UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

(Mark One)

Or

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

     Commission file number 1-6196

Piedmont Natural Gas Company, Inc.

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

     State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of April 30, 2004.

Common Stock, no par value - $1,530,797,879

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 4, 2005, are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

2004 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

PART I

Item 1. Business

     Piedmont Natural Gas Company, Inc. (Piedmont), was incorporated in New York in 1950 and began operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the same name for the purpose of changing our state of incorporation to North Carolina.

     Piedmont 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. 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.

     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.

     Effective at the close of business on September 30, 2003, we purchased 100% of the common stock of North Carolina Natural Gas Corporation (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 Eastern North Carolina Natural Gas Company (EasternNC), a regulated utility. EasternNC 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 preferred stock for $14.4 million.

     We have two reportable business segments, regulated utility and non-utility activities. Operations of our regulated utility segment are conducted by Piedmont, the parent company, and by EasternNC and are conducted within the United States of America. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures. As of October 31, 2004, these operations were primarily conducted by Piedmont Intrastate Pipeline Company (Piedmont Intrastate), Piedmont Interstate Pipeline Company (Piedmont Interstate) and Piedmont Energy Company (Piedmont Energy). All of these companies are wholly owned subsidiaries of Piedmont Energy Partners, a holding company that is a wholly owned subsidiary

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of the parent company.

     Piedmont Intrastate owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina. Piedmont Interstate owns 40.0587% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina. Piedmont Energy owns 30% of the membership interests in SouthStar Energy Services LLC (SouthStar), 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.

     As of October 31, 2003, Piedmont Greenbrier Pipeline Company, LLC, owned 33% of the membership interests in Greenbrier Pipeline Company, LLC (Greenbrier). Greenbrier was formed to build a proposed interstate gas pipeline from West Virginia to North Carolina. On November 6, 2003, we sold our interest to the other member in the venture for our book value of $9.2 million.

     Prior to January 20, 2004, Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners, owned 20.69% of the membership interests in US Propane, L.P., which 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, we, along with the other members, 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 recorded a gain on the sale of $4.7 million in our first quarter ended January 31, 2004. In connection with the sale, the former members of US Propane formed TAAP, LP, a limited partnership, to receive the approximately 180,000 common units of Heritage Propane retained in the sale. On May 21, 2004, TAAP distributed to us 37,244 common units of Energy Transfer Partners, LP (formerly Heritage Propane), as our share of the retained units.

     On November 12, 2004, our subsidiary, Piedmont Hardy Storage Company, LLC, and Columbia Hardy Corporation, a subsidiary of Columbia Gas Transmission Corporation (Columbia Gas), a subsidiary of NiSource Inc., announced an agreement to form Hardy Storage Company LLC (Hardy Storage), with each having a 50% equity interest in the project. Hardy Storage will seek approval from the FERC to construct, own and operate an underground natural gas storage facility located in Hardy and Hampshire Counties, West Virginia. Subject to obtaining all necessary approvals, construction is expected to begin in October 2005 with storage service commencing with initial injections in April 2007. Our portion of the project capital expenditures is estimated at $50 to $55 million. Columbia Gas will serve as operator of the facilities.

     Operations by segment for the years ended October 31, 2004, 2003 and 2002, are presented below.

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     Operating revenues shown in the consolidated statements of income represent revenues from the regulated utility segment. The cost of purchased gas is a component of operating revenues. Increases or decreases in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures. Therefore, our operating revenues are impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For the year ended October 31, 2004, 41% of our operating revenues were from residential customers, 23% from commercial customers, 13% from industrial and power generation customers, 20% from secondary market activity and 3% from various other sources. Operations of the non-utility activities segment are included in “Other Income (Expense)” in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.” For further information on equity method investments and business segments, see Notes 10 and 11 to the consolidated financial statements in Item 8 of this Form 10-K.

     Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (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. The utility operations of EasternNC are subject to regulation by the NCUC. 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 Federal Energy Regulatory Commission (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

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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.

     We hold non-exclusive franchises for natural gas service in the communities we serve, with expiration dates from 2005 to 2054. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. Two franchises have expired as of October 31, 2004, and four will expire within the next fiscal year. We continue to operate in those areas with expired franchises with no significant impact on our business as we have operated normally within the provisions of the expired franchise. The likelihood of cessation of service under an expired franchise is remote. We believe that these franchises will be renewed with no material adverse impact on us as most government entities do not want to prevent their citizens from having access to gas service or to interfere with our required system maintenance. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action.

     The natural gas distribution business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months when temperatures are colder. For further information on weather sensitivity and the impact of seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form 10-K. 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. During the year ended October 31, 2004, the amount of natural gas in storage varied from 7.5 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 27 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $37 million to $138.7 million.

     During the year ended October 31, 2004, which reflects a full year of the operations of NCNG and EasternNC compared with only one month in 2003, 102.5 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 62.5 million dekatherms in 2003. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 89.9 million dekatherms in 2004, compared with 86.3 million dekatherms in 2003. Weather, as measured by degree days, was 6% warmer than normal in 2004 and 3% colder than normal in 2003.

