Back to GetFilings.com

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-K

Piedmont Natural Gas Company, Inc.
(Exact name of registrant as specified in its charter)

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

     State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of January 13, 2003.

Common Stock, no par value — $1,160,769,792

     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 28, 2003, are incorporated by reference into Part III.

Piedmont Natural Gas Company, Inc.

2002 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

PART I

Item 1. Business

     Piedmont Natural Gas Company, Inc., incorporated in 1950, is an energy services company primarily engaged in the distribution of natural gas to 740,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. We are the second-largest natural gas utility in the Southeast. Piedmont is also invested in a number of non-utility, energy-related businesses, including companies involved in unregulated retail natural gas and propane marketing and interstate and intrastate natural gas storage and transportation. 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, Spartanburg and Gaffney in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine and Reidsville in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville.

     We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Based on products and services and regulatory environments, operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company, Piedmont Interstate Pipeline Company and Piedmont Greenbrier Pipeline Company through their investments in ventures accounted for under the equity method. Piedmont Intrastate is a 16.45% member of Cardinal Pipeline Company, L.L.C., which owns and operates a 104-mile intrastate natural gas pipeline in North Carolina. Piedmont Interstate is a 35% member of Pine Needle LNG Company, L.L.C., which owns a liquefied natural gas (LNG) storage facility in North Carolina. Piedmont Greenbrier Pipeline has a 33% equity interest in Greenbrier Pipeline Company, LLC, which proposes to build a 280-mile interstate gas pipeline originating in West Virginia and extending through Virginia to North Carolina. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company through its 30% interest in SouthStar Energy Services LLC, accounted for under the equity method. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States.

     Our propane activities are conducted by Piedmont Propane Company through its ownership of 20.69% of the membership interest in US Propane, L.P., accounted for under the equity method. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P.

1

     Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. 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. Operating revenues for the year ended October 31, 2002, totaled $832 million, of which 43% was from residential customers, 23% from commercial customers, 12% from industrial and power generation customers, 21% from secondary market activity and 1% from various other sources. Revenues from non-utility operations, less related costs, are shown in “Other Income (Expense)” in the statements of consolidated income in “Non-utility activities, at equity” or “Other.” For further information on equity investments and segments, see Notes 9 and 10 to the consolidated financial statements beginning on page 50 in Item 8 of this report.

     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. We are also subject to or affected by various federal and state regulations.

     We hold non-exclusive franchises for natural gas service in more than 90 communities we serve, with expiration dates from 2003 to 2050. The franchises are adequate for the operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. Two franchises that expired in 2000 and one franchise that expired in 2002 are currently being negotiated; however, we continue to operate in those areas with no significant impact on our business. We believe that these franchises will be renewed with no material adverse impact on us. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action. In most cases, the loss of a franchise would not have a material effect on operations.

     Our utility business is seasonal in nature as variations in weather conditions generally result in greater revenues and earnings during the winter months. We normally inject natural gas into storage during summer months (principally April 1 through October 31) for withdrawal from storage during winter months (principally November 1 through March 31) when customer demand is higher. During the year ended October 31, 2002, the amount of natural gas in storage varied from 4.9 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 22.2 million dekatherms, and the aggregate commodity cost of this gas in

2

storage varied from $17.2 million to $91.7 million.

     The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1998 through 2002:

3

     During the year ended October 31, 2002, 60.1 million dekatherms of gas were sold to or transported for large industrial and power generation customers, compared with 55.5 million dekatherms in 2001. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 65.9 million dekatherms in 2002, compared with 78.9 million dekatherms in 2001. Weather, as measured by degree days, was 15% warmer than normal in 2002 and 8% colder than normal in 2001.

     As of November 1, 2002, we have contracted for the following pipeline firm transportation capacity in dekatherms of daily deliverability:

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

     We own or have under contract 25.3 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.

     We utilize a “best cost” gas purchasing philosophy that seeks to purchase gas on a portfolio basis by weighing cost against supply security and reliability factors. For further information on gas supply and regulation, see “Gas Supply and

4

Regulatory Proceedings” beginning on page 16 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     During the year ended October 31, 2002, 35% 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 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 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 the residential and small commercial markets, natural gas competes primarily with electricity for such uses as cooking, water heating and space heating.

     During the year ended October 31, 2002, our largest customer contributed $1.7 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” beginning on page 28 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     At October 31, 2002, we had 1,715 employees, compared with 1,657 at October 31, 2001.

