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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 [NO FEE REQUIRED]

     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 x No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. x

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). Yes x No o

     State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of April 30, 2003.

Common Stock, no par value - $1,233,063,624

     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 February 27, 2004, are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

2003 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 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 and propane 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 for $417.5 million in cash 100% of the common stock of North Carolina Natural Gas Corporation (NCNG) from Progress Energy, Inc. (Progress). NCNG, a natural gas distributor, served approximately 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. The purchase price for the NCNG common stock was increased by the amount of NCNG’s working capital on the closing date. Based on a preliminary working capital schedule, the closing date working capital was $32.4 million. The preliminary working capital amount will be adjusted in 2004 to actual under the terms of the purchase agreement. 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). Progress’ equity interest in EasternNC consisted of 50% of EasternNC’s outstanding common stock and 100% of EasternNC’s outstanding preferred stock. 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.

     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 comprise all of our other ventures. These operations are primarily conducted by Piedmont Intrastate Pipeline Company (Piedmont Intrastate), Piedmont Interstate Pipeline Company (Piedmont Interstate), Piedmont Energy Company (Piedmont Energy), Piedmont Propane Company (Piedmont Propane) and Piedmont Greenbrier Pipeline Company,

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LLC (Piedmont Greenbrier), through their investments in ventures accounted for under the equity method. All of these companies, except for Piedmont Greenbrier, are wholly owned subsidiaries of Piedmont Energy Partners, a holding company which is a wholly owned subsidiary of the parent company. Piedmont Greenbrier is a wholly owned subsidiary 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 a 104-mile 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 Greenbrier owns 33% of the membership interest in Greenbrier Pipeline Company, LLC (Greenbrier). Greenbrier proposed to build a 280-mile interstate gas pipeline. 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. Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P., which owns all of the general partnership interest and approximately 26% of the limited partnership interest in Heritage Propane Partners, L.P. (Heritage). Heritage is a marketer of propane through a nationwide retail distribution network.

     On November 6, 2003, Piedmont Greenbrier sold its interest in Greenbrier to Dominion Resources Inc., the other member in the venture, for its book value of $9.2 million. On November 7, 2003, we, along with the other members of US Propane, entered into an agreement to sell the general and limited partnership interests in Heritage to a third party for $130 million. Our share of the sale proceeds is expected to be $26.9 million. In connection with the sale, US Propane retained approximately 180,000 common units of Heritage for ultimate distribution to US Propane’s members. This transaction closed on January 20, 2004.

     Operations by segment for the years ended October 31, 2003, 2002 and 2001, 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, 2003, 43% of our operating revenues were from residential customers, 25% from commercial customers, 9% from industrial and power generation customers, 22% from secondary market activity and 1% from various other sources. Revenues, less related costs, from the non-utility activities segment and earnings from equity investments are shown in “Other Income (Expense)” in the consolidated statements of income in “Non-operating income” or “Non-utility activities, at equity,” respectively. For further information on equity investments and 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 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

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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 hold non-exclusive franchises for natural gas service in the communities we serve, with expiration dates from 2004 to 2053. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. As of October 31, 2003, three franchises have expired; however, we continue to operate in those areas 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, 2003, the amount of natural gas in storage varied from 3.1 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 22.3 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $14.1 million to $113.4 million.

     During the year ended October 31, 2003, 62.4 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 60.1 million dekatherms in 2002. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 86 million dekatherms in 2003, compared with 65.9 million dekatherms in 2002. Weather, as measured by degree days, was 3% colder than normal in 2003 and 15% warmer than normal in 2002.

     The following is a five-year comparison of operating statistics for the years ended October 31, 1999 through 2003:

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     As of October 31, 2003, 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 30 million dekatherms of storage capacity, either in the 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, 2003, 36% of our gas deliveries were made 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. The 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 existing regulations of the Federal Energy Regulatory Commission (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. To date, only

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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 the customers’ 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. 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 consumers’ preference is for natural gas based on such factors as reliability, comfort and convenience compared with electricity in space heating, hot water and cooking. In addition to its many advantages, natural gas has generally maintained a price advantage over electricity in our service areas; however, with the rising demand for natural gas, flat to declining production levels and other public policy issues primarily associated with access to public lands for drilling, upward pressure on the price of natural gas could be more of an issue in the future. Rising prices can impact our competitive position by decreasing the price benefits of natural gas to the end user.