     The following is a five-year comparison of operating statistics for the years ended October 31, 2000 through 2004:

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     As of October 31, 2004, we had contracts for the following pipeline firm transportation capacity in dekatherms of daily deliverability:

     In addition, we had the following contracts for local peaking facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to meet the firm demands of our markets. This availability varies from five days to one year:

     We own or have under contract 29.9 million dekatherms of storage capacity, either in the

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form of underground storage or LNG. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases.

     The gas delivered to meet our design day requirements for firm customers is purchased under firm contractual commitments. These contracts provide that we pay a reservation fee to the supplier to reserve or guarantee the availability of gas supplies for delivery. Under these provisions, absent force majeure conditions, any disruption of supply deliverability is subject to penalty and damage assessment against the supplier. We ensure the delivery of the gas supplies to our distribution system to meet the peak day, seasonal and annual needs of our customers by using a variety of firm transportation and storage capacity arrangements. The pipeline capacity contracts require the payment of fixed demand charges to reserve firm transportation or storage entitlements. We align the contractual agreements for supply with the firm capacity agreements in terms of volumes, receipt and delivery locations and demand fluctuations. We may supplement firm contractual commitments with other supply arrangements to serve our interruptible market, or as an alternate supply for inventory withdrawals or injections. The source of the gas we distribute is primarily from the on-shore and off-shore Gulf Coast production region and is purchased primarily from major producers and marketers. For further information on gas supply and regulation, see “Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K.

     During the year ended October 31, 2004, 8% of our margin (operating revenues less cost of gas) was generated from deliveries to industrial or large commercial customers that have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or increase deliveries of gas to these customers depends on a number of factors, including weather conditions, governmental regulations, the price of gas from suppliers and the price of alternate fuels. Under regulations of the FERC, certain large-volume customers located in proximity to the interstate pipelines delivering gas to us could attempt to bypass us and take delivery of gas directly from the pipeline or from a third party connecting with the pipeline. Through October 31, 2004, only minimal bypass activity has been experienced, in part because of our ability to negotiate competitive rates and service terms. The future level of bypass activity cannot be predicted.

     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. There are four major electric company competitors within our service areas. We continue to attract the majority of the new residential construction market, and we believe that the consumer’s preference is for natural gas based on such factors as reliability, comfort and convenience compared with electricity to meet their needs. In addition to its many advantages, natural gas has historically maintained a price advantage over electricity in our service areas; however, with the increasing customer demand for natural gas, flat to declining production levels and other public policy issues primarily associated with access to public lands for drilling, natural gas prices and price volatility have increased. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer.

     In the industrial market, many of our customers are capable of burning a fuel other than

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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 natural gas supply and demand has the greatest impact on the price of our product. 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 price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and policies of foreign and domestic governments.

     During the year ended October 31, 2004, our largest customer contributed $14.1 million, or 1%, to total operating revenues.

     We spend an immaterial amount for research and development costs, primarily limited to gas industry-sponsored research projects.

     Compliance with federal, state and local environmental protection laws have had no material effect on construction expenditures, earnings or competitive position. For further information on environmental issues, see “Environmental Matters” in Item 7 of this Form 10-K.

     During our fourth quarter ended October 31, 2004, we established and committed to funding the Piedmont Natural Gas Foundation. The charitable foundation was funded with $7 million in cash in November 2005.

     As of October 31, 2004, we had 2,120 employees, compared with 2,155 as of October 31, 2003.

     Our filings on Form 10-K, Form 10-Q and Form 8-K are available at no cost on our web site at www.piedmontng.com on the same day the report is filed with the Securities and Exchange Commission.

Item 2. Properties

     All property shown in the consolidated balance sheets in “Utility Plant” is owned by the parent company or EasternNC and is used in our regulated utility segment. This property consists of intangible plant, production plant, storage plant, transmission plant, distribution plant and general plant as categorized by natural gas utilities, with 93% of the total invested in distribution and transmission plant to serve our customers. We have approximately 2,350 miles of lateral pipelines up to 30 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 21,150 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or property owned by others, for which we have obtained the necessary legal rights to place and operate our facilities on private property. All of these properties are located within our service areas in North Carolina, South Carolina and Tennessee. Utility Plant includes “Construction work in progress” which represents projects, primarily distribution, transmission and general plant, that have not been placed into service pending completion.

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     None of our property is encumbered and all property is in use.

     We own our corporate headquarters building located in Charlotte, North Carolina, and we own or lease for varying periods district and regional offices in the locations shown below. Lease payments for these various offices totaled $1.6 million for the year ended October 31, 2004.

     We are in the process of selling our corporate headquarters building. We have negotiated a preliminary 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 are estimated to range from $3 million to $3.4 million annually. We expect to lease back our current office building prior to occupancy of the new office space.

     All property shown in the consolidated balance sheets “Other Physical Property” is owned by the parent company and is primarily comprised of residential and commercial water heaters leased to natural gas customers. None of our subsidiaries directly own property as their operations consist solely of participating in joint ventures as an equity member.

Item 3. 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 4. Submission of Matters to a Vote of Security Holders

     No matters were submitted to a vote of security holders during our fourth quarter ended October 31, 2004.

