-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, F0v3YeHiUcSWrcj5pc1/Zw9Ylh1seRr8r7GAlPocEWESM/dMYy9b8z9PVVimSBEb CTGIO3Bv0M36W/5g6o2f5A== 0000950144-02-000674.txt : 20020414 0000950144-02-000674.hdr.sgml : 20020414 ACCESSION NUMBER: 0000950144-02-000674 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20011031 FILED AS OF DATE: 20020125 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PIEDMONT NATURAL GAS CO INC CENTRAL INDEX KEY: 0000078460 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 560556998 STATE OF INCORPORATION: NC FISCAL YEAR END: 1031 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-06196 FILM NUMBER: 02517100 BUSINESS ADDRESS: STREET 1: 1915 REXFORD RD CITY: CHARLOTTE STATE: NC ZIP: 28211 BUSINESS PHONE: 7043643120 MAIL ADDRESS: STREET 1: P.O. BOX 33068 CITY: CHARLOTTE STATE: NC ZIP: 28233 10-K405 1 g73788k5e10-k405.txt PIEDMONT NATURAL GAS COMPANY, INC. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------ FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) FOR THE FISCAL YEAR ENDED OCTOBER 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) FOR THE TRANSITION PERIOD FROM ____________ TO____________ COMMISSION FILE NUMBER 1-6196 ------------------ PIEDMONT NATURAL GAS COMPANY, INC. (Exact name of registrant as specified in its charter) NORTH CAROLINA 56-0556998 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1915 REXFORD ROAD, CHARLOTTE, NORTH CAROLINA 28211 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (704) 364-3120 ------------------ SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common Stock, no par value New York Stock Exchange 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 __ 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 10, 2002. Common Stock, no par value -- $1,094,847,837 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. CLASS OUTSTANDING AT JANUARY 10, 2002 ----- ------------------------------- Common Stock, no par value 32,553,461 DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Shareholders on February 22, 2002, are incorporated by reference into Part III. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Piedmont Natural Gas Company, Inc. 2001 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS Part I. Page ---- Item 1. Business 1 Item 2. Properties 6 Item 3. Legal Proceedings 6 Item 4. Submission of Matters to a Vote of Security Holders 6 Part II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 7 Item 6. Selected Financial Data 8 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 8 Item 7A. Quantitative and Qualitative Disclosure about Market Risk 24 Item 8. Financial Statements and Supplementary Data 25 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 51 Part III. Item 10. Directors and Executive Officers of the Registrant 52 Item 11. Executive Compensation 54 Item 12. Security Ownership of Certain Beneficial Owners and Management 54 Item 13. Certain Relationships and Related Transactions 55 Part IV. Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K 56 Signatures 66 PART I Item 1. Business - ----------------- Piedmont Natural Gas Company, Inc., incorporated in 1950, is an energy and services company primarily engaged in the distribution of natural gas to 710,000 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 retail 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 and Spruce Pine in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville. In January 2001, we began serving customers in Gaffney and Cherokee County, South Carolina, following the purchase of the natural gas system serving that area from Atmos Energy Corporation. For further information, see "Note 2. Regulatory Matters" in Item 8 of this report on page 35. We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Operations of our domestic natural gas distribution segment are conducted by the parent company and two wholly owned subsidiaries, Piedmont Intrastate Pipeline Company and Piedmont Interstate Pipeline Company, of our wholly owned subsidiary, Piedmont Energy Partners. Piedmont Intrastate is a 16.45% member of Cardinal Pipeline Company, L.L.C., which owns and operates an intrastate natural gas pipeline in North Carolina. Piedmont Interstate is a 35% member of Pine Needle LNG Company, L.L.C., which owns an interstate liquefied natural gas (LNG) peak-demand storage facility in North Carolina. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company, a wholly owned subsidiary of Piedmont Energy Partners. Piedmont Energy is a 30% member of SouthStar Energy Services LLC. SouthStar offers a combination of unregulated natural gas services to industrial, commercial and residential customers in the southeastern United States. Most of our other activities are conducted by Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners. Piedmont Propane owns 20.69% of the membership interest in US Propane, L.P., which owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P. 1 (NYSE:HPG). Heritage is the nation's fourth-largest propane distributor, serving customers in 29 states. 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. Substantially all changes in gas costs 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, 2001, totaled $1.1 billion, of which 47% was from residential customers, 27% from commercial customers, 12% from industrial customers, 13% from secondary market activity and 1% from various other sources. Revenues from non-utility operations, less related costs, are shown in the statements of consolidated income in "non-utility activities, at equity" or "other, net" in Other Income. For further segment information, see "Note 8. Business Segments and Other Non-Utility Activities" in Item 8 of this report on page 43. 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 regulations. We hold non-exclusive franchises for natural gas service in more than 90 communities we serve, with expiration dates from 2002 to 2050. The franchises are adequate for operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. Two franchises that expired in 2000 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 to us. In most cases, the loss of a franchise would not have a material effect on operations. We have never failed to obtain the renewal of a franchise; however, this is not necessarily indicative of future action. 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, 2001, the amount of natural gas in storage varied from 7.4 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 20.8 million 2 dekatherms, and the aggregate commodity cost of this gas in storage varied from $32.4 million to $75.1 million. The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1997 through 2001:
2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- OPERATING REVENUES (in thousands): Sales and Transportation: Residential $ 525,650 $343,476 $295,108 $323,777 $319,722 Commercial 299,672 207,087 168,731 189,341 195,862 Industrial 129,732 202,120 143,129 162,336 191,565 For Resale 371 249 254 87 266 ---------- -------- -------- -------- -------- Total 955,425 752,932 607,222 675,541 707,415 Secondary Market Sales 145,712 73,505 75,734 86,333 64,411 Miscellaneous 6,719 3,940 3,514 3,403 3,691 ---------- -------- -------- -------- -------- Total $1,107,856 $830,377 $686,470 $765,277 $775,517 ========== ======== ======== ======== ======== GAS VOLUMES - DEKATHERMS (in thousands): System Throughput: Residential 47,869 40,520 38,111 41,142 38,339 Commercial 31,002 29,315 26,668 28,528 28,476 Industrial 54,285 61,144 64,171 64,165 65,000 For Power Generation 1,169 4,081 6,991 9,141 3,236 For Resale 29 20 29 17 27 ---------- -------- -------- -------- -------- Total 134,354 135,080 135,970 142,993 135,078 ========== ======== ======== ======== ======== Secondary Market Sales 29,545 21,072 34,792 33,953 24,547 =========== ======== ======== ======== ======== NUMBER OF RETAIL CUSTOMERS BILLED (12 month average): Residential 601,682 577,314 549,610 522,874 495,739 Commercial 71,069 68,879 66,409 63,878 62,258 Industrial 2,770 2,702 2,764 2,778 2,697 ---------- -------- -------- -------- -------- Total 675,521 648,895 618,783 589,530 560,694 ========== ======== ======== ======== ======== AVERAGE PER RESIDENTIAL CUSTOMER: Gas Used - Dekatherms 79.56 70.19 69.34 78.69 77.34 Revenue $873.63 $594.95 $536.94 $619.23 $644.94 Revenue Per Dekatherm $10.98 $8.48 $7.74 $7.87 $8.34 COST OF GAS (in thousands): Natural Gas Purchased $670,380 $426,329 $290,501 $337,400 $362,249 Liquefied Petroleum Gas (LPG) - - - - 77 Transportation Gas Received (Not Delivered) 214 (868) (1,236) 339 (1,840) Natural Gas Withdrawn from (Injected into) Storage, net 115 (20,144) (3,111) (2,750) 2,597 Other Storage (983) (4,937) (4,937) 333 318 Capacity Demand Charges 80,622 94,095 91,661 94,831 87,439 Other Adjustments 19,530 17,571 (6,916) 12,269 9,825 ---------- -------- -------- -------- -------- Total $769,878 $512,046 $365,962 $442,422 $460,665 ========== ======== ======== ======== ======== COST OF GAS PER DEKATHERM OF GAS SOLD $6.94 $4.17 $3.05 $3.45 $3.81 SUPPLY AVAILABLE FOR DISTRIBUTION - DEKATHERMS (in thousands): Natural Gas Purchased 121,465 126,228 130,633 138,870 129,797 LPG - - - - 10 Transportation Gas 44,285 31,896 44,322 42,091 32,026 Natural Gas Withdrawn from (Injected into) Storage, net 1,598 (712) (373) (3,301) (3) Other Storage 50 (259) (2,132) 27 16 Company Use (167) (161) (154) (110) (121) ---------- -------- --------- -------- -------- Total 167,231 156,992 172,296 177,577 161,725 ========== ======== ========= ======== ========
3
2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- UTILITY CAPITAL EXPENDITURES (in thousands) $90,212 $108,650 $102,020 $93,513 $93,482 GAS MAINS - MILES OF 3" EQUIVALENT 19,500 18,900 18,400 18,200 17,800 DEGREE DAYS - SYSTEM AVERAGE: Actual 3,821 3,097 3,124 3,339 3,471 Normal 3,541 3,563 3,597 3,612 3,611 Percentage of Actual to Normal 108% 87% 87% 92% 96%
During the year ended October 31, 2001, 42.8 million dekatherms of gas were transported for large customers, compared with 32 million dekatherms in 2000. Deliveries to temperature-sensitive residential and commercial customers, whose consumption varies with the weather, totaled 78.9 million dekatherms in 2001, compared with 69.8 million dekatherms in 2000. Weather, as measured by degree days, was 8% colder than normal in 2001 and 13% warmer than normal in 2000. Except as set forth below, all natural gas distributed is transported to us by one or more of eight interstate pipelines, Transcontinental Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company, Texas Eastern Transmission Corporation, Columbia Gas Transmission Company, Columbia Gulf Transmission Corporation, National Fuel Gas Supply Corporation, Texas Gas Transmission Corporation and Dominion Transmission Corporation. As of November 1, 2001, we have contracted to purchase the following pipeline firm transportation capacity in dekatherms of daily deliverability: Transco (including certain upstream arrangements with Dominion, Texas Gas and National Fuel) 495,400 Tennessee Pipeline 74,100 Texas Eastern 1,700 Columbia Gas (through arrangements with Transco and Columbia Gulf) 23,000 Columbia Gulf 35,000 ------- Total 629,200 ======= In addition, we have the following seasonal or peaking capacity in dekatherms of daily deliverability through local peaking facilities, storage contracts and third-party city gate arrangements to meet the firm demands of our markets: Piedmont LNG 213,000 Piedmont LPG 8,000 Transco Storage 72,600 Columbia Gas Storage 91,200 Tennessee Pipeline Storage 55,900 Dominion Storage 7,000 Pine Needle LNG 222,000 Third-Party City Gate Arrangements 28,000 ------- Total 697,700 ======= We own or have under contract 25.1 million dekatherms of storage capacity, either in the form of underground storage or 4 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 Regulatory Proceedings" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report. During the year ended October 31, 2001, approximately 26% of the gas delivered was to industrial or large commercial customers who have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and some 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 commercial or industrial 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 and water heating and primarily with electricity and fuel oil for space heating. During the year ended October 31, 2001, our largest customer contributed $1.9 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 capital expenditures, earnings or competitive position. For further information on environmental issues, see "Environmental Matters" included in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report. At October 31, 2001, we had 1,657 employees, compared with 1,603 at October 31, 2000. 