     In the interruptible industrial market, the regulated utility’s customers are capable of burning a fuel other than natural gas. Fuel oil is the most significant competing energy alternative. Our ability to maintain our 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 reduction in natural gas production occurring from domestic sources, the cost of natural gas from non-domestic sources may play a greater role in our competitive position in the future. 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, 2003, our largest customer contributed $1.8 million, or .2%, to total operating revenues.

     We spend an immaterial amount for research and development costs. We contribute to gas industry-sponsored research projects; however, the amounts contributed to such projects are not material.

     Compliance with federal, state and local environmental protection laws has 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.

     As of October 31, 2003, we had 2,155 employees, compared with 1,715 as of October 31, 2002. The increase is primarily due to the acquisitions of NCNG and an equity interest in EasternNC.

     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.

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Item 2. Properties

     All property shown in the consolidated balance sheets in “Utility Plant” is owned by Piedmont and 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 the majority (73%) invested in distribution and transmission plant to serve our customers. We have approximately 2,250 miles of lateral pipelines up to 16 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. We distribute natural gas through approximately 22,830 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.

     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 $.8 million for the year ended October 31, 2003.

     “Other Physical Property” in the consolidated balance sheets is owned by the parent company with the majority (76%) comprised of residential and commercial water heaters leased to customers.

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     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. We do not expect any material impact on 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 the fourth quarter of our fiscal year ended October 31, 2003.

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PART II

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

     (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, 2003 and 2002.

     (b)  As of January 15, 2004, our Common Stock was owned by 16,391 shareholders of record.

     (c)  Information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2003 and 2002, is as follows:

     The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in our 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, 2003, net earnings available for restricted payments were greater than retained earnings; therefore, none of our retained earnings were restricted.

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Item 6. Selected Financial Data

     Selected financial data for the years ended October 31, 1999 through 2003, is as follows:

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

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 North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (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 Federal Energy Regulatory Commission (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.

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	•		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.
	•		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 and propane 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

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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.

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 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 and propane 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 January 1, 2001, we purchased for cash the natural gas distribution assets of Atmos Energy Corporation located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition was at book value of $6.6 million and added 5,400 customers to our operations.

     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 North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc. The initial purchase price was reduced by $2.2 million in 2003 due to adjusting estimated working capital to actual. Final determination of the purchase price allocation resulted in recording goodwill of $7.1 million. 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 for $417.5 million in cash 100% of the common stock of NCNG from Progress. NCNG, a natural gas distributor, served approximately 176,000 customers in eastern North Carolina, including 57,000 customers served by four municipalities who were wholesale customers of NCNG. The purchase price for the NCNG common stock was increased by the amount of NCNG’s working capital on the closing date. Based on a preliminary working capital schedule, the closing date working capital was $32.4 million. The preliminary working capital amount will be adjusted to actual under the terms of the purchase agreement in 2004. 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

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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.

     The primary reasons for these acquisitions are consistent with our strategy of pursuing profitable growth in our core natural gas distribution business in the Southeast. The reasons for the acquisitions and the factors that contributed to the goodwill include:

	•		A reasonable purchase price slightly above book value,
	•		The prospect of entering a market contiguous to our existing North Carolina service areas where, as a combined company, we could realize on-going system benefits,
	•		The prospect of acquiring an operation that could be integrated into our existing business systems and processes, and
	•		The opportunity to grow within a regulatory environment with which we are familiar.

     We have two reportable business segments, regulated utility and non-utility activities. For further information on segments, see Note 11 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 “Results of Operations” below and Notes 3 and 6 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 area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.

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Financial Condition and Liquidity

     We finance current cash requirements primarily from operating cash flows and short-term borrowings. During 2003, outstanding short-term borrowings under committed bank lines of credit totaling $200 million ranged from zero to $114.5 million, and interest rates ranged from 1.1903% to 2.04%. As of October 31, 2003, we had additional uncommitted lines of credit totaling $68 million on a no fee and as needed, if available, basis. As of October 31, 2003, our current assets of $307.6 million were less than our current liabilities of $725.2 million primarily due to the short-term financing of the acquisitions of NCNG and an equity interest in EasternNC with commercial paper of $445.3 million. On December 19, 2003, we redeemed $198.3 million of the commercial paper with the net proceeds from the sale of $200 million of medium-term notes. See subsequent events update in Note 13 to our consolidated financial statements in Item 8.

     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 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 2003, 56% of our sales and transportation revenues were from residential customers and 32% 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 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 2003 was 3% colder than normal, compared with 15% warmer than normal in 2002 and 8% colder than normal in 2001. The WNA generated credits to customers of $10.2 million in 2003, charges to customers of $19.8 million in 2002 and credits to customers of $8.5 million in 2001. 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 purchased gas cost recovery mechanisms and is not affected by the WNA.