5

Item 2. Properties

     Our properties consist primarily of distribution systems and related facilities to serve our utility customers. We have approximately 670 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 20,500 miles (three-inch equivalent) of distribution mains. The lateral pipelines and distribution mains are located on or under public streets and highways, or private property with the permission of the individual owners.

     We own or lease for varying periods district and regional offices for our operations.

Item 3. Legal Proceedings

     There are a number of lawsuits pending against us in the ordinary course of business for damages alleged to have been caused by our employees. We have liability insurance which we believe is adequate to cover any material judgments that may result from these lawsuits.

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

     None.

6

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

     (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, 2002 and 2001.

     (b)  At January 13, 2003, our Common Stock was owned by 16,186 shareholders of record.

     (c)  Information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2002 and 2001, is as follows:

     The amount of cash dividends that may be paid on Common Stock is restricted by provisions contained in our articles of incorporation and in note agreements under which long-term debt was issued. At October 31, 2002, all retained earnings were free of such restrictions.

7

Item 6. Selected Financial Data

     Selected financial data for the years ended October 31, 1998 through 2002 is as follows:

*     The results for 2000 were impacted by the contribution of substantially all of Piedmont Propane Company’s assets in exchange for a partnership interest in Heritage Propane Partners, L.P. This transaction resulted in $5.1 million in net income, or earnings per share of $.16.

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. Such 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 condition of service, rate structures and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are

8

			regulated by the Federal Energy Regulatory Commission (FERC) and the North Carolina Utilities Commission (NCUC), respectively.
	•		Residential, commercial and industrial growth in our service territories. 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 local markets and the country.
	•		Deregulation, unanticipated impacts of 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 to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins.
	•		The ability to meet internal performance goals. Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our performance goals.
	•		The capital-intensive nature of our business, including governmental approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project.
	•		Changes in the availability and cost of natural gas. To meet 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 activity to minimize 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

9

			have a significant impact on the demand for and the cost of natural gas.
	•		Changes in environmental requirements and cost of compliance.
	•		Earnings from our equity investments. We have investments in unregulated retail energy marketing services, interstate liquefied natural gas (LNG) storage operations, intrastate and interstate pipeline operations and unregulated retail propane operations. 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 these forward-looking statements to be reasonable, there can be no assurance that they 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,” “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 in our Annual Report on Form 10-K, as well as information included in, or incorporated by reference from, future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in the Annual Report to Shareholders. There also may be other factors besides those described above or incorporated 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 Business

     Piedmont Natural Gas Company, Inc., began operations in 1951, and is an energy services company primarily engaged in the distribution of natural gas to 740,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. Piedmont is also invested in a number of non-utility, energy-related businesses, including companies involved in unregulated retail natural gas and propane marketing and interstate and intrastate natural gas storage and transportation.

10

We also sell residential and commercial gas appliances in Tennessee.

     Our utility operations are subject to regulation by the 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. We are also subject to or affected by various federal and state regulations.

     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.

     In the Carolinas, our service area is comprised of numerous cities, towns and communities including Anderson, Greenville, Spartanburg and Gaffney in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine and Reidsville in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville.

     We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. For further information on segments, see Note 10 to the consolidated financial statements.

Liquidity and Capital Resources

     We finance current cash requirements primarily from operating cash flows and short-term borrowings. Outstanding short-term borrowings under committed bank lines of credit totaling $150 million ranged from zero to $57 million during the year ended October 31, 2002, and interest rates ranged from 2.0663% to 2.6875%. At October 31, 2002, $46.5 million of short-term debt was outstanding at a weighted average interest rate of 2.2323%. Borrowings under these lines include LIBOR cost-plus loans, transactional borrowings and overnight cost-plus loans based on the lending bank’s cost of money, with a maximum rate of the lending bank’s commercial prime interest rate. The maximum annual fee for the committed lines of credit is $198,000. We have additional uncommitted lines of credit totaling $73 million on a no fee and as needed, if available, basis. At October 31, 2002, our current assets were less than our current liabilities due primarily to the $45 million long-term debt maturity in 2003; however, the lines of credit are adequate to provide the necessary near-term liquidity.

     Our utility operations are weather sensitive. The primary

11

factor that impacts our cash flows from operations is weather. Warmer weather can lead to lower total margin from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but extremely cold weather may lead to conservation by our customers in order to reduce their consumption. Weather outside the normal range of temperatures can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements. During 2002, 55% of our sales and transportation revenues were from residential customers and 29% were from commercial customers, both of which are weather-sensitive customer classes. We have a weather normalization adjustment (WNA) mechanism in all three states that partially offsets the impact of unusually cold or warm weather on bills rendered in November through March for these weather-sensitive customers. The mechanism is most effective in a reasonable temperature range relative to normal weather using 30 years of history.