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PART II

     Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     (a) Our Common Stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following table provides information with respect to the high and low sales prices on the NYSE for each quarterly period for the years ended October 31, 2004 and 2003. All amounts reflect a two-for-one stock split effective October 11, 2004.

     (b) As of January 7, 2005, our Common Stock was owned by 16,409 shareholders of record.

     (c) The following table provides information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2004 and 2003. All amounts reflect a two-for-one stock split effective October 11, 2004. We expect that comparable cash dividends will continue to be paid in the future.

     The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of October 31, 2004, net earnings available for restricted payments were greater than retained earnings; therefore, none of our retained earnings were restricted.

     On June 4, 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that authorizes the repurchase of up to three million shares of currently outstanding shares of Common Stock. We utilize a broker to repurchase the shares on the open market and such shares are then cancelled and become authorized but unissued shares available for issuance under the Dividend Reinvestment and Stock Purchase Plan, the Employee Stock Purchase Plan and the Executive Long-Term Incentive Plan. We implemented the program on September 1, 2004, and during September and October repurchased .2 million shares of Common Stock at a total cost of $4.5 million.

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     The following table provides information with respect to repurchases of our Common Stock during the fourth quarter ended October 31, 2004. All amounts except the number of shares authorized reflect a two-for-one stock split effective October 11, 2004.

Item 6. Selected Financial Data

     The following table provides selected financial data for the years ended October 31, 2000 through 2004 . The information presented is not comparable due to the acquisitions of North Carolina Natural Gas Corporation (NCNG) and an equity interest in Eastern North Carolina Natural Gas Company (EasternNC) effective September 30, 2003.

     *Reflects a two-for-one stock split effective October 11, 2004.

Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations

Overview Our Operations. 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 and is regulated by three state regulatory commissions. The 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 rate of return for our shareholders. The regulated utility is weather sensitive and faces competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy

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products and the relative prices of those products. The regulated utility faces competition in the industrial market as many of our customers have the capability of burning a fuel other than natural gas. Fuel oil is the most significant competing energy alternative for such customers. Our ability to maintain industrial market share is largely dependent on price.

     The non-utility activities segment consists of our equity method investments in joint venture, energy–related businesses that are involved, as of October 31, 2004, in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

Key Items in Fiscal 2004

	•	Net income increased 28% to $95.2 million and diluted earnings per share increased 14% to $1.27 per share.
	•	A two-for-one stock split was effective on October 11, 2004.
	•	In September 2004, we implemented a common stock repurchase program.
	•	We completed the permanent financing of the acquisitions of North Carolina Natural Gas Corporation (NCNG) and a 50% equity interest in Eastern North Carolina Natural Gas Company (EasternNC) through the sale of long-term debt and Common Stock. The acquisitions were originally financed with commercial paper.
	•	We began a Continuous Business Process Improvement (CBPI) program that analyzed key areas of our business to identify and implement improvements to increase revenues, to reduce costs and to better serve customers.
	•	We began to reorganize our customer service delivery system to enhance operational efficiency and to improve customer satisfaction.
	•	We refocused our non-utility activities segment by completing the sale of our interests in US Propane, L.P., and the proposed Greenbrier Pipeline project.
	•	We established a charitable foundation with an initial funding commitment of $7 million.

Results of Operations Operating results for 2004 reflect the full effect of the acquisitions of NCNG and an equity interest in EasternNC on September 30, 2003.

     Net income was $95.2 million in 2004, $74.4 million in 2003 and $62.2 million in 2002. As more fully explained in this section, the net income increase of $20.8 million in 2004 compared with 2003 was primarily due to the following:

	•	$105.5 million increase in margin (operating revenues less cost of gas).
	•	$9.4 million increase in income from equity method investments.
	•	$4.7 million gain on the sale of our equity method investment in propane.
		These increases were partially offset by the following:
	•	$48.2 million increase in operations and maintenance expenses.
	•	$19.1 million increase in depreciation expense.
	•	$8.4 million increase in charitable contributions.
	•	$7.2 million increase in interest on long-term debt.
	•	$2.6 million increase in general taxes.

     The net income increase of $12.2 million in 2003 compared with 2002 was primarily due to an increase of $47.1 million in margin, partially offset by increases of $18.7 million in operations and maintenance expenses and $5.6 million in depreciation expense.

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     Compared with the prior year, weather in our service area, as measured by degree days, was 9% warmer in 2004, 21% colder in 2003 and 21% warmer in 2002. Volumes of gas delivered to customers were 201.3 million dekatherms in 2004, compared with 149.3 million dekatherms in 2003 and 126.1 million dekatherms in 2002. In addition to volumes delivered to customers, secondary market sales volumes were 51.7 million dekatherms in 2004, compared with 45.9 million dekatherms in 2003 and 55.7 million dekatherms in 2002.