     The regulated utility faces competition in the residential and commercial customer markets based on the customers’ 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 could 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 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

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future. 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. 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 bills.

     We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. During 2003, we issued $17.9 million of common stock through dividend reinvestment and stock purchase plans but none on the open market. We did not sell any long-term debt during fiscal 2003; however, we did retire $45 million of 6.23% medium-term notes at the scheduled maturity date and made a sinking fund payment of $2 million on the 10.06% senior notes. As noted above, in December 2003 we sold $200 million of long-term debt and redeemed commercial paper issued in connection with funding the acquisitions of NCNG and an equity interest in EasternNC.

     As of October 31, 2003, our capitalization consisted of 42% in long-term debt and 58% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

     As of October 31, 2003, 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
	•		Contingencies.

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                 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 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 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 October 31, 2003.

                 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 increased from October 31, 2002 to October 31, 2003, and accounts payable and accounts receivable increased during this same period due to seasonality, higher gas prices, the growth of our business 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. Utility construction expenditures in 2003 were $80.3 million, compared with $83.7 million in 2002. Utility construction expenditures totaling $103.8 million, primarily to serve customer growth, are budgeted for 2004. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue. Short-term debt may be used to finance construction pending the issuance of long-term debt or equity.

                 As of October 31, 2003, our estimated future contractual obligations for long-term debt, purchase obligations and capital and operating leases were as follows:

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*Purchase obligations consist of pipeline and storage capacity and gas supply contracts that are 100% recoverable through purchased gas cost recovery mechanisms.

Off-balance Sheet Arrangements

     We have no material off-balance sheet arrangements other than operating leases that are discussed in Note 7 to the consolidated financial statements.

Critical Accounting Policies and Estimates

     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.

     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” (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 income in the balance sheet as regulatory assets and liabilities when those expenses and income will be allowed in the rate-setting 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.

     We believe the following represents the more significant judgments and estimates used in preparing the consolidated financial statements.

Unbilled Utility Revenues. We record estimated revenues for volumes delivered but not yet billed at month end due to reading meters and billing on a cycle basis. The estimated revenues

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are calculated based on estimated volumes delivered but unbilled at month end and the billing rates applicable to those volumes, adjusted for any estimated billing impacts of the WNA in the appropriate months. For further information on operating revenues, see Note 1.H to the consolidated financial statements.

Allowance for Uncollectible Accounts. We evaluate the collectibility of our billed accounts receivable based on recent loss history and an overall assessment of past due accounts receivable amounts outstanding.

Employee Benefits. We have a defined-benefit pension plan for the benefit of eligible full-time employees. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to the plan. These factors include assumptions about the discount rate, expected 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 the projected benefit obligation. 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 recorded in future periods.

Self Insurance. We are self-insured for certain losses related to general liability, group medical benefits and workers’ compensation. We maintain stop loss coverage with third-party insurers to limit our total exposure. Our recorded liabilities represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. Along with independent actuaries, we review the liabilities at least annually to ensure that they are appropriate. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from our estimates.

Long-Term Incentive Plan. We have a Long-Term Incentive Plan (LTIP) under which units, equivalent in value to one share of common stock, are awarded to participants. Through October 31, 2003, the performance period was a five-year period; however, effective November 1, 2003, the performance period is a three-year period. Following the end of the performance period and if performance measures are met, awards are distributed in the form of shares of common stock and cash withheld to pay taxes. During the performance period, we calculate the expense and liability for the LTIP based on performance levels achieved or expected to be achieved and the estimated market value of common stock as of the distribution date. While we believe these estimates are reasonable based on the information available, actual amounts, which are not known until after the end of the performance period, could differ from our estimates.

Gas Supply and Regulatory Proceedings

               To meet customer requirements, we acquire gas supplies and pipeline capacity to ensure delivery to meet the demands of our distribution system, while also ensuring that supply and capacity contracts allow us to remain competitive. 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.

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               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. 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 the on-shore and off-shore Gulf Coast production region and is purchased primarily from major producers and marketers.

               In our opinion, present rules and regulations of our three state regulatory commissions permit the pass-through of interstate pipeline capacity and storage service costs that may be incurred under orders or regulations of the FERC, as well as commodity gas costs from natural gas suppliers. The majority of our natural gas supply is purchased from producers and marketers in non-regulated transactions. Our rate schedules include provisions permitting the recovery of prudently incurred gas costs. The NCUC and the PSCSC require annual prudence reviews covering historical twelve-month periods. For the most recent periods, the NCUC and the PSCSC found us to be prudent in our gas purchasing practices and allowed recovery of 100% of our gas costs.