     During 2002, 66% of our cash needs were funded through internal operations. The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas that are charged by suppliers and to increased gas supplies required to meet our customers’ needs during cold weather and to meet our storage needs. Short-term debt generally increases 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. We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. During 2002, we issued $18.5 million of equity through dividend reinvestment and stock purchase plans but none on the open market. We did not sell any long-term debt during the year. We anticipate selling long-term debt in the fourth quarter of 2003 under the $250 million combined debt and equity shelf registration statement filed with the SEC in 2001. Unless otherwise specified at the time such securities are offered for sale, the net proceeds will be used for general corporate purposes, including construction of additional facilities, repayment of short-term debt and working capital needs. Pending such use, we may temporarily invest the net proceeds in investment grade securities.

     Our debt ratings are “A2” from Moody’s and “A” from Standard & Poor’s (S&P). We are well within the debt default provisions established for our senior notes, medium-term notes, short-term bank lines of credit and accounts receivable financings. Following the announcement of our proposed acquisition of North Carolina Natural Gas, as discussed in Note 2 to the consolidated financial statements, Moody’s and S&P placed our debt ratings under review for possible downgrade. The purchase price of $425 million will initially be funded with short-term debt that will be refinanced within six to nine months through the issuance of long-term debt and equity securities. While this acquisition will be positive in the long run by permitting us to expand our customer service base

12

with an additional 176,000 customers in North Carolina, it would have the initial effect of increased debt levels and reduced fixed charge coverages. See further discussion of this acquisition in Gas Supply and Regulatory Proceedings.

     At October 31, 2002, we had $509 million of long-term debt outstanding. Annual sinking fund requirements and maturities of this debt over the next five years are $47 million in 2003, $2 million in 2004, zero in 2005, $35 million in 2006 and zero in 2007. We retired $2 million of long-term debt in 2002.

     The financial condition of the pipelines and marketers that supply and deliver natural gas to our system can increase our exposure to supply and price fluctuations. The Williams Companies, Inc., whose subsidiary Transcontinental Gas Pipe Line Corporation (Transco) is the major pipeline which serves our Carolina service areas and whose subsidiary Williams Energy Services Company (Wesco) is a wholesale supplier of commodity natural gas service, has experienced financial difficulties. Wesco currently provides natural gas to us under several supply contracts. In all cases with Transco and Wesco, and with other suppliers with whom we have smaller contracts, the products and services are received by us prior to payment or are subject to payment netting agreements. We believe our risk exposure to the financial condition of these companies is minimal based on 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 short-term borrowings discussed above. Our accounts receivable and accounts payable balances were higher at October 31, 2002, compared with 2001, due in part to the purchase of the North Carolina Gas Service gas distribution system from NUI Utilities, Inc., as discussed in Note 2 to the consolidated financial statements. From April 1 to October 31, we build up natural gas inventories by injecting gas into storage for sale in the colder months. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year.

     We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our approximately 4% current annual growth in customer base. Utility construction expenditures for 2002 were $83.7 million. Utility construction expenditures totaling $85.3 million, primarily to serve customer growth, are budgeted for 2003. Due to growth in our service area, significant utility construction expenditures are expected to continue. Short-term debt may be used to finance construction

13

pending the issuance of long-term debt or equity.

     During 2002, cash provided from operations, from bank lines of credit and from the issuance of common stock through dividend reinvestment and stock purchase plans was sufficient to fund construction expenditures, pay debt principal and interest of $41.7 million and pay dividends to shareholders of $51.9 million.

     Our expected future contractual obligations at October 31, 2002, for long-term debt, pipeline and storage capacity and gas supply and operating leases are as follows:

     At October 31, 2002, our capitalization consisted of 44% in long-term debt and 56% in common equity. Our long-term targeted capitalization ratio is 45% in long-term debt and 55% in common equity. The embedded cost of long-term debt at October 31, 2002, was 7.71%. The return on average common equity for 2002 was 10.82%.

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 domestic natural gas distribution segment is subject to regulation by certain state and federal authorities. We have accounting policies that conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effect 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 on the balance sheet as regulatory assets and liabilities when it is

14

probable that 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. At October 31, 2002, we had $19.7 million of regulatory assets and $28.6 million of regulatory liabilities, including deferred income tax liabilities of $13 million. If, for any reason, we 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 these 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 our consolidated financial statements. For further discussion of significant accounting policies, see Notes 1, 9 and 11 to the consolidated financial statements.