5 Item 2. Properties - ------------------- Our properties consist primarily of distribution systems and related facilities to serve our utility customers. We have approximately 662 miles of lateral pipelines up to 16 inches in diameter that connect our distribution systems with the transmission systems of our pipeline suppliers. Natural gas is distributed through approximately 19,500 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 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 (symbol PNY) for each quarterly period for the years ended October 31, 2001 and 2000. 2001 High Low 2000 High Low ---- ---- --- ---- ---- --- January 31 39.4375 29.1875 January 31 33.1875 28.2500 April 30 36.5500 31.7500 April 30 29.6875 23.7500 July 31 36.0000 32.1500 July 31 31.3125 26.5625 October 31 35.1000 29.1900 October 31 31.1875 26.5000 (b) At January 10, 2002, our Common Stock was owned by 16,620 shareholders of record. (c) Information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2001 and 2000, is as follows: Dividends Paid Dividends Paid 2001 Per Share 2000 Per Share ---- --------- ---- --------- January 31 36.5(cent) January 31 34.5(cent) April 30 38.5(cent) April 30 36.5(cent) July 31 38.5(cent) July 31 36.5(cent) October 31 38.5(cent) October 31 36.5(cent) 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, 2001, all retained earnings were free of such restrictions. 7 Item 6. Selected Financial Data - -------------------------------- Selected financial data for the years ended October 31, 1997 through 2001, is as follows:
In thousands except per share amounts 2001 2000* 1999 1998 1997 ---- ----- ---- ---- ---- Margin $ 337,978 $ 318,331 $ 320,508 $ 322,855 $ 314,852 Operating Revenues $1,107,856 $ 830,377 $ 686,470 $ 765,277 $ 775,517 Net Income $ 65,485 $ 64,031 $ 58,207 $ 60,313 $ 54,074 Earnings per Share of Common Stock: Basic $ 2.03 $ 2.03 $ 1.88 $ 1.98 $ 1.81 Diluted $ 2.02 $ 2.01 $ 1.86 $ 1.96 $ 1.79 Cash Dividends Per Share of Common Stock $ 1.52 $ 1.44 $ 1.36 $ 1.28 $ 1.205 Average Shares of Common Stock: Basic 32,183 31,600 31,013 30,472 29,883 Diluted 32,420 31,779 31,242 30,717 30,229 Total Assets $1,393,658 $1,445,003 $1,288,657 $1,162,844 $1,098,156 Long-Term Debt (less current maturities) $ 509,000 $ 451,000 $ 423,000 $ 371,000 $ 381,000 Rate of Return on Average Common Equity 12.04% 12.57% 12.25% 13.74% 13.42% Long-Term Debt to Total Capitalization Ratio 47.60% 46.10% 46.24% 44.74% 47.58%
*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 This document and other documents we file with the Securities and Exchange Commission (SEC) contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements orally to analysts, investors, the media and others. Our discussion contains forward-looking statements concerning, among others, plans, objectives, proposed capital expenditures and future events or performance. Our 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: o Regulatory issues, including those that affect allowed rates of return, rate structure and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate pipeline companies whose 8 rates and services are regulated by the Federal Energy Regulatory Commission (FERC). o Residential, commercial and industrial growth in our service territories. The ability to grow our customer base is 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 United States. o Deregulation, unanticipated impacts of restructuring and increased competition in the energy industry. We face competition from electric companies and energy marketing and trading companies. As a result of continued deregulation, we expect this highly competitive environment to continue. o 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. o The ability to meet internal performance goals. Regulatory issues, customer growth, deregulation, economic and capital market conditions, the price and availability of natural gas and weather conditions can impact our performance goals. o The capital-intensive nature of our business, including 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. o Changes in the availability and price 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. 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 and pipelines are subject to risks associated with exploring, drilling, producing, gathering and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. o 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 weather, either during the winter period or the summer period, can have a significant impact on the demand for and the price of natural gas. o Changes in environmental requirements and cost of compliance. 9 o Earnings of our equity investments. We have investments in unregulated retail energy marketing services, non-utility interstate LNG operations, intrastate pipeline operations and propane. These companies have risks that are inherent to their industries. As an equity investor, we assume the risks of these companies in proportion to our investment interests. 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 this report. There also may be other factors besides those described or incorporated 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. Liquidity and Capital Resources The gas distribution business is highly weather sensitive and seasonal which may cause short-term cash requirements to vary significantly during the year. We finance current cash requirements through operating cash flows, short-term borrowings and the issuance of new common stock through dividend reinvestment and employee stock purchase plans. Short-term debt may be used to finance construction pending the issuance of long-term debt or equity. We sell common stock and long-term debt when market or other conditions are favorable for such long-term financing. Various banks provide lines of credit totaling $150 million for direct short-term borrowings. Additional lines are also available on an as needed, if available, basis. Borrowings under these lines include open-ended loans based on the Federal Reserve funds rate, LIBOR cost-plus loans, transactional borrowings and 10 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. Outstanding short-term borrowings during 2001 ranged from zero to a high of $148.5 million and interest rates ranged from 2.6375% to 10.5% during the year. At October 31, 2001, $32 million of short-term debt was outstanding at a weighted average interest rate of 2.74%. The level of short-term borrowings can vary significantly over the year due to changes in the wholesale prices for natural gas that are charged by suppliers and to increased gas supplies required to meet our customers' needs during cold weather. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we can recover our costs from customers through their monthly bills. The natural gas business is seasonal in nature, resulting in fluctuations 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. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. Due to increased wholesale gas costs and colder-than-normal weather this past winter, our accounts receivable balances over the current twelve-month period have been higher at certain times than historical levels, as such gas costs are passed through to customers under purchased gas adjustment (PGA) mechanisms. We incurred more short-term debt to pay gas bills and other operating costs since collections from customers were significantly slower. Some customers have been unable to pay their gas bills, thereby increasing our bad debts expense. Write-offs of accounts receivable, net of recoveries, increased $5.7 million compared with the prior year. Write-offs may continue to be higher than historical due to general economic conditions. See Gas Supply and Regulatory Proceedings for a discussion of special accounting treatment for excess write-offs of accounts receivable. We had $511 million of long-term debt outstanding at October 31, 2001. Annual sinking fund requirements and maturities of this debt are $2 million in 2002, $47 million in 2003, $2 million in 2004, zero in 2005 and $35 million in 2006. We retired $32 million of long-term debt in 2001. On June 4, 2001, we filed with the SEC a combined debt and equity shelf registration statement for $250 million of securities. The registration statement was declared effective on August 10. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including construction of additional facilities, the repayment of short-term debt and working capital needs. Pending such use, we may temporarily invest the net proceeds in investment grade securities. 11 On September 26, 2001, we issued $60 million of 6.55% medium-term notes under this shelf registration statement. The note is to be redeemed in a single payment at maturity in 2011. At October 31, 2001, our capitalization ratio consisted of 48% long-term debt and 52% common equity. The embedded cost of long-term debt at that date was 7.73%. The return on average common equity for the year ended October 31, 2001, was 12.04%. Cash provided from operations, from financing and from the issuance of common stock through dividend reinvestment and stock purchase plans was sufficient to fund capital expenditures of $90.6 million, payments of debt principal and interest of $68.7 million and dividend payments to shareholders of $48.9 million. We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements that is funded through the sources noted above. The capital expansion program supports our 4% current annual growth in customer base. Utility capital expenditures for 2001 were $90.2 million. Utility capital expenditures totaling $96.9 million, primarily to serve customer growth, are budgeted for 2002. Competition and Accounting for Regulated Activities The natural gas industry has undergone significant changes in moving toward a less-regulated marketplace. In response, we continue to assess the nature of our business and explore alternatives to the traditional utility role of purchase, sale and transportation of natural gas. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us. We anticipate that opportunities for non-regulated sales will increase as competition intensifies and further retail market unbundling occurs. We account for our regulated activities in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71). FAS 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying FAS 71, we have capitalized certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of state utility regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery of or refunds to utility customers in future periods. As competition increases and we are further subjected to the impacts of deregulation, we may not be able to continue to apply FAS 71 to all or parts of our business. If this were to occur, we would be 12 required to apply accounting standards utilized by non-regulated enterprises. At such time as we determine that the provisions of FAS 71 no longer apply, costs previously deferred as regulatory assets in the consolidated balance sheets would be eliminated, net of the elimination of any regulatory liabilities. The composition and amount of regulatory assets and liabilities are shown in Note 1 to the consolidated financial statements. While we believe the provisions of FAS 71 continue to apply to our regulated operations, the changing nature of the business requires continual assessment of the impact of those changes on our accounting policies. Gas Supply and Regulatory Proceedings To meet customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to 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 utility regulators, the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA), 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 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 rates, together with income from marketing transportation and storage capacity in the secondary market. 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 13 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 short-term gas supplies and transportation services by contract with wholesale or off-system customers. These sales contribute the smallest per-unit margin 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 firm customers. Sales in Tennessee are included in the performance incentive plan discussed above. Approximately 26% of annual gas deliveries in 2001 were made to industrial or large commercial customers who have the capability to burn a fuel other than natural gas. The alternative fuels are primarily fuel oil and some 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 commercial or industrial 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. The NCUC has established an expansion fund consisting of supplier refunds due customers to be used to extend natural gas service into unserved areas of the state. The NCUC decides the use of these funds as we file individual project applications