               In 1996, the TRA approved a performance incentive plan that eliminated annual prudence reviews in Tennessee and established an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark amounts determined by published market indices. These differences, after applying a monthly 1% positive or negative deadband, together with margin from marketing unused capacity in the secondary market and margin from secondary market sales of gas, are subject to an overall annual cap of $1.6 million for shareholder gains or losses. The net gains or losses on gas costs within the deadband (99% to 101% of the benchmark) are not subject to sharing under the plan and are allocated to customers. Any net gains or losses on gas costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders, subject to the annual cap. The net overall annual performance results are collected from or refunded to customers, subject to the cap. In addition to the elimination of annual gas purchase prudence reviews, the benefits of the incentive plan include the reduction of gas costs for customers and potential earnings to shareholders by sharing in gas cost reductions. Initially approved for a two-year period, the plan now continues on a year-to-year basis each July 1 until we notify the TRA of termination 90 days before the end of a plan year or until the plan is modified, amended or terminated by the TRA.

               In 1996, the NCUC ordered us to establish an expansion fund to enable the extension of natural gas service into unserved areas of the state. The expansion fund was funded with supplier refunds, plus investment income earned, that would otherwise be refunded to customers. In accordance with an NCUC order in 2002, we no longer deposit such refunds in the expansion fund. As of October 31, 2003, the balance of $6.1 million in our expansion fund held by the state is included in “Restricted cash” with an offsetting liability included in “Refunds due customers” in the consolidated balance sheets.

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               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 was granted $188.3 million of the $200 million state bond package to pay for the uneconomic portion of the infrastructure to construct a pipeline and distribution system of approximately 800 miles. The economic portion of the project was estimated to cost $22.1 million. As of October 31, 2003, EasternNC had received $101 million from bond funds and had recorded a bond reimbursement receivable of $2.6 million.

               In 2002, the PSCSC approved a gas cost hedging plan for the purpose of cost stabilization for customers. This plan is limited to 60% of our annual normalized sales volumes for South Carolina and operates off of historical pricing indices that are tied to future projected gas prices as traded on a national exchange. All properly accounted for costs incurred in accordance with the plan, except for certain personnel and administrative costs that are recovered in rates as operations and maintenance expenses, are deemed to be prudently incurred and are recovered in rates as a gas cost. We began hedging activities in April 2002 under the approved program.

               Effective November 1, 2002, we implemented a hedging program in North Carolina under the terms of a generic order issued by the NCUC on February 26, 2002, as later clarified by a Piedmont-specific order dated October 18. This plan is limited to 60% of the annual normalized sales volumes for North Carolina and operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange. We believe the plan is designed with limited subjective discretion in making purchases with little or no risk of speculation in the market. Prudently incurred gas costs associated with the hedging program are not pre-approved by the NCUC but are treated as gas costs subject to the annual gas cost prudency review based on information available at the time of the hedge, not at the time of the prudency review. Through October 31, 2003, we have recovered 100% of gas costs subject to prudency review.

               On October 28, 2002, the NCUC issued an order approving an annual revenue increase of $13.9 million, effective November 1, 2002. This order also approved changes in cost allocations and rate design and changes in tariffs and service regulations.

               On October 29, 2002, the PSCSC issued an order approving an annual revenue increase of $8.4 million, effective November 1, 2002. This order also approved new depreciation rates and changes in cost allocations and rate design and changes in tariffs and service regulations.

               On March 31, 2003, NCNG filed an application with the NCUC requesting an increase in rates and charges along with changes in cost allocations and rate design and changes in tariffs and service regulations. On September 2, a settlement agreement supported by all parties in the proceeding was filed with the NCUC. The agreement provided for, among other things, an annual increase in NCNG’s regulatory margin of $29.4 million. The NCUC issued an order in accordance with the agreement on October 30, effective November 1, 2003.

               On April 29, 2003, we filed an application with the TRA requesting an annual increase in revenues along with changes in cost allocations and rate design and changes in tariffs and service regulations. On September 9, a settlement agreement with the Tennessee Consumer Advocate was filed with the TRA that, among other things, increased revenues by $10.3 million annually. On September 22, the TRA approved the settlement agreement and authorized us to increase rates, effective November 1, 2003.