     Operating revenues were $1,529.7 million in 2004, $1,220.8 million in 2003 and $832 million in 2002. Operating revenues in 2004 increased $308.9 million compared with 2003 primarily due to the following increases:

	•	$259.9 million from the increase in volumes of 59.6 million dekatherms and facility charges from NCNG customers, including the impact of weather normalization adjustment mechanism (WNA) credits of $1.6 million. 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.
	•	$28.5 million from secondary market activity.
	•	$32.2 million from increased commodity gas costs.
	•	$13.3 million from the WNA due to charges of $3.7 million in 2004 compared with credits of $9.6 million in 2003, excluding the impact of WNA for NCNG.
	•	$8.4 million from increased customer rates and charges, including changes in rate design, in Tennessee, effective November 1, 2003.

     Excluding NCNG, volumes decreased 7.8 million dekatherms primarily due to 9% warmer weather. This decrease resulted in a decrease in operating revenues of $46.8 million.

     Operating revenues in 2003 increased $388.8 million compared with 2002 primarily due to the following increases:

	•	$98.3 million from increased volumes due to colder weather and growth in our customer base, including $16.2 million from customers acquired in the purchase of North Carolina Gas Service (NCGS) in September 2002. Volumes increased 16.4 million dekatherms primarily due to 21% colder weather.
	•	$143.7 million from increased commodity gas costs.
	•	$99.6 million from secondary market activity.
	•	$31.9 million due to a change in 2003 in the way we recorded revenues and cost of gas related to volumes delivered but not yet billed. See Note 1.J to the consolidated financial statements.
	•	$25.7 million from increased customer rates and charges, including changes in rate design, in North Carolina and South Carolina, effective November 1, 2002.
	•	$19 million from customers acquired in the NCNG acquisition.

     These increases were partially offset by $10.2 million in WNA credits in 2003 compared with charges of $19.8 million in 2002, a net decrease in operating revenues of $30 million.

     In general rate proceedings, state regulatory commissions have authorized us to recover a margin, applicable rate less cost of gas, on each unit of gas delivered. The commissions have also authorized us to recover margin losses resulting from negotiating lower rates to industrial customers when necessary to remain competitive. The ability to recover such negotiated margin

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reductions is subject to continuing regulatory approvals.

     Cost of gas was $1,041.4 million in 2004, $837.9 million in 2003 and $496.2 million in 2002. Cost of gas in 2004 increased $203.5 million compared with 2003 primarily due to the following increases:

	•	$166.3 million from the increase in volumes from NCNG customers.
	•	$30.3 million from an increase in secondary market activity.
	•	$32.2 million from increased commodity gas costs.

     Excluding NCNG, volumes decreased 7.8 million dekatherms which resulted in a decrease in cost of gas of $32.8 million.

     Cost of gas in 2003 increased $341.7 million compared with 2002 primarily due to the following increases:

	•	$143.7 million from increased commodity gas costs.
	•	$56.9 million from an increase in volumes delivered, including $10.4 million from NCGS customers.
	•	$99 million from an increase in secondary market activity.
	•	$22.8 million from a change in 2003 in the way we recorded revenues and cost of gas related to volumes delivered but not yet billed. See Note 1.J to the consolidated financial statements.
	•	$13.3 million from the acquisitions of NCNG and an equity interest in EasternNC.

     Margin was $488.4 million in 2004, $382.9 million in 2003 and $335.8 million in 2002. The margin increase of $105.5 million in 2004 compared with 2003 was primarily due to the following increases:

	•	$104.8 million from the increase in volumes and facility charges from NCNG customers, including the impact of WNA credits of $1.6 million.
	•	$13.3 million from the WNA due to charges of $3.7 million in 2004 compared with credits of $9.6 million in 2003, excluding the impact of WNA for NCNG.
	•	$8.4 million from increased customer rates and charges, including changes in rate design, in Tennessee, effective November 1, 2003.

     Excluding NCNG, volumes decreased 7.8 million dekatherms which resulted in a decrease in margin of $14 million.

     The margin increase of $47.1 million in 2003 compared with 2002 was primarily due to the following increases:

	•	$43 million due to an increase of 16.4 million dekatherms due to customer growth, including the NCGS acquisition, and colder weather.
	•	$24.9 million from increased customer rates and charges, including changes in rate design, in North Carolina and South Carolina, effective November 1, 2002.
	•	$9.2 million due to a change in 2003 in the way we recorded revenues and cost of gas related to volumes delivered but not yet billed. See Note 1.J to the consolidated financial statements.
	•	$5.7 million due to the acquisitions of NCNG and an equity interest in EasternNC.

     These increases were partially offset by a decrease of $30 million due to WNA credits of

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$10.2 million in 2003 compared with charges of $19.8 million in 2002.

     Operations and maintenance expenses were $200.3 million in 2004, $152.1 million in 2003 and $133.4 million in 2002. Operations and maintenance expenses increased $48.2 million in 2004 compared with 2003 primarily due to the following increases:

	•	$22.8 million in payroll costs primarily due to merit increases, the addition of NCNG employees for a full year and accruals of short-term incentive plans.
	•	$5.9 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. See Note 3 to the consolidated financial statements.
	•	$4.3 million in employee benefits expense primarily due to pension and postretirement health care and life insurance costs.
	•	$4 million in outside labor primarily due to NCNG operations and increased costs of outsourced mainframe utilization.
	•	$2.4 million in transportation primarily due to NCNG operations.
	•	$2.3 million due to accrual of the projected benefit obligation for the Board of Director’s retirement plan.
	•	$1.6 million in utilities primarily due to NCNG operations.
	•	$1.2 million in materials primarily due to NCNG operations.
	•	$1.2 million in outside consulting fees primarily due to the CBPI program, the pipeline integrity management program and the integrated mapping project.