Allowance for Uncollectible Accounts. We evaluate the collectibility of our trade accounts receivable based on our recent loss history and an overall assessment of past due trade 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 liabilities represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are not discounted and are established based upon analyses of historical data and actuarial estimates. We, along with independent actuaries, review

15

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) covering five-year performance periods under which units are awarded to participants. Each unit is equivalent in value to one share of common stock. Following the end of the performance period, awards are distributed in the form of shares of common stock and cash withheld to pay taxes if performance measures are met. 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 sufficient 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.

     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 a historical twelve-month period. For the most recent period, the NCUC and the PSCSC found us to be prudent in our gas purchasing practices and allowed 100% recovery of our gas costs.

     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. During 2000 and 2001, the NCUC allowed us to use $38.5 million of expansion funds to extend natural gas service to the counties of Avery, Mitchell and Yancey. As we believe that we have no other anticipated projects that qualify

16

for expansion funds as currently determined by the NCUC, we petitioned the NCUC on January 30, 2002, for permission to deposit supplier refunds held in escrow at that time and future supplier refunds in the appropriate gas costs deferred accounts for refund to customers. On February 21, the NCUC agreed and ordered that these supplier refunds be placed in the deferred accounts. At October 31, 2002, the balance in our expansion fund was $5.8 million and is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.

     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 net book value of $6.6 million and added 5,400 customers to our operations.

     In September 2001, we filed a petition with the PSCSC seeking approval of a gas cost hedging plan for the purpose of cost stabilization for customers. On March 26, 2002, the PSCSC issued an order approving the plan on an experimental basis. The PSCSC ruled that all properly accounted for costs incurred in accordance with the plan, with the exception of certain personnel and administrative costs, would be deemed prudently incurred and would be recoverable in rates as a gas cost. We began hedging activities in April under the approved program.

     In October 2001, we filed an application with the NCUC seeking approval to implement an experimental natural gas hedging program. At the time, the NCUC was engaged in a generic investigation into the hedging of natural gas commodity costs, and the NCUC took no action on our application pending further proceedings in the generic investigation.

     On February 26, 2002, the NCUC issued an order in the generic proceeding that concluded, among other things, that hedging costs should be treated as gas costs and that pre-approval of a hedging program would be inconsistent with the procedures for the annual gas costs prudency reviews. In its order, the NCUC stated that hedging is an option that must be considered in connection with the gas purchasing practices of a local distribution company. The NCUC recognized that the review of the prudency of a decision to hedge or not to hedge, just like the review of the prudency of other gas purchasing decisions, must be made on the basis of the information available at the time the decision is made, not on the basis of the information available at the time of the annual prudency review proceeding. On April 10, we again asked the NCUC for approval to operate a hedging plan on an experimental basis for a period of two years and for reconsideration of the NCUC’s conclusion on the pre-approval of a hedging program. On October 18, the NCUC denied our request for pre-approval; however, the NCUC commended us for our hedging plan proposal and our contribution to the understanding of hedging by the NCUC. The NCUC made it clear that while it would not pre-approve the plan,

17

it recognized that the plan is experimental in nature and did not wish to be understood as having disapproved the plan or expressed the opinion that adoption of the plan would result in disallowances in an annual review of gas costs. Nothing in the order precluded us from implementing the plan if we chose to do so subject to the terms of the order in the generic proceeding. Given the favorable comments and assurances by the NCUC in both orders, we implemented a hedging program in North Carolina effective November 1, 2002.

     On March 28, 2002, we filed an application with the NCUC requesting an annual increase in revenues of $28.2 million, an increase of 6.8%. In addition, we requested changes in cost allocations and rate design and changes in tariffs and service regulations. On August 5, a stipulation among Piedmont, the Public Staff of the NCUC and Carolina Utility Customers Association, Inc., an intervenor, was filed with the NCUC. The stipulation resolved all outstanding issues among the stipulating parties and provided for an annual increase in revenues of $13.9 million. A hearing was held on August 27. At the hearing and based on further residential rate design changes agreed to by us, the only intervenor who did not sign the stipulation did not oppose the stipulation. On October 28, the NCUC issued an order approving an annual revenue increase of $13.9 million, effective November 1, 2002.

     On May 3, 2002, we filed an application with the PSCSC requesting an annual increase in revenues of $15.3 million, an increase of 10.5%. In addition, we requested approval of new depreciation rates, changes in cost allocations and rate design and changes in tariffs and service regulations. A hearing was held on September 4 and 5. On October 29, the PSCSC issued an order approving an annual revenue increase of $8.4 million, effective November 1, 2002. The Consumer Advocate of South Carolina has requested a rehearing of the order and we are unable to predict the outcome of that request.