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               On October 27, 2003, we filed a joint motion for clarification of the right of EasternNC to defer and collect its operations and maintenance expenses under prior NCUC orders. As part of EasternNC’s certificate authorization, the NCUC recognized that EasternNC would not have a sufficient customer base from which to immediately collect its operations and maintenance expenses. The NCUC allowed EasternNC to defer its operations and maintenance expenses for up to eight years or until the first rate case order. The NCUC set the cap on deferred expenses at $15 million. On December 1, 2003, the NCUC confirmed that these deferred expenses should be treated as a regulatory asset for future recovery from customers to the extent they are deemed prudent and proper. Operations and maintenance costs totaling $2.9 million, including those expensed prior to September 30, 2003, have been deferred as a regulatory asset.

               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, a sharing mechanism is in effect where 75% of any margin earned is refunded to customers. In connection with the South Carolina rate case noted above, this same sharing mechanism is in place in South Carolina effective November 1, 2002. Secondary market transactions in Tennessee are included in the performance incentive plan discussed above.

               In 2003, 36% of gas deliveries were made to industrial or large commercial customers which 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. The 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 existing 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 directly from the pipeline or from a third party connecting with the pipeline. To date, 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.

               In 2001, we requested special accounting treatment from the NCUC, the PSCSC and the TRA to allow us to defer for recovery in future rates the amounts of accounts receivable that were written off as uncollectible during 2001 in excess of amounts recovered through base rates. These higher write-offs resulted from the high gas prices and abnormally cold weather experienced during the 2000-2001 winter season. The PSCSC and the TRA approved deferral of only the gas cost portion of the excess write-offs, which totaled $1.3 million, for recovery under normal purchased gas cost adjustment (PGA) procedures. The NCUC did not approve our request.

               On March 17, 2003, we, along with other natural gas companies in Tennessee, filed a petition with the TRA to allow recovery of the gas cost portion of uncollectible accounts expense in excess of those allowed currently in rates under normal PGA procedures. A ruling is expected in early 2004. The outcome of this proceeding cannot be determined at this time.

Equity Investments

               The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary of Piedmont

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Natural Gas Company. Another wholly owned subsidiary of Piedmont Natural Gas Company, Piedmont Energy Partners, Inc., is a holding company for certain other wholly owned subsidiaries. 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.

               As of October 31, 2003, the amount of our retained earnings that represents undistributed earnings of 50% or less owned entities accounted for by the equity method was $23.1 million.

               Piedmont Intrastate Pipeline Company owns 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. With the acquisition of NCNG, we acquired an additional 5.03% interest in Cardinal over our previous interest of 16.45%. The other members are subsidiaries of The Williams Companies, Inc., and SCANA Corporation. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with local distribution companies, including Piedmont, for 100% of the 270,000 dekatherms per day of firm transportation capacity on the pipeline. Cardinal is dependent on the Williams-Transco pipeline system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is secured by Cardinal’s assets and by each member’s equity investment in Cardinal. In accordance with the NCUC’s order authorizing Cardinal to construct, own and operate the pipeline, Cardinal filed a general rate case in January 2003. On July 24, 2003, the NCUC decreased Cardinal’s revenues by $1.6 million annually, effective August 1, 2003.

               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. With the acquisition of NCNG, we acquired an additional 5.0587% interest in Pine Needle over our previous interest of 35%. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Amerada Hess Corporation, and the Municipal Gas Authority of Georgia. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the FERC. Storage capacity of the facility is 4.14 million dekatherms with vaporization capability of 414,000 dekatherms per day and is fully subscribed under firm service agreements with customers. We subscribe to approximately 64% of this capacity to provide gas for peak-use periods when demand is the highest. Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133). Pine Needle’s long-term debt is secured by Pine Needle’s assets and by each member’s equity investment in Pine Needle. On January 15, 2003, a stipulation agreement was filed with the FERC that reduced Pine Needle’s annual rate of return from 9.8% to 9.7%. New lower rates were effective May 1, 2003.

               Piedmont Propane Company owns 20.69% of the membership interests in US Propane, L.P. The other members are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns 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. Heritage Propane utilizes hedging transactions to provide protection against significant fluctuations in prices. Movements in the mark-to-market value of these agreements are recorded in “Accumulated other comprehensive income” in the consolidated balance sheets as a hedge

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under Statement 133 and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement 149). Heritage Propane also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments utilized in connection with the liquids marketing activity are accounted for using the mark-to-market method of accounting.

               In July 2002, we recorded a pre-tax loss in value of $1.4 million on our investment in US Propane due to an other than temporary decline in the value of the general partnership interest in Heritage Propane. This other than temporary loss was calculated based on estimated future cash flow projections that reflect actual and projected customer growth assumptions for Heritage Propane.