     Operations and maintenance expenses increased $18.7 million in 2003 compared with 2002 primarily due to the following increases:

	•	$9 million in payroll costs primarily due to merit increases, including the impact of moving to a common review date for all non-bargaining unit employees, the addition of NCNG employees, accruals of the short-term and long-term incentive plans and severance paid to NCNG employees not acquired.
	•	$5.1 million in employee benefits expense primarily due to increases in pension and postretirement health care and life insurance costs.
	•	$3.4 million in the provision for uncollectibles primarily due to higher charge-offs resulting from colder weather and higher gas prices.
	•	$1.5 million in risk insurance due to higher premiums.

     These increases were partially offset by a decrease of $2.7 million to defer to a regulatory asset EasternNC’s operations and maintenance costs that were expensed prior to September 30, 2003. See Note 3 to the consolidated financial statements.

     Depreciation expense increased from $57.6 million to $82.3 million over the three-year period 2002 to 2004 primarily due to increases in plant in service, including a full year of depreciation expense in 2004 compared with only one month in 2003 on plant acquired from NCNG. Due to the continued growth in our service areas and our commitment to capital expansion, we anticipate that depreciation expense will continue to increase.

     General taxes were $27 million in 2004, $24.4 million in 2003 and $23.9 million in 2002. General taxes increased $2.6 million in 2004 compared with 2003 primarily due to the reasons listed below.

•

$1.7 million increase in payroll taxes.

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	•	$1.5 million increase in property taxes.
	•	$.3 million decrease in Tennessee gross receipts taxes.

     General taxes increased $.5 million in 2003 compared with 2002 primarily due to the reasons listed below.

	•	$.6 million increase in payroll taxes.
	•	$.3 million increase in Tennessee gross receipts taxes.
	•	$.2 million decrease due to a non-recurring payment in 2002 related to a sales and use tax audit in North Carolina.

     Income from equity method investments was $27.4 million in 2004, $18 million in 2003 and $19.2 million in 2002. The increase of $9.4 million in 2004 compared with 2003 was primarily due to an increase of $8.9 million in earnings from SouthStar, including a one-time benefit of $2.5 million from the resolution of certain disproportionate sharing issues between the members of SouthStar, and an increase of $.4 million in earnings from Pine Needle.

     Income from equity method investments decreased $1.2 million in 2003 compared with 2002 primarily due to a decrease in earnings from SouthStar of $4.1 million, partially offset by an increase in earnings from propane operations of $3.1 million.

     The gain on sale of equity method investments of $4.7 million in 2004 resulted from the sale of our propane interests effective January 20, 2004. See Note 10 to the consolidated financial statements.

     The equity portion of the allowance for funds used during construction (AFUDC) was $.9 million in 2004, $1.1 million in 2003 and $2 million in 2002. 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, the non-equity-method portion of the activities of our subsidiaries, interest income and other miscellaneous income. Non-operating income was $2.3 million in 2004, $2.6 million in 2003 and $1.2 million in 2002.

     Charitable contributions were $9.1 million in 2004, $.7 million in 2003 and $.6 million in 2002. Contributions increased $8.4 million in 2004 primarily due to the initial commitment of $7 million to the newly established charitable foundation.

     Utility interest charges were $47.4 million in 2004, $40.2 million in 2003 and $40.6 million in 2002. Utility interest charges increased $7.2 million in 2004 compared with 2003 primarily due to the reasons listed below.

	•	$7.2 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.
	•	$.3 million increase in interest on short-term debt due to the commercial paper used to temporarily finance the acquisitions.
	•	$.8 million 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 higher average net receivables in 2004 compared with significantly higher average net payables in 2003.

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     Utility interest charges decreased $.4 million in 2003 compared with 2002 primarily due to the reasons listed below.

	•	$1 million decrease in interest on long-term debt due to lower balances outstanding.
	•	$1 million decrease in interest on amounts due to customers due to lower net payables outstanding.
	•	$1.2 million increase in interest on short-term debt, primarily due to the commercial paper used to temporarily finance the NCNG and EasternNC acquisitions.

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 October 31, 2004, 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.

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

     Effective September 30, 2002, we purchased for $26 million in cash substantially all of the natural gas distribution assets and certain of the liabilities of NCGS, a division of NUI Utilities, Inc. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina.

     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 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 11 to the consolidated financial statements.

     Our utility operations are subject to regulation by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also

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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 Federal Energy Regulatory Commission (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 Notes 3 and 6 to the 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. These resources include net cash flow from operating activities, access to capital markets, investments in non-utility activities 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, the timing of 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 increases in working capital needs. During the first and second quarters, we generally have positive cash flows from the sale of flowing gas and gas in storage and the collection of accounts receivable from customers. This cash is used to reduce short-term debt to zero during much of the 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 the third and fourth quarters due to increases in accounts payable for natural gas purchases for storage and decreases in collections of accounts receivable.