     Effective September 30, 2002, we purchased substantially all of the natural gas distribution assets and certain of the liabilities, including potential remediation costs of a manufactured gas plant site, of North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc., for $26 million in cash. The transaction added 14,000 customers to our distribution system in the counties of Rockingham and Stokes, North Carolina. Included in the assets acquired was NCGS’s expansion fund in the amount of $2.2 million. At October 31, 2002, this amount is included in “Restricted cash” and “Refunds due customers” in the consolidated balance sheets.

     On October 16, 2002, we entered into an agreement to purchase for $425 million in cash the stock of North Carolina Natural Gas (NCNG), a natural gas distribution subsidiary of Progress Energy, Inc., serving 176,000 customers in eastern North Carolina, and

18

Progress Energy’s 50% investment in Eastern North Carolina Natural Gas Company (EasternNC). EasternNC is a joint venture with Albemarle Pamlico Economic Development Corporation to bring natural gas service to 14 counties in eastern North Carolina. The transaction is subject to approvals by various regulatory agencies and is expected to close in mid-2003.

     In 1996, the TRA approved a performance incentive plan, effective July 1, 1996, 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, together with margin from marketing transportation and capacity in the secondary market and from secondary market sales of gas. The plan is subject to an overall annual cap of $1.6 million on gains or losses by us. The benefits of the incentive plan are the elimination of annual gas purchase prudence reviews, 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 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.

     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 discussed 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 2002, 35% 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 of gas 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.

19

     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 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.

Equity Investments

     Piedmont Energy Partners, Inc. (PEP), is a wholly owned subsidiary that is a holding company for various other wholly owned non-utility subsidiaries.

     Piedmont Intrastate Pipeline Company, a wholly owned subsidiary of PEP, is a 16.45% member of Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. 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 Natural Gas Company, for 100% of the 270 million cubic feet 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 will file a general rate case on or before January 15, 2003.

     Piedmont Interstate Pipeline Company, a wholly owned subsidiary of PEP, is a 35% member of Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the FERC. Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under firm service agreements with customers. We subscribe to slightly more than one-half 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

20

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 August 1, 2002, Pine Needle filed a rate increase request with the FERC. We expect an order and new rates to be effective in early 2003.

     Piedmont Propane Company, a wholly owned subsidiary of PEP, owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns all of the general partnership interest and approximately 31% 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 competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage Propane purchases propane at numerous supply points for delivery primarily via railroad tank cars and common carrier transport. Heritage Propane’s profitability is also sensitive to changes in the wholesale prices of propane. Heritage Propane utilizes hedging transactions to provide price 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 under Statement 133. Heritage Propane also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments used in connection with this liquids trading activity are marked to market.

     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. At October 31, 2002, our capital account was positive.

     Piedmont Energy Company, a wholly owned subsidiary of PEP, has a 30% interest in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other members are subsidiaries of AGL Resources, Inc., and Dynegy Inc. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States. SouthStar was formed

21

and began marketing natural gas in Georgia in 1998 when that state implemented full natural gas retail competition. SouthStar conducts most of its business in Georgia, and the unregulated retail gas market in that state is highly competitive.

     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 service areas. The earnings test is based on SouthStar’s fiscal year ending December 31, therefore, the actual impact, if any, of disproportionate sharing is not known until after December 31. At October 31, 2002, we estimated that a portion of SouthStar’s earnings for calendar year 2002 will be above the threshold, and that disproportionate sharing will occur for the first time. We reduced our portion of the equity earnings from SouthStar for the twelve months ended October 31, 2002, by $778,000, pre-tax, to reflect our estimate that our earnings from SouthStar will be at a level of approximately 26% of total earnings, rather than our equity ownership percentage of 30% of total earnings. Based on various calculation methodologies and interpretations of the Operating Policy, our pre-tax earnings reduction for 2002 due to disproportionate sharing could range from zero to $1.1 million.

     SouthStar manages commodity price and weather risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. Financial contracts in the form of futures, options and swaps are used to hedge the price volatility of natural gas. These derivative transactions qualify as cash flow hedges. 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 Statement 133. Weather derivative contracts are used to preserve margins in the event of warmer-than-normal weather during the winter period. Such 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.”

