January 23, 2004, we sold 4,250,000 shares of Common Stock at a public offering price of $42.50 per share. The proceeds of $174.1 million, net of underwriting discount and expenses, were used to repay a portion of our outstanding commercial paper. During the twelve months ended January 31, 2004, we issued $17.1 million of common equity through dividend reinvestment and stock purchase plans.

As of January 31, 2004, our capitalization consisted of 43% in long-term debt and 57% 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, 2004, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services with a negative outlook and “A3” by Moody’s Investors Service with a negative outlook. 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 various factors. The more significant quantitative factors include:

	•		Ratio of total debt to total capitalization, including balance sheet leverage,
	•		Ratio of net cash flows to capital expenditures,
	•		Funds from operations interest coverage,
	•		Ratio of funds from operations to average total debt and
	•		Pre-tax interest coverage.

Qualitative factors include, among other things:

	•		Stability of regulation in the jurisdictions in which we operate,
	•		Risks and controls inherent in the distribution of natural gas,
	•		Predictability of cash flows,
	•		Business strategy and management,
	•		Corporate governance guidelines and practices,
	•		Industry position and

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•

Contingencies.

We are subject to default provisions related to our long-term debt, short-term bank lines of credit and accounts receivable financing. The default provisions of our senior notes are:

	•		Failure to make principal, interest or sinking fund payments,
	•		Interest coverage of less than 1.75 times,
	•		Total debt cannot exceed 70% of total capitalization,
	•		Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total capitalization,
	•		Failure to make payments on any capitalized lease obligation,
	•		Bankruptcy, liquidation or insolvency and
	•		Final judgment against us in excess of $1 million that after 60 days is not discharged, satisfied or stayed pending appeal.

The default provisions of our medium-term notes are:

	•		Failure to make principal, interest or sinking fund payments,
	•		Failure after the receipt of a 90-day notice to observe or perform for any covenant or agreement in the notes or in the indenture under which the notes were issued and
	•		Bankruptcy, liquidation or insolvency.

Failure to satisfy any of the default provisions results in total outstanding issues becoming due. There are cross default provisions in all our debt agreements. Based on our calculations, we met the default provisions as of January 31, 2004.

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 other services prior to payment and the availability of other marketers of natural gas to meet our supply needs if necessary.

The natural gas business is seasonal in nature, resulting in fluctuations primarily in balances in accounts receivable from customers, inventories of stored natural gas and accounts payable to suppliers, in addition to fluctuations in short-term borrowings noted above. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. As is prevalent in the industry, we inject natural gas into storage during the summer months (principally April through October) for withdrawal from storage during the winter months (principally November through March) when customer demand is higher. Inventories of gas in storage decreased from October 31, 2003 to January 31, 2004, and accounts payable and accounts receivable increased during this same period due to seasonality, higher gas prices, the growth of our business, including the acquisitions of NCNG and EasternNC, and the demand for gas during the winter season.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our current annual growth in customer base. Utility construction expenditures in the three months ended January 31, 2004, were $21.1 million, compared with $17.6 million in the similar prior period. Utility construction expenditures in the twelve months ended January 31, 2004, were $83.8 million, compared with $83.1 million in the similar prior period. Due to projected growth in our service area, significant utility construction expenditures are expected to continue. Short-term debt may be used to

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finance construction pending the issuance of long-term debt or equity.

As of January 31, 2004, our estimated future contractual obligations for long-term debt, purchase obligations and capital and operating leases were as follows:

Off-balance Sheet Arrangements

We have no material off-balance sheet arrangements other than operating leases.

Critical Accounting Policies and Estimates

Our accounting policies are fundamental to understanding our results of operations and financial condition. In our Form 10-K for the year ended October 31, 2003, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we identified one critical policy and five other policies that require significant judgments and estimates in preparing the consolidated financial statements. We also described the more significant accounting policies we use in Note 1 to the consolidated financial statements in our Form 10-K. We prepare our 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. These interim financial statements should be read together with the consolidated financial statements, notes and the critical accounting policies and estimates included in our Form 10-K.

Accounting Pronouncements

In December 2003, the Financial Accounting Standards Board issued SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits (Revised)” (Statement 132). Statement 132 requires additional disclosures about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. We will adopt Statement 132 in our second quarter beginning February 1, 2004.