     Net cash provided by operating activities was $154.3 million in 2004, $96.7 million in

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2003 and $108 million in 2002. 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. Weather outside the normal range of temperatures can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements. During 2004, 51% of our sales and transportation revenues were from residential customers and 30% were from commercial customers, both of which 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 weather normalization adjustment mechanisms (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 in 2004 was 6% warmer than normal, compared with 3% colder than normal in 2003 and 15% warmer than normal in 2002. The WNA generated charges to customers of $2.1 million in 2004, credits to customers of $9.6 million in 2003 and charges to customers of $19.8 million in 2002. 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 purchased gas adjustment (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 other 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 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 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.

Cash Flows from Investing Activities. Net cash used in investing activities was $36.3 million in 2004, $515.2 million in 2003 and $87.6 million in 2002. The net cash used in investing activities

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for 2004 was primarily due to utility construction expenditures. Gross utility construction expenditures were $141.8 million ($103.2 million net of AFUDC, contributions in aid of construction and bond reimbursements for EasternNC’s expenditures). 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. The capital expansion program supports the growth in our customer base. Net utility construction expenditures in 2004 were $103.2 million, compared with $80.3 million in 2003 and $83.7 million in 2002. Gross utility construction expenditures totaling $157.4 million, primarily to serve customer growth, are budgeted for 2005; however, we are not contractually obligated to expend capital until the work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecast.

     Our equity interest in EasternNC consists of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s preferred stock. We are obligated to purchase additional authorized but unissued shares of such preferred stock for $14.4 million.

     We are in the process of selling our corporate office building located in Charlotte, North Carolina. We have negotiated a preliminary 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 are estimated to range from $3 million to $3.4 million annually. We expect to lease back our current office building prior to occupancy of the new office space.

     We received $36.1 million from the sale of equity method investments in 2004, $26.9 million from our investment in US Propane, L.P., and $9.2 million from our investment in Greenbrier Pipeline Company, LLC. We received $26.3 million in capital distributions from our equity method investments in 2004, compared with $10.2 million in 2003 and $22.1 million in 2002. We regularly evaluate the performance of the non-utility activities segment based on earnings from the ventures and the return on our investments in the ventures.

     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. For further information, see “Equity Method Investments” below.

     In 2003, we acquired 100% of the common stock of NCNG and a 50% equity interest in EasternNC from Progress. In 2002, we acquired substantially all of the natural gas distribution assets and certain liabilities of NCGS, a division of NUI Utilities, Inc. These acquisitions were a part of our focus on growing our core utility business. For further information regarding the acquisitions, see Note 1.E and Note 2 to the consolidated financial statements.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $(123.5) million in 2004, $424.6 million in 2003 and $(20.9) million in 2002. 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

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debt to cover cash requirements when market and other conditions favor such long-term financing. As of October 31, 2004, our current assets were $335.2 million and our current liabilities were $306.2 million.

     Under committed bank lines of credit totaling $200 million, outstanding short-term borrowings during 2004 ranged from zero to $174 million, and interest rates ranged from 1.39% to 2.25%. As of October 31, 2004, we had additional uncommitted lines of credit totaling $103 million on a no fee and as needed, if available, basis.

     In addition to these bank lines of credit, we had a commercial paper program where we could issue up to $450 million in unsecured promissory notes that were backed by a $450 million credit agreement scheduled to expire June 22, 2004. This program was put in place to provide for the temporary financing of our acquisitions of NCNG and the equity interest in EasternNC. The notes issued under this program on September 29, 2003, were sold at a discount from face values at LIBOR cost-plus rates, with maturities ranging from one to 30 days. On December 19, 2003, we repaid $198.3 million of commercial paper with the proceeds from the sale of $200 million of medium-term notes. On January 23, 2004, we sold 8.5 million shares of Common Stock at a public offering price of $21.25 per share (4.3 million shares at $42.50 on a pre-split basis). The proceeds of $174.3 million, net of underwriting discount, were used to repay a portion of our outstanding commercial paper. On January 22, 2004, we repaid the balance of $16 million of the outstanding commercial paper from internally generated cash, and the program was terminated.

     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 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.

     During 2004, we issued $20 million of Common Stock through dividend reinvestment and stock purchase plans. Under the Common Stock Open Market Purchase Program discussed in Note 5 to the consolidated financial statements, we repurchased in our fourth quarter ended October 31, 2004, .2 million shares of Common Stock that are available for reissuance to these plans. In June 2004, we made the remaining scheduled sinking fund payment of $2 million on the 10.06% senior notes.

     We increased our Common Stock dividend on an annualized basis by $.03 per share in 2002, 2003 and 2004. Dividends of $63.3 million, $54.9 million and $51.9 million for 2004, 2003 and 2002, respectively, were paid on Common Stock. The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in certain note agreements under which long-term debt was issued; however, as of October 31, 2004, none of our retained earnings were restricted. For further information, see Note 4 to the consolidated financial statements.

     As of October 31, 2004, our capitalization consisted of 44% in long-term debt and 56% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

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     As of October 31, 2004, 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. 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
	•	Contingencies.