               The limited partnership agreement of US Propane requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $10 million. As of October 31, 2003, our capital account was positive.

               On November 7, 2003, we, along with the other members of US Propane, entered into an agreement to sell the general and limited partnership interests in Heritage Propane to a third party for $130 million. Our share of the sales proceeds is expected to be $26.9 million. In connection with the sale, US Propane will retain approximately 180,000 common units of Heritage Propane for ultimate distribution to US Propane’s members. This transaction closed on January 20, 2004. We estimate that we will record a one-time gain on the transaction of approximately $.03 to $.05 per diluted share in fiscal year 2004. See subsequent events update in Note 13 to the consolidated financial statements in Item 8.

               Piedmont Energy Company owns 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. The remaining non-controlling 70% interest is owned by a subsidiary of AGL Resources, Inc. Key governance provisions in the LLC agreement require unanimous approval of the members. 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%. This threshold is not reached until all prior period losses are recovered. Earnings below the 17% return threshold are allocated to members based on their ownership percentages. Earnings above the threshold are allocated at various percentages based on actual margin generated in four defined geographic service areas. The earnings test is based on SouthStar’s fiscal year ending December 31. As of October 31, 2003 and 2002, we recognized as equity earnings only the amounts that we believe have 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. Accordingly, we recorded pre-tax earnings from SouthStar for the years ended October 31, 2003 and 2002, at overall percentages of 20% and 24%, respectively.

               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 estimate that we will record an increase in pre-tax earnings from

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SouthStar of $2.5 million in the first quarter of our fiscal year 2004.

               SouthStar utilizes financial contracts to hedge the variable cash flows associated with changes in the price of natural gas. These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Those derivative transactions that qualify as cash flow hedges are reflected in SouthStar’s balance sheet at the fair values of the open positions, with the corresponding unrealized gain or loss included in “Accumulated other comprehensive income” under Statement 133 and Statement 149. Those derivative transactions that are not designated as hedges are reflected in SouthStar’s balance sheet with the corresponding unrealized gain or loss included in cost of sales in SouthStar’s income statement. SouthStar does not enter into or hold derivatives for trading or speculative purposes. SouthStar also enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. These contracts are accounted for using the intrinsic value method under the guidelines of Emerging Issues Task Force Issue No. 99-2, “Accounting for Weather Derivatives.”

               Atlanta Gas Light Company (AGLC), under the terms of its tariffs with the Georgia Public Service Commission, has required SouthStar’s members to guarantee SouthStar’s ability to pay AGLC’s fees for local delivery service. Piedmont Energy Company, through its parent Piedmont Energy Partners, has guaranteed its 30% share of South Star’s obligation with AGLC with a letter of credit with a bank in the amount of $15 million that expires on July 30, 2004. On November 25, 2003, Piedmont Energy Company increased its guarantee with an additional letter of credit of $3.1 million that expires on August 4, 2004.

               As of October 31, 2003, Piedmont Greenbrier Pipeline Company, LLC, 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 280-mile 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.

Results of Operations

               Net income in 2003 was $74.4 million, $62.2 million in 2002 and $65.5 million in 2001. The net income increase of $12.2 million in 2003 compared with 2002 was primarily due to the following:

	•		Increase of $28.5 million due to an increase in margin (operating revenues less cost of gas).
	•		Decrease of $11.3 million due to an increase in operations and maintenance expenses.
	•		Decrease of $3.4 million due to an increase in depreciation expense.

          The net income decrease of $3.3 million in 2002 compared with 2001 was primarily due to the following:

	•		Decrease of $1.3 million due to a decrease in margin.
	•		Decrease of $3.3 million due to an increase in depreciation expense.
	•		Increase of $1.8 million due to an increase in earnings from non-utility activities, at equity.

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               Compared with the prior year, weather in our service area, as measured by degree days, was 21% colder in 2003, 21% warmer in 2002 and 23% colder in 2001. Volumes of gas delivered to customers (system throughput) were 149.1 million dekatherms in 2003, compared with 126.1 million dekatherms in 2002, an increase of 18%, and 134.4 million dekatherms in 2001. In addition to system throughput, secondary market sales volumes were 45.9 million dekatherms in 2003, compared with 55.7 million dekatherms in 2002 and 29.5 million dekatherms in 2001.