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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. As a result of deregulation, 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 construct additions to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining government 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 cash flows are not adequate to finance the cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock.
	•		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 will allow us to remain competitive. Natural gas is an unregulated commodity subject to market 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.

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	•		Changes in weather conditions. Weather conditions and other natural phenomena can have a large 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 regulations and cost of compliance.
	•		Earnings from our equity investments. We have investments in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks.

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 for natural gas.

Interest Rate Risk

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

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As of January 31, 2004, we had $123 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 1.56%. During the three months ended January 31, 2004, short-term debt ranged from $83.5 million to $174 million, with interest rates ranging from 1.47% to 1.61%. The carrying amount of our short-term debt approximates fair value.

Information as of January 31, 2004, about our long-term debt that is sensitive to changes in interest rates is presented below.

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various durations for the forward sales and purchase of natural gas. 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 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 under PGA procedures.

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, 2004, 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 procedures 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. We do not expect any material impact on financial position or results of operations.

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Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

None.

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 February 27, 2004, to elect five directors, to ratify the selection of independent auditors and to approve the 2003 Executive Long-Term Incentive Plan. The record date for determining the shareholders entitled to receive notice of and to vote at the meeting was January 9, 2004. 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 management’s nominees for director as listed in the proxy statement by the following votes:

Directors Malcolm E. Everett III and Muriel W. Helms will continue in office until 2005. Directors C. M. Butler III, John W. Harris and Aubrey B. Harwell, Jr., will continue in office until 2006.

Shareholders ratified the selection by the Board of Directors of the firm of Deloitte & Touche LLP as independent auditors for the fiscal year ending October 31, 2004, by the following vote:

Shareholders approved the 2003 Executive Long-Term Incentive Plan by the following vote:

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Item 5. Other Information

Regulatory Proceedings

On March 17, 2003, we, along with two other natural gas companies in Tennessee, filed a petition with the TRA requesting a declaratory order that the gas cost portion of uncollectible accounts is recoverable through PGA procedures. The petition stated that to the extent that the gas cost portion of net write-offs for a fiscal year exceeds the gas cost portion of uncollectible accounts allowed in base rates, the unrecovered portion would be included in Actual Cost Adjustment (ACA) filings for future recovery from customers. Conversely, to the extent that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion included in base rates, the difference would be refunded to customers through the ACA filings. On February 9, 2004, the TRA approved the petition by modifying the formula in the PGA rules to allow for the recovery of uncollected gas costs.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits -

(b)		Reports on Form 8-K -
		On November 6, 2003, we filed a Form 8-K regarding a press release announcing the sale of our 33% equity interest in the Greenbrier Pipeline project to Dominion Resources.
		On November 7, 2003, we filed a Form 8-K regarding a press release announcing an agreement by us and our three partners to sell our general and limited partnership interests in Heritage Propane Partners, L.P., to Energy Transfer Company.
		On December 15, 2003, we filed a Form 8-K regarding press releases announcing changes in the Board of Directors and officer positions, 2003 year-end and fourth-quarter operating results, subject to completion of the annual audit, and the declaration of a dividend on common stock.

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		On December 17, 2003, we filed a report on Form 8-K regarding a press release announcing the placement of an offering of $200 million aggregate principal amount of long-term debt.
		On December 23, 2003, we filed a report on Form 8-K regarding the sale of $100 million of 5% Notes due 2013 and $100 million of 6% Notes due 2033 under a shelf registration statement filed with the Securities and Exchange Commission.
		On December 30, 2003, we filed a report on Form 8-K regarding a press release announcing the election of David E. Shi to our Board of Directors.
		On January 9, 2004, we filed a report on Form 8-K to disclose our audited financial statements for the year ended October 31, 2003.
		On January 12, 2004, we filed a report on Form 8-K regarding a press release to report our intention to issue 4.25 million new shares of common stock in a public offering.
		On January 21, 2004, we filed a report on Form 8-K regarding press releases to report the sale of our general and limited partnership interests in Heritage Propane and the pricing of a public offering of 4.25 million shares of common stock.
		Outside of the period, on March 1, 2004, we filed a report of Form 8-K regarding press releases to announce first-quarter operating results and the declaration of a dividend on common stock.

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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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