     Currently, SouthStar has exposure to supply fluctuations due to the financial condition of Dynegy. Dynegy has managed SouthStar’s capacity asset agreements and has supplied the majority of its gas. SouthStar is only obligated to purchase gas at market prices from Dynegy. Dynegy has announced that it is exiting the gas supply and capacity management businesses and is in the process of providing an orderly transition for its customers. SouthStar will perform in-house certain activities now provided by Dynegy. SouthStar’s portfolio of suppliers has been significantly expanded to mitigate the exposure to Dynegy. Also,

22

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 bills for local delivery service. Piedmont Energy Company, through its parent, has guaranteed its 30% share of SouthStar’s obligation with AGLC with a letter of credit with a bank in the amount of $13.4 million that expires on August 5, 2003.

     Piedmont Greenbrier Pipeline Company, LLC, a North Carolina limited liability company, is a wholly owned subsidiary that has a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier), a Delaware limited liability company. The other member is a subsidiary of Dominion Resources, Inc. Greenbrier, formed in 2001, proposes to build a 280-mile interstate gas pipeline linking multiple gas supply basins and storage to markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day to commence service in 2005. The pipeline would originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. This pipeline will broaden our access to competitive gas supplies and will also serve new power generation facilities in the region. The pipeline is expected to cost $497 million, with $150 million of the cost expected to be contributed as equity by the owners and the remainder expected to be provided by project-financed debt. As of October 31, 2002, we have made capital contributions to Greenbrier totaling $6.8 million. We have signed a precedent agreement for firm transportation service with Greenbrier. On October 30, 2002, the FERC gave preliminary approval to the project regarding non-environmental issues. Construction of the pipeline is subject to a number of conditions, including final certificate approval by the FERC.

Results of Operations

     Net income for 2002 was $62.2 million, compared with $65.5 million in 2001 and $64 million in 2000. Net income for 2002 decreased $3.3 million from 2001 primarily for the reasons listed below.

	•		Decrease in margin due to warmer weather resulting in fewer volumes of gas delivered to customers (system throughput).
	•		Increase in depreciation expense.
	•		Increase in interest expense.

These changes were partially offset by an increase in volumes delivered to industrial customers and an increase in earnings from unregulated retail energy marketing services.

     Net income for 2001 increased $1.5 million over 2000 primarily for the reasons listed below.

23

	•		Rates charged to customers increased due to general rate increases in Tennessee effective July 1, 2000, and in North Carolina effective November 1, 2000.
	•		Even though total system throughput decreased, volumes delivered to residential and commercial customers from whom we earn a higher margin increased.
	•		Increase in the allowance for funds used during construction (AFUDC).
	•		Increase in interest income.
	•		Increase in earnings from unregulated retail energy marketing services.
	•		Increase in earnings from non-utility LNG operations.
	•		Increase in earnings from secondary market transactions.
	•		Addition of Gaffney customers in January 2001.

     These changes were partially offset for the reasons listed below.

	•		Increase in operations and maintenance expenses.
	•		Increase in depreciation expense.
	•		Increase in general taxes.
	•		Increase in interest charges.
	•		Decrease in earnings from propane operations.

     Compared with the prior year, weather in our service area, as measured by degree days, was 21% warmer in 2002, 23% colder in 2001 and 1% warmer in 2000. System throughput was 126.1 million dekatherms in 2002, compared with 134.4 million dekatherms in 2001, a decrease of 6%, and 135.1 million dekatherms in 2000. In addition to system throughput, secondary market sales volumes were 55.7 million dekatherms in 2002, compared with 29.5 million dekatherms in 2001 and 21.1 million dekatherms in 2000.

     Operating revenues were $832 million in 2002, $1,107.9 million in 2001 and $830.4 million in 2000. Operating revenues for 2002 decreased $275.9 million from 2001 primarily for the reasons listed below.

	•		The commodity cost of gas decreased significantly during the winter of 2001-2002 resulting in a corresponding decrease in rates charged to customers.
	•		Decreased system throughput to all customer classes except industrial due to warmer weather.

     These decreases were partially offset by increased secondary market activity.

     Operating revenues for 2001 increased $277.5 million over 2000 primarily for the reasons listed below.

•

The commodity cost of gas increased significantly during

24

			the winter of 2000-2001 resulting in a corresponding increase in rates charged to customers.
	•		Increased customer growth and 23% colder weather.
	•		System throughput to higher-margin residential and commercial customers increased nine million dekatherms.
	•		Rates increased due to general rate increases as noted above.
	•		Increased secondary market activity.
	•		Addition of Gaffney customers in January 2001.

     The WNA generated revenues from customers of $19.8 million in 2002, refunds to customers of $8.5 million in 2001 and revenues of $19.3 million in 2000. The WNA is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin. Weather 15% warmer than normal was experienced in 2002, compared with 8% colder than normal in 2001 and 13% warmer than normal in 2000.