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

	•	Failure to make principal, interest or sinking fund payments,
	•	Interest coverage of 1.75 times,
	•	Total debt cannot exceed 70% of total capitalization,
	•	Funded debt of all subsidiaries in the aggregate cannot exceed 15% of total company 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 would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of October 31, 2004, we are in compliance with all default provisions.

     As of October 31, 2004, our estimated future contractual obligations were as follows.

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	(1)	For further detail on long-term debt, see Note 4 to the consolidated financial statements.
	(2)	Presented as current, however, there is no timeframe specified in the acquisition documents.
	(3)	100% recoverable through purchased gas adjustment (PGA) procedures.
	(4)	Reservation fees that are 100% recoverable through PGA procedures.
	(5)	Consists primarily of maintenance fees for hardware and software applications, usage fees, local and long- distance data costs, frame relay, cell phone and pager usage fees and contract labor and consulting fees.
	(6)	Excludes amounts due for new corporate office space pending the negotiation of the final lease and the completion of the building. See Note 7 to the consolidated financial statements.
	(7)	Consists primarily of pipeline products, vehicles, contractors and merchandise.

Off-balance Sheet Arrangements We have no off-balance sheet arrangements other than operating leases that are reflected in the table above and discussed in Note 7 to the consolidated financial statements.

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 accounting estimates. Management and our independent auditors have discussed the development and selection of the critical accounting estimates presented below with the Audit Committee of the Board of Directors.

Regulatory Accounting. Our regulated utility segment is subject to regulation by certain state and federal authorities. Our accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting For The Effects of Certain Types of Regulation”

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(Statement 71), and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues in the balance sheet as regulatory assets and liabilities when those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. We then recognize these deferred regulatory assets and liabilities through the income statement in the period in which the same amounts are reflected in rates. If we, for any reason, cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, we would eliminate from the balance sheet the regulatory assets and liabilities related to those portions ceasing to meet such criteria and include them in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such an event could have a material effect on our results of operations in the period this action was recorded. Regulatory assets as of October 31, 2004 and 2003, totaled $65.1 million and $41.7 million, respectively. Regulatory liabilities as of October 31, 2004 and 2003, totaled $297.6 million and $282.6 million, respectively. The detail of these regulatory assets and liabilities is presented in Note 1.B to the consolidated financial statements.

Revenue Recognition. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA procedures. A WNA factor, based on the margin or base rate component of the billing rate, is included in rates charged to residential and commercial customers during the winter period of November through March in all jurisdictions except EasternNC. The WNA is designed to offset the impact that unusually cold or warm weather has on customer billings during the winter season. Without the WNA, our operating revenues in 2004 would have been lower by $2.1 million.

     Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. Meters are read throughout the month based on an approximate 30-day usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, changes in weather during the period and the impact of the WNA. Prior to 2003, we recognized revenues from meters read on a monthly cycle basis and deferred the cost of gas for volumes delivered but not yet billed. Secondary market, or wholesale, sales revenues are recognized when the physical sales are delivered based on the contracted or market prices.

Goodwill. All of our goodwill is attributable to the regulated utility segment. We evaluate goodwill for impairment annually, or more frequently if impairment indicators arise, using a weighted average of the guideline company method of the market approach and the discounted cash flow method of the income approach on the premise of continued use, which assumes that a buyer and seller contemplate the continued use of the reporting unit at its present location as part of current and future operations. The guideline company method of the market approach is based on market multiples of companies that are representative of our peers in the natural gas distribution industry. The discounted cash flow method of the income approach consists of estimating annual future cash flows and individually discounting them back to the present value. These calculations are dependent on several subjective factors, including the timing of future cash flows, future growth rates and the discount rate. The calculations also define the reporting unit as the domestic natural gas distribution business. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. Through October 31, 2004, no impairment has been recognized.

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     Using a discounted cash flow model to estimate fair value is subjective and requires significant judgment in applying a discount rate, growth assumptions and continued cash flows. An increase or decrease of 100 basis points in the weighted average cost of capital would have the following effects.

     The 100 basis point increase or decrease in the weighted average cost of capital would not have required the recording of an impairment charge.

Pension and Postretirement Benefits. We have a defined-benefit pension plan for the benefit of eligible full-time employees. We also provide certain postretirement health care and life insurance benefits to eligible full-time employees. Our reported costs of providing these benefits, as described in Note 8 to the consolidated financial statements, are impacted by numerous factors, including the provisions of the plans, changing employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used, our estimate of these costs is a critical accounting estimate.

     Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expenses and liabilities related to the plans. These factors include assumptions about the discount rate used in determining future benefit obligations, projected health care cost trend rates, expected long-term return on plan assets and rate of future compensation increases, within certain guidelines. In addition, our actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate projected benefit obligations. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.