for unserved areas. From August 2000 through September 2001, we received $38.5 million from the expansion fund to extend natural gas service to the counties of Avery, Mitchell and Yancey. At October 31, 2001, the North Carolina State Treasurer held $5.6 million in our expansion fund account. This amount along with other supplier refunds, including interest earned to date, is included in restricted cash in the consolidated balance sheets. Effective January 1, 2001, we purchased 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 and $1.5 million of margin to our operations. We have filed petitions with the NCUC and the PSCSC requesting permission to engage in certain hedging activities. Under these petitions, we are requesting advance prudency 14 determination and full recovery under PGA procedures in these states for all costs to be incurred by us in connection with the implementation and administration of these hedging programs. We are unable to determine the outcome of these proceedings at this time. 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. The NCUC did not approve our request but stated that we could seek recovery of the gas cost portion of these excess write-offs in our next annual gas cost review proceeding. 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. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. There are long-term service agreements with local distribution companies for 100% of the 270 million cubic feet per day of firm transportation capacity on the pipeline. Cardinal is dependent on the interstate pipeline company serving North Carolina to deliver gas into the Cardinal pipeline system for service to these companies. Cardinal's long-term debt is secured by an interest in Cardinal's contracts and by pledges of the equity membership interests. 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. Pine Needle owns a liquefied natural gas (LNG) peak-demand 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 long-term 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. The members of Pine Needle have pledged their membership interests as a guarantee of Pine Needle's long-term debt. Pine Needle has also 15 pledged to the lender all its rights in long-term contracts to buy natural gas. Piedmont Propane Company, a wholly owned subsidiary of PEP, owns 20.69% of the membership interest in US Propane, L.P. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P., a marketer of propane through a nationwide retail distribution network in 29 states. Heritage 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 very seasonal with weather conditions significantly affecting the demand for propane. Heritage purchases propane at numerous supply points for delivery to Heritage primarily via railroad tank cars and common carrier transport. Heritage's profitability is sensitive to changes in the wholesale price of propane. Heritage utilizes hedging transactions to provide price protection against significant fluctuations in prices. Piedmont Energy Company, a wholly owned subsidiary of PEP, has a 30% equity interest in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar offers a combination of unregulated energy products and services to industrial, commercial and residential customers in the southeastern United States. SouthStar was formed and began marketing energy services in Georgia in 1998 when that state became the first in the Southeast to fully open to retail competition. After three years of deregulation, a study committee has been appointed to reevaluate the deregulation of the Georgia natural gas market. Some of the proposals could have a substantial impact on the business and earnings of SouthStar. We do not have sufficient information to permit us to predict the outcome of this study or any legislation or regulation that may result from the study. In August 2001, SouthStar reported that its net income was overstated due to the manner in which SouthStar estimated the amount of lost and unaccounted for gas in computing unbilled revenues. SouthStar recorded the adjustment as a change in estimate. Our portion of the adjustment, $5 million net of tax, was recorded as a reduction in other income for the quarter ended July 31, 2001. The loss per share impact of the adjustment was $(.15) for the year ended October 31, 2001. SouthStar manages commodity price risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. During 2001, we formed Piedmont Greenbrier Pipeline Company, LLC, a North Carolina limited liability company. This wholly owned subsidiary is a 33% equity member of Greenbrier Pipeline 16 Company, LLC (Greenbrier), a Delaware limited liability company. Greenbrier is proposing to build a 263-mile interstate pipeline linking multiple gas supply basins and storage to the growing demand of markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day. The pipeline will originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. The $497 million pipeline is expected to be project financed by the owners. The pipeline is expected to be ready for service by the second quarter of 2005. The certificate application for the project will be filed with the FERC in the first half of 2002. Results of Operations Net income for 2001 was $65.5 million, compared with $64 million in 2000 and $58.2 million in 1999. Net income for 2001 increased $1.5 million from 2000 primarily for the reasons listed below. o Rates charged to customers increased due to general rate increases in Tennessee effective July 1, 2000, and in North Carolina effective November 1, 2000. o Even though system throughput decreased, delivered volumes from residential and commercial customers from whom we earn a higher margin increased. o Increase in the allowance for funds used during construction (AFUDC). o Increase in interest income. o Increase in earnings from unregulated retail energy marketing services. o Increase in earnings from non-utility LNG operations. o Increase in earnings from secondary market transactions. o Addition of Gaffney customers in January 2001. These increases were partially offset for the reasons listed below. o Operations and maintenance expenses increased. o Depreciation expense increased. o General taxes increased. o Interest charges increased. o Earnings from propane operations decreased. Net income for 2000 increased $5.8 million from 1999 primarily for the reasons listed below. o Regulatory rate changes increased rates and updated gas cost components. 