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

     Cost of gas for 2002 was $496.2 million, compared with $769.9 million in 2001 and $512 million in 2000. Cost of gas for 2002 decreased $273.7 million from 2001 primarily due to decreases in the wholesale commodity cost of gas from suppliers and decreases in volumes sold to residential and commercial customers.

     Cost of gas for 2001 increased $257.9 million over 2000 primarily due to increases in the commodity cost of gas from suppliers. Wholesale market prices during the winter of 2000-2001 were more than double the prices of the previous winter. Increases in wholesale prices resulted in lower volumes sold to customers due to customer conservation and the loss of industrial volumes to oil due to price competition. We also curtailed interruptible industrial customers for system management during a portion of the 2000-2001 winter period. Increases or decreases in purchased gas costs from suppliers are passed on to customers through PGA procedures.

     Margin (operating revenues less cost of gas) for 2002 was $335.8 million, compared with $338 million in 2001 and $318.3 million in 2000. Margin increased or decreased due to the changes in revenues and cost of gas noted above. The margin earned per dekatherm of system throughput increased by $.12 in 2002 over 2001 and by $.13 in 2001 over 2000.

25

     Operations and maintenance expenses were $133.4 million in 2002 and 2001 and $127 million in 2000. Even though operations and maintenance expenses were even for 2002 and 2001, the following increases and decreases were experienced.

	•		Increase in payroll expense due to positions being filled by employees rather than by outside labor.
	•		Increase in other corporate expense due to increases in fees for committed lines of credit and net service fees to banks and increases in training expenses.
	•		Increase in employee benefits expense due to pension expense recorded in 2002 with pension income recorded in 2001 and increased health insurance premiums.
	•		Decrease in outside labor as explained above.
	•		Decrease in the provision for uncollectibles due to warmer weather and lower gas prices.

     Operations and maintenance expenses for 2001 increased $6.4 million over 2000 primarily for the reasons listed below.

	•		Increase in transportation expense due to higher fuel costs and increases in license fees and taxes.
	•		Increase in utilities expense due to the installation of new communications units in service trucks and the higher volume of telephone calls to our customer information centers.
	•		Increase in bank charges for activity fees and for fees associated with higher committed bank lines.
	•		Increase in the provision for uncollectibles due to higher charge-offs for customers who could not pay their bills due to higher gas prices and colder-than-normal weather.
	•		Amortization of North Carolina environmental expense as recovered from customers beginning in November 2000.

These increases were partially offset by the following decreases.

	•		Decrease in employee benefits expense due primarily to a decrease in pension expense and the shift of the payment of administrative fees from benefit plan assets rather than by the sponsor.
	•		Decrease in outside consultants expense due to a reduction in the need for information systems upgrades.

     Depreciation expense increased from $48.9 million to $57.6 million over the three-year period 2000 to 2002 primarily due to growth in plant in service.

     General taxes increased from $18.8 million to $23.9 million over the three-year period 2000 to 2002 primarily due to increases in property taxes due to growth in plant in service, franchise

26

taxes due to a rate increase and payroll taxes due to increased payroll.

     Other income (expense), net of income taxes, was $12.7 million in 2002, compared with $10.9 million in 2001 and $11.3 million in 2000. Other income (expense) for 2000 includes $5.1 million from a business combination affecting our propane operations. Other income (expense) for 2000 without this transaction would have been $6.2 million.

     Prior to August 2000, Piedmont Propane Company marketed propane and propane appliances to residential, commercial and industrial customers within and adjacent to our three-state natural gas service area. In August, US Propane, L.P., was formed to combine our propane operations with the propane operations of three other companies. Piedmont Propane owns 20.69% of the membership interest in US Propane. Immediately after formation, US Propane combined with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (Heritage Propane), by contributing all of its assets to Heritage Holdings for $181.4 million in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage Holdings for $120 million. At the time of the combination, US Propane owned all of the general partnership interest and approximately 34% of the limited partnership interest in Heritage Propane. This combination, including a gain on the transfer of the propane assets, transaction costs and certain employee benefit plans’ gains and charges, contributed $5.1 million to net income in 2000.

     Income from non-utility activities, at equity, before taxes, for 2002 increased $2.9 million over 2001 primarily due to an increase in earnings from unregulated retail energy marketing services. This increase was partially offset by a decrease in earnings from propane due to warmer weather experienced in 2002.

     Income from non-utility activities, at equity, before taxes, for 2001 increased $8.7 million over 2000 primarily due to increases in earnings from unregulated retail energy marketing services, non-utility LNG operations and propane.

     The equity portion of AFUDC, before taxes, was $2 million in 2002, compared with $1.8 million in 2001 and zero in 2000. 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.

     Other, before taxes, for 2002 was $511,000, compared with $192,000 in 2001 and $11 million in 2000. Other in 2000 includes the effect of the propane business combination discussed above. The increase in 2002 over 2001 was primarily due to an increase in earnings from merchandise operations and interest income. The decrease in 2001 from 2000, excluding the propane business

27

combination discussed above, was primarily due to a decrease in income from propane operations which we operated in 2000, partially offset by an increase in interest income.

     Utility interest charges were $40.6 million in 2002, compared with $39.4 million in 2001 and $37 million in 2000. Utility interest charges for 2002 increased $1.2 million over 2001 primarily due to the following reasons.

	•		Increase in interest on long-term debt due to higher balances outstanding.
	•		Decrease in the portion of AFUDC attributable to borrowed funds.

These changes were partially offset by the following decreases.

	•		Decrease in interest on short-term debt due to lower balances outstanding at lower interest rates.
	•		Decrease in interest charged on refunds due customers due to lower balances outstanding.

     Utility interest charges for 2001 increased $2.4 million over 2000 primarily due to the following reasons.

	•		Increase in interest on long-term debt due to higher balances outstanding.
	•		Increase in interest charged on refunds due customers due to higher balances outstanding.

These increases were partially offset by the following changes.

	•		Decrease in interest on short-term debt due to lower balances outstanding at lower interest rates.
	•		Increase in the portion of AFUDC attributable to borrowed funds.

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. Three other MGP sites that we also have owned, leased or operated were not included in the settlement.

28

     In September 2002, in connection with the purchase of the operations of NCGS discussed in Note 2 to the consolidated financial statements, we acquired the liability for an MGP site located in Reidsville, North Carolina. We had a limited assessment performed by a third party that consisted of an evaluation of documents, a site visit and an interview with an employee of the seller. This study concluded that a comprehensive baseline risk assessment would cost $150,000 and the maximum cost to remediate the site would be $487,000. Based on this study and the similar nature of the three sites not covered by the settlement, 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 $637,000 for each of the four sites.

     At October 31, 2002, our undiscounted environmental liability totaled $2.9 million, consisting of $2.6 million for the four MGP sites and $320,000 for underground storage tanks not yet remediated. This liability is not net of any anticipated recoveries.

     At October 31, 2002, our regulatory assets for environmental costs totaled $6.2 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 current approved 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.

Accounting Pronouncements

     Effective November 1, 2002, we will adopt SFAS No. 141, “Business Combinations” (Statement 141). Statement 141 requires that business combinations be accounted for using the purchase method. Statement 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination. The adoption of Statement 141 will not have a material effect on financial position or results of operations.

     Effective November 1, 2002, we will adopt SFAS No. 142, “Goodwill and Other Intangible Assets” (Statement 142). Statement 142 provides new guidance for accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be

29

accounted for subsequent to their initial recognition. The adoption of Statement 142 will not have a material effect on financial position or results of operations.

     Effective November 1, 2002, we will adopt SFAS No. 143, “Accounting for Asset Retirement Obligations” (Statement 143). Statement 143 addresses financial accounting and reporting for asset retirement obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the asset. Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that asset retirement obligations exist for our underground mains and services, however, the fair value of the obligation cannot be determined because the end of the system life is indeterminable.

     Effective November 1, 2002, we will adopt SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement 144). Statement 144 provides one accounting model to be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. The adoption of Statement 144 will not have a material effect on financial position or results of operations.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

     All financial instruments discussed below are held by us 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 supply of and demand for natural gas.

Interest Rate Risk

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

     At October 31, 2002, we had $46.5 million of short-term debt outstanding at a weighted average interest rate of 2.23%. The carrying amount of our short-term debt approximates fair value.

30

     Information about our long-term debt at October 31, 2002, that is sensitive to changes in interest rates is presented below.

Commodity Price Risk

     In the normal course of business, we utilize contracts of various duration for the forward sales and purchase of natural gas. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers. Due to cost-based rate regulation, we have limited exposure to changes in commodity prices as substantially all changes in purchased gas costs from suppliers are passed on to customers through purchased gas adjustment procedures.

     For further information on market risk, see “Liquidity and Capital Resources” beginning on page 11 in Item 7 of this report in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8. Financial Statements and Supplementary Data

     Consolidated financial statements and schedules required by this item are listed in Item 14(a)1 and 2 in Part IV of this report on page 67.

31

Consolidated Balance Sheets
October 31, 2002 and 2001