               Operating revenues were $1,220.8 million in 2003, $832 million in 2002 and $1,107.9 million in 2001. Operating revenues in 2003 increased $388.8 million compared with 2002 primarily due to the following increases:

	•		$98.3 million from increased volumes billed due to colder weather and growth in our customer base, including $16.2 million from NCGS. Billed volumes increased 16.4 million dekatherms primarily due to 21% colder weather.
	•		$143.7 million due to increased wholesale gas prices.
	•		$99.6 million from secondary market activity.
	•		$31.9 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed. See Note 1.H 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 volumes billed to NCNG customers.

These increases were partially offset by $10.2 million in credits to customers from the WNA in 2003, compared with surcharges of $19.8 million in 2002, a net decrease in operating revenues of $30 million. As discussed above, 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.

               Operating revenues in 2002 decreased $275.9 million compared with 2001 primarily due to the following decreases:

	•		$275.3 million as a result of a decrease of 12.9 million dekatherms delivered to weather-sensitive residential and commercial customers due to warmer weather.
	•		Significant decreases in the wholesale commodity cost of gas resulting in a corresponding decrease in rates charged to customers as substantially all changes in gas prices are passed through to customers.

These decreases were partially offset by an increase of $27.9 million from secondary market activity.

               In general rate proceedings, the state regulatory commissions have authorized us to recover a margin, applicable rate less cost of gas, on each unit of gas sold. The commissions have also authorized us to negotiate lower rates to industrial customers when necessary to remain competitive and to recover margin losses resulting from these negotiated transactions. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.

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               Cost of gas was $837.9 million in 2003, $496.2 million in 2002 and $769.9 million in 2001. Cost of gas in 2003 increased $341.7 million compared with 2002 primarily due to the following increases:

	•		$143.7 million due to increases in the wholesale commodity cost of gas from suppliers.
	•		$56.9 million due to an increase in system throughput, including $10.4 million from NCGS.
	•		$99 million due to an increase in secondary market activity.
	•		$22.8 million due to a change in the way we record revenues and cost of gas related to volumes delivered but not yet billed.
	•		$13.3 million from the acquisitions of NCNG and an equity interest in EasternNC.

              Cost of gas in 2002 decreased $273.7 million compared with 2001 primarily due to significant decreases in the wholesale commodity cost of gas and a decrease in volumes delivered to weather-sensitive residential and commercial customers due to warmer weather.

              Margin was $382.9 million in 2003, $335.8 million in 2002 and $338 million in 2001. The margin increase of $47.1 million in 2003 compared with 2002 was primarily due to the following increases:

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

These increases to margin were partially offset by a decrease of $30 million due to WNA credits to customers in 2003 compared with charges to customers in 2002.

               The margin decrease of $2.2 million in 2002 compared with 2001 was primarily due to the following:

	•		$9.2 million decrease due to warmer weather resulting in a decrease of 12.9 million dekatherms to weather sensitive residential and commercial customers despite customer growth.
	•		$2.2 million increase due to an increase of 4.1 million dekatherms to industrial customers.
	•		$4.1 million increase due to the allocation of gas costs between jurisdictions.

               Operations and maintenance expenses were $152.1 million in 2003, $133.4 million in 2002 and $133.4 million in 2001. The operations and maintenance expenses increase of $18.7 million in 2003 compared with 2002 was 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.

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	•		$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 as 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.

               Operations and maintenance expenses were even in 2002 and 2001; however, the following increases and decreases in 2002 compared with 2001 were experienced:

	•		$5.1 million increase in payroll costs due to merit increases, accrual of the long-term incentive plan and positions being filled by employees rather than by outside contractors.
	•		$1.4 million increase in employee benefits costs due to pension expense in 2002 compared with pension income in 2001 and increased health insurance premiums.
	•		$2 million decrease in outside labor partially offset by payroll costs as noted above.
	•		$5 million decrease in the provision for uncollectibles due to improved charge-off experience in 2002 due to warmer weather and lower gas prices.

               Depreciation expense increased from $52.1 million to $63.2 million over the three-year period 2001 to 2003 primarily due to increases in plant in service, including one month of depreciation expense in 2003 on plant acquired from NCNG. Due to the continued growth in our service areas and our commitment to capital expansion and a full year of depreciation expense in 2004 on plant acquired from NCNG, we anticipate that depreciation expense will continue to increase.

               General taxes were $24.4 million in 2003, $23.9 million in 2002 and $24 million in 2001.

               Other income (expense), net of income taxes, was $12.3 million in 2003, $12.7 million in 2002 and $10.9 million in 2001. Income from non-utility activities, at equity, decreased $1.2 million in 2003 compared with 2002 primarily due to a decrease of $4.1 million in earnings from SouthStar’s operations, partially offset by an increase of $3.1 million in earnings from propane operations. Income from non-utility activities, at equity, increased $2.9 million in 2002 compared with 2001 primarily due to an increase of $5.9 million in earnings from SouthStar’s operations, partially offset by a decrease of $2.7 million in earnings from propane operations primarily due to the impact of warmer weather.