17 o Decrease in general taxes. o Increase in earnings from unregulated retail energy marketing services. o Increase in earnings from non-utility LNG operations. o Increase in earnings from pipeline operations. o Sale of propane assets. These increases were partially offset for the reasons listed below. o Increase in operations and maintenance expenses. o Increase in depreciation expense. o Increase in utility interest charges. Compared with the prior year, weather in our service area was 23% colder in 2001, 1% warmer in 2000 and 6% warmer in 1999. Volumes of gas delivered to customers, which we refer to as system throughput, were 134.4 million dekatherms in 2001, compared with 135.1 million dekatherms in 2000, a decrease of 1%, and 136 million dekatherms in 1999. In addition to this system throughput, secondary market sales volumes were 29.5 million dekatherms in 2001, compared with 21.1 million dekatherms in 2000 and 34.8 million dekatherms in 1999. Operating revenues were $1,107.9 million in 2001, $830.4 million in 2000 and $686.5 million in 1999. Operating revenues for 2001 increased $277.5 million from 2000 primarily for the reasons listed below. o The commodity cost of gas increased significantly during the winter of 2000-2001 causing a corresponding increase in rates charged to customers. o Increased customer growth and 23% colder weather. o Deliveries to higher-margin residential and commercial customers increased 9 million dekatherms. o Rates increased due to general rate increases as noted above. o Increased secondary market activity. o The addition of Gaffney customers in January 2001. Operating revenues for 2000 increased $143.9 million from 1999 primarily for the reasons listed below. o Increase in the commodity cost of gas which is a component of revenues. o The shift in the industrial market from transportation of gas to sales of gas on which there is a commodity cost included in revenues. 18 o Deliveries to residential and commercial customers increased. The weather normalization adjustment mechanism (WNA) generated refunds to customers of $8.5 million in 2001 and revenues of $19.3 million and $19.7 million in 2000 and 1999, respectively. The WNA is designed to offset the impact that unusually cold or warm weather has on residential and commercial customer billings and margin. Weather 8% colder than normal was experienced in 2001, compared with 13% warmer-than-normal weather in 2000 and 1999. 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 was $769.9 million in 2001, $512 million in 2000 and $366 million in 1999. Cost of gas for 2001 increased $257.9 million from 2000 primarily due to increases in commodity gas costs from our suppliers. Wholesale market prices for 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 winter period. Cost of gas for 2000 increased $146 million from 1999 primarily due to increases in commodity gas costs and increases in volumes sold to residential and commercial customers and to industrial customers who shifted from transportation. Increases or decreases in purchased gas costs from suppliers have no significant impact on margin as substantially all changes are passed on to customers through PGA procedures. Margin was $338 million in 2001, $318.3 million in 2000 and $320.5 million in 1999. Margin increased or decreased due to the changes in revenues and cost of gas noted above. As explained in the general taxes discussion below, operating revenues, and therefore margin, included North Carolina gross receipts taxes of $9.6 million in 1999. The margin earned per dekatherm of system throughput increased by $.13 in 2001 from 2000 and did not change in 2000 from 1999. 19 Operations and maintenance expenses were $133.4 million in 2001, $127 million in 2000 and $116.8 million in 1999. Operations and maintenance expenses for 2001 increased $6.4 million, compared with 2000, primarily due to the reasons listed below. o Increase in transportation expenses due to higher gasoline costs and increases in license fees and taxes. o 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. o Increase in other corporate expense due to an increase in Directors' fees and an increase in bank charges for activity fees and for fees associated with higher committed bank lines. o 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 the colder-than-normal winter. o Amortization of North Carolina environmental expense as recovered from customers beginning in November 2000. These increases were partially offset by the following decreases. o 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. o Decrease in outside consultants expense due to a reduction in the need for information systems upgrades. Operations and maintenance expenses for 2000 increased $10.2 million, compared with 1999, primarily due to the reasons listed below. o Increase in payroll expense due to increased salaries and long-term incentive plan accruals. o Increase in insurance expense due to an increase in workers' compensation costs. o Increase in advertising expense for the production of new television, radio and print ads. o Increase in the provision for uncollectibles. o Increase in outside consultants expense due to e-commerce activities and information systems upgrades. o Increase in employee benefits expense due to increases in health insurance premiums and payments. A decrease in outside labor expense partially offset these increases in 2000. The information services area did not require 20 the use of outside labor in network services, outsourcing and Year 2000 preparation as in 1999. Depreciation expense increased from $44.1 million to $52.1 million over the three-year period 1999 to 2001 primarily due to growth in plant in service. General taxes decreased from $29.5 million to $24 million over the three-year period 1999 to 2001 primarily due to the elimination of North Carolina gross receipts taxes explained below. This decrease was partially offset by an increase in property taxes due to growth in plant in service. Effective July 1, 1999, for bills rendered after August 1, 1999, we began charging a new excise tax on piped natural gas used in North Carolina. This tax replaced the sales and use tax and gross receipts tax that were previously applicable to piped natural gas. The excise tax is calculated using a declining block rate structure applied to the number of therms