     The discount rate is determined by developing a hypothetical bond portfolio matching our projected benefit cost with our projected benefit obligations. Based on market trends, we reduced the discount rate to 5.75% in 2004 from 6.25% in 2003 and 7% in 2002. Based on our review of actual cost trend rates and projected future trends in establishing health care cost trend rates, we changed our health care cost trend rate from 11.5% in 2002 to 10% in 2003 and 10.5% in 2004, declining gradually to 5% in 2012 for participants aged less than 65. For participants aged greater than 65, we changed our health care cost trend rate from 14.5% in 2002 to 13% in 2003 and 10.5% in 2004, declining gradually to 5% by 2012.

     In determining our expected long-term rate of return on plan assets, we review past long-term performance, asset allocations and long-term inflation assumptions. We target our asset allocation for pension plan assets to be approximately 60% equity securities and 40% fixed income securities. The target allocation for our other postretirement benefit assets is also 60% equity securities and 40% fixed income securities. Based on market trends, we reduced the expected long-term rate of return of plan assets from 9.5% in 2002 to 8.5 % in 2003 and 2004. Based on a fairly stagnant inflation trend, our assumed rate of increase in future compensation levels has remained at 3.97% from 2002 to 2004.

     The following reflects the sensitivity of pension cost in certain actuarial assumptions,

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assuming that the other components of the calculation are constant.

     The following reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions, assuming that the other components of the calculation are constant.

     We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

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 2004, we filed $42.4 million for reimbursement from the bond fund and received $41.5 million. As of October 31, 2004, there was $30.5 million remaining of the bond funds allocated to EasternNC. As of October 31, 2004 and 2003, we had receivables of $3.5 million and $2.6 million, respectively, related to the bond fund recorded in “Receivables” in the consolidated balance sheets.

     Secondary market transactions permit us to market gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute smaller per-unit wholesale margins to earnings; however, the program allows us to act as a wholesale marketer of natural gas and transportation capacity in order to generate operating margin from sources not restricted by the capacity of our retail distribution system. In North Carolina and South Carolina, a sharing mechanism is in effect where 75% of any margin earned is refunded to customers. Secondary market transactions in Tennessee are included in the performance incentive plan discussed in Note 6 to the consolidated financial statements.

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     No general rate case activity is expected that would impact 2005 earnings in any of our jurisdictions. See Note 3 to the consolidated financial statements.

Equity Method Investments As of October 31, 2003, we owned 33% of the membership interests in Greenbrier Pipeline Company, LLC (Greenbrier). The other member was a subsidiary of Dominion Resources, Inc. Greenbrier was formed to build a proposed interstate gas pipeline from West Virginia to North Carolina. On November 6, 2003, we sold our interest in Greenbrier to Dominion Resources for our book value of $9.2 million.

     On November 12, 2004, we, and a subsidiary of NiSource Inc., announced an agreement to form Hardy Storage Company LLC (Hardy Storage), with each having a 50% equity interest in the project. Hardy Storage will seek approval from the FERC to construct, own and operate an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia. If approved, the facility will have the capacity to store approximately 12 billion cubic feet of natural gas and deliver up to 176,000 dekatherms per day by November 2009. Subject to obtaining all necessary approvals, construction is expected to begin in October 2005 with storage service commencing with initial injections in April 2007. Total project capital expenditures are estimated at $100 to $110 million. Columbia Gas Transmission Corporation, a subsidiary of NiSource, will serve as operator of the facilities.

     For additional information about our equity method investments, see Note 10 to the consolidated financial statements.

Environmental Matters We have developed an internal environmental self-assessment plan to assess our facilities and program areas for compliance with federal, state and local environmental regulations and to correct in a timely manner any deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with other responsible parties, work directly with the North Carolina Department of Environment and Natural Resources to set priorities for MGP site remediation. For additional information on environmental matters, see Note 12 to the consolidated financial statements.

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

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		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 engage in interstate natural gas storage, intrastate natural gas transportation and unregulated retail natural gas marketing. These companies have risks that are inherent in their industries and we assume such risks as an equity investor.

     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

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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 7A. 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 utility construction expenditures. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

     As of October 31, 2004, we had $109.5 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 2.18%. The carrying amount of our short-term debt approximates fair value. During 2004, such short-term debt ranged from zero to $174 million with interest rates from 1.39% to 2.25%. We had a commercial paper program that was put into place to provide for the temporary financing of our acquisitions of NCNG and the equity interest in EasternNC in 2003. In December 2003 and January 2004, the balance of the commercial paper was repaid from the net proceeds from issuing long-term debt and Common Stock and from internally generated cash, and the program was terminated.

     Information as of October 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 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

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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 7 of this Form 10-K.

Item 8. Financial Statements and Supplementary Data

     Consolidated financial statements and schedules required by this item are listed in Item 15 (a) 1 and (a) 2 in Part IV of this Form 10-K on page 71.

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Consolidated Balance Sheets
October 31, 2004 and 2003

Assets

See notes to consolidated financial statements.

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Capitalization and Liabilities

*Reflects a two-for-one stock split effective October 11, 2004. See Note 5.

See notes to consolidated financial statements.

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Consolidated Statements of Income
For the Years Ended October 31, 2004, 2003 and 2002

*Reflects a two-for-one stock split effective October 11, 2004. See Note 5.

See notes to consolidated financial statements.

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Consolidated Statements of Cash Flows
For the Years Ended October 31, 2004, 2003 and 2002

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