               The equity portion of the allowance for funds used during construction (AFUDC), was $1.1 million in 2003, $2 million in 2002 and $1.8 million in 2001. 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, jobbing and compressed natural gas operations, the non-equity portion of activities of the subsidiaries, interest income and other miscellaneous income. Non-operating income was $2.6 million in 2003, $1.2 million in 2002 and $1.1 million in 2001.

               Non-operating expense is comprised of charitable contributions and other miscellaneous

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expenses. Non-operating expense was $.9 million in 2003, $.7 million in 2002 and $.9 million in 2001.

               Utility interest charges were $40.2 million in 2003, $40.6 million in 2002 and $39.4 million in 2001. Utility interest charges decreased $.4 million in 2003 compared with 2002 primarily due to the following decreases:

	•		$1 million in interest on long-term debt due to lower balances outstanding.
	•		$1 million in interest on refunds due customers due to lower balances outstanding.

These decreases were partially offset by an increase of $1.2 million in interest on short-term debt, primarily due to commercial paper issued to temporarily finance the acquisitions of NCNG and an equity interest in EasternNC.

               Utility interest charges increased $1.2 million in 2002 compared with 2001 primarily due to the following:

	•		$1.3 million increase in interest on long-term debt due to higher balances outstanding.
	•		$3.5 million decrease in the portion of AFUDC attributable to borrowed funds.

These increases in utility interest charges were partially offset by the following:

	•		$2.7 million decrease in interest on short-term debt due to lower balances outstanding at lower interest rates.
	•		$.9 million decrease in interest on refunds due customers due to lower balances outstanding.

Environmental Matters

               Our three state regulatory commissions have authorized us to utilize deferral accounting, or to create a regulatory asset, in connection with environmental costs. Accordingly, we have established regulatory assets for environmental costs incurred and for estimated environmental liabilities.

               In 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid an amount that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. Three other MGP sites that we also have owned, leased or operated were not included in the settlement.

               In 2002, in connection with the acquisition of certain assets and liabilities of NCGS, we acquired the liability for potential remediation costs of an MGP site located in Reidsville, North Carolina. Based on a limited assessment performed by a third party on this site and its similarity to the three sites not covered by the settlement noted above, we increased our environmental liability in the fourth quarter of 2002 by $1.5 million, with an offsetting increase to a regulatory asset, to reflect a liability of $.6 million for each of the four sites.

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               As of October 31, 2003, our undiscounted environmental liability totaled $2.9 million, consisting of $2.6 million for the four MGP sites and $.3 million for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries.

               As of October 31, 2003, our regulatory assets for environmental costs totaled $5.4 million, net of recoveries from customers, in connection with the estimated liabilities for the MGP sites and underground storage tanks and for environmental costs incurred, primarily legal fees and engineering assessments. The portion of the regulatory assets representing actual costs incurred is being amortized as recovered in rates from customers in all three states.

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

               In connection with the NCNG general rate case proceeding discussed in Note 3 to the consolidated financial statements, the NCUC ordered an environmental regulatory liability of $3.5 million be established for refund to customers over the three-year period beginning November 1, 2003. This liability was derived from deducting deferred MGP costs from a prior payment made to NCNG by its insurers.

Recently Issued Accounting Standards

               We will adopt FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), in our second quarter ending April 30, 2004. We believe that FIN 46 applies to our equity investments, all of which were acquired prior to February 1, 2003. We have evaluated the impact of FIN 46 on our equity method investments and concluded that we are not the primary beneficiary as we do not absorb a majority of the expected losses nor are we entitled to a majority of the residual returns. Accordingly, we believe the adoption of FIN 46 will not have a material effect on financial position or results of operations.

               In December 2003, the FASB 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. We believe the adoption of Statement 132 will not have a material effect on financial position or results of operations.

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 investments in capital projects. Future short-term

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interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

               As of October 31, 2003, we had $109.5 million of short-term debt outstanding under committed bank lines of credit at a weighted average interest rate of 1.58%. During 2003, such short-term debt ranged from zero to $114.5 million. As of October 31, 2003, we also had outstanding borrowings of $445.6 million under a commercial paper program at a weighted average interest rate of 1.16%. The carrying amount of our short-term debt approximates fair value.

               Information as of October 31, 2003, about our long-term debt that is sensitive to changes in interest rates is presented below.