delivered each month. The gross receipts tax was included in our gas rates billed to customers and therefore was in our operating revenues. Gross receipts tax expense in the same amount was also included in general taxes. The sales and use tax was not included in rates but was collected as a surcharge and remitted to the state with no impact on the income statement. The excise tax follows the previous sales and use tax treatment and is not included in revenues or expenses. This change impacts the comparability of revenues, margin (revenues less cost of gas) and general taxes for 1999 relative to all other periods. Other income, net of income taxes, was $10.9 million in 2001, compared with income of $11.3 million in 2000 and a loss of $1.1 million in 1999. Other income for 2000 includes $5.1 million from a business combination affecting our propane operations. Pro forma other income 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., 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 21 the limited partnership interest in Heritage Propane Partners. 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. Using the pro forma amount of $6.2 million noted above, other income for 2001 increased $4.7 million, compared with 2000, primarily due to the following reasons. o Increase in earnings from unregulated retail energy marketing services. o Increase in earnings from non-utility LNG operations. o Increase in interest income. o Increase in the portion of AFUDC attributable to equity. Also using the pro forma amount of $6.2 million, other income for 2000 increased $7.3 million, compared with 1999, primarily due to the following reasons. o Increase in earnings from unregulated retail energy marketing services. o Increase in earnings from non-utility LNG operations. o Increase in earnings from pipeline operations. These increases were partially offset by a decrease in the portion of AFUDC attributable to equity. Utility interest charges were $39.4 million in 2001, $37 million in 2000 and $32.4 million in 1999. Utility interest charges for 2001 increased $2.4 million, compared with 2000, primarily due to the following reasons. o Increase in interest on long-term debt due to higher balances outstanding. o Increase in interest charged on refunds due customers due to higher balances outstanding. These increases were partially offset by the following decreases. o Decrease in interest on short-term debt due to lower balances outstanding at lower interest rates. o Increase in the portion of AFUDC attributable to borrowed funds. Utility interest charges for 2000 increased $4.6 million, compared with 1999, primarily due to the following reasons. o Increase in interest on long-term debt due to higher balances outstanding. 22 o Increase in interest on short-term debt due to higher balances outstanding at slightly higher rates. These increases were partially offset by an increase in the portion of AFUDC attributable to borrowed funds. Environmental Matters We have owned, leased or operated manufactured gas plant (MGP) facilities at 12 sites in our three-state service area. In 1997, we entered into a settlement with a third party with respect to nine of these sites. At October 31, 2001, we had an undiscounted environmental liability of $1.4 million for the remaining three MGP sites not covered by the settlement. This liability is estimated based on the minimum of the range of a generic MGP site study as we have not performed site-specific evaluations and is not net of any related recoveries. Our three state regulatory commissions authorized us to utilize deferral accounting, or to create a regulatory asset, for expenditures made in connection with environmental matters. At October 31, 2001, we had a regulatory asset in the amount of $5.8 million, net of recoveries from customers, in connection with the settlement noted above and the estimated liability for the remaining sites and for other environmental costs, primarily legal fees and engineering assessments. The North Carolina portion of this asset is being amortized as recovered from customers over the three-year period beginning November 1, 2000. Further evaluations of the three remaining sites could 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, 2000, we adopted SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (FAS 140), which clarifies issues regarding securitizations of financial assets and special purpose entities and collateralizations of transferred financial assets. FAS 140 is effective for transfers after March 31, 2001, and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. The adoption of FAS 140 did not have a material effect on results of operations or financial position. Effective November 1, 2002, we will adopt SFAS No. 141, "Business Combinations" (FAS 141). With FAS 141, business combinations must be accounted for under the purchase method; the 23 pooling of interests method has been discontinued. FAS 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination and requires greater disclosure about a business combination. We believe the adoption of FAS 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" (FAS 142). FAS 142 provides new guidance for the accounting for the acquisition of intangibles (but not those acquired in a business combination) and the manner in which intangibles, including goodwill, should be accounted for subsequent to their initial recognition. We are currently evaluating the effects of FAS 142 but do not believe its adoption will 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" (FAS 143). FAS 143 establishes standards of accounting for an asset retirement obligation (ARO) arising from the acquisition, construction, development and operation of a long-lived asset. Rate-regulated entities must recognize a regulatory asset or liability for differences in the timing of period costs of AROs due to the ability to recover costs related to retirement of long-lived assets through rates charged to customers. We are currently evaluating the effects of FAS 143 and have formed no opinion as to its effect on financial position or results of operations. Effective November 1, 2002, we will adopt SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS 144). FAS 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. We are currently evaluating the effects of FAS 144 and have formed no opinion as to its 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. 24 Interest Rate Risk We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period, depending upon many factors, including our investments in capital projects. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels. At October 31, 2001, we had $32 million of short-term debt outstanding with a weighted average interest rate of 2.74%. We borrow primarily highly liquid debt instruments of a short-term nature and the carrying amount of such debt approximates fair value. The table below provides information about our long-term debt at October 31, 2001, that is sensitive to changes in interest rates. Expected Maturity Date ---------------------- Fair Value at There- October 31, 2002 2003 2004 2005 2006 after Total 2001 ---- ---- ---- ---- ---- ----- ----- ----------- (dollars in millions) Fixed Rate Long-term Debt $2 $47 $2 -- $35 $425 $511 $565 Average Interest Rate 10.06% 6.39% 10.06% -- 9.44% 7.55% 7.60% 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. Additional information concerning market risk is set forth in "Liquidity and Capital Resources" in Item 7 of this report on page 10. 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 56. 25 CONSOLIDATED BALANCE SHEETS October 31, 2001 and 2000 ASSETS In thousands 2001 2000 ---- ---- Utility Plant: Utility plant in service $1,569,774 $1,464,392 Less accumulated depreciation 511,477 462,955 ---------- ---------- Utility plant in service, net 1,058,297 1,001,437 Construction work in progress 56,402 69,570 ---------- ---------- Total utility plant, net 1,114,699 1,071,007 ---------- ---------- Other Physical Property, at cost (net of accumulated depreciation of $1,341 in 2001 and $1,187 in 2000) 1,163 976 ---------- ---------- Current Assets: Cash and cash equivalents 5,610 8,747 Restricted cash 7,064 39,796 Receivables (less allowance for doubtful accounts of $592 in 2001 and $482 in 2000) 25,898 55,145 Inventories: Gas in storage 70,220 67,709 Materials, supplies and merchandise 2,942 6,041 Deferred cost of gas 16,310 13,228 Refundable income taxes 22,271 69,118 Prepayments 24,986 24,451 ---------- ---------- Total current assets 175,301 284,235 ---------- ---------- Investments, Deferred Charges and Other Assets: Investments in non-utility activities, at equity 82,287 67,175 Unamortized debt expense (amortized over life of related debt on a straight-line basis) 4,130 3,938 Other 16,078 17,672 ---------- ---------- Total investments, deferred charges and other assets 102,495 88,785 ---------- ---------- Total $1,393,658 $1,445,003 ========== ========== See notes to consolidated financial statements. 26 CAPITALIZATION AND LIABILITIES In thousands 2001 2000 ---- ---- Capitalization: Stockholders' equity: Cumulative preferred stock - no par value - 175 shares authorized $ -- $ -- Common stock - no par value - 100,000 shares authorized; outstanding, 32,463 in 2001 and 31,914 in 2000 332,038 314,230 Retained earnings 229,718 213,142 Accumulated other comprehensive income (1,377) -- ----------- ---------- Total stockholders' equity 560,379 527,372 Long-term debt 509,000 451,000 ----------- ---------- Total capitalization 1,069,379 978,372 ----------- ---------- Current Liabilities: Current maturities of long-term debt and sinking fund requirements 2,000 32,000 Notes payable 32,000 99,500 Accounts payable 41,144 88,313 Customers' deposits 9,487 9,110 Deferred income taxes 2,344 8,678 General taxes accrued 14,544 11,205 Refunds due customers 31,685 32,889 Other 16,023 16,011 ----------- ---------- Total current liabilities 149,227 297,706 ----------- ---------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 143,211 145,070 Unamortized federal investment tax credits 6,149 6,707 Other 25,692 17,148 ----------- ---------- Total deferred credits and other liabilities 175,052 168,925 ----------- ---------- Total $ 1,393,658 $1,445,003 =========== ========== See notes to consolidated financial statements. 27 STATEMENTS OF CONSOLIDATED INCOME For the Years Ended October 31, 2001, 2000 and 1999 In thousands except per share amounts 2001 2000 1999 ---- ---- ---- Operating Revenues $ 1,107,856 $ 830,377 $ 686,470 Cost of Gas 769,878 512,046 365,962 ----------- --------- --------- Margin 337,978 318,331 320,508 ----------- --------- --------- Other Operating Expenses: Operations 114,358 109,942 101,263 Maintenance 19,064 17,059 15,562 Depreciation 52,060 48,894 44,131 General taxes 23,952 18,761 29,465 Income taxes 34,575 33,975 38,365 ----------- --------- --------- Total other operating expenses 244,009 228,631 228,786 ----------- --------- --------- Operating Income 93,969 89,700 91,722 ----------- --------- --------- Other Income (Expense): Non-utility activities, at equity 15,322 17,403 (5,052) Allowance for equity funds used during construction 1,767 -- 1,434 Other, net 1,141 1,260 1,754 Income taxes (7,300) (7,381) 720 ----------- --------- --------- Total other income (expense) 10,930 11,282 (1,144) ----------- --------- --------- Income Before Utility Interest Charges 104,899 100,982 90,578 ----------- --------- --------- Utility Interest Charges: Interest on long-term debt 37,789 33,890 31,005 Allowance for borrowed funds used during construction (4,910) (3,321) (2,027) Other 6,535 6,382 3,393 ----------- --------- --------- Total utility interest charges 39,414 36,951 32,371 ----------- --------- --------- Net Income $ 65,485 $ 64,031 $ 58,207 =========== ========= ========= Average Shares of Common Stock: Basic 32,183 31,600 31,013 Diluted 32,420 31,779 31,242 Earnings Per Share of Common Stock: Basic $ 2.03 $ 2.03 $ 1.88 Diluted $ 2.02 $ 2.01 $ 1.86 See notes to consolidated financial statements. 28 STATEMENTS OF CONSOLIDATED CASH FLOWS For the Years Ended October 31, 2001, 2000 and 1999
In thousands 2001 2000 1999 ---- ---- ---- Cash Flows from Operating Activities: Net income $ 65,485 $ 64,031 $ 58,207 --------- --------- --------- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 53,069 52,090 47,917 Deferred income taxes (8,193) 14,612 12,918 Amortization of investment tax credits (558) (558) (558) Allowance for funds used during construction (6,677) (3,321) (3,461) Net gain on propane business combination, net of tax -- (5,063) -- Changes in assets and liabilities: Restricted cash 32,732 360 (12,672) Receivables 29,247 (22,677) (7,647) Receivables from affiliate -- 22,354 (22,354) Inventories 588 (18,553) (6,841) Other assets, net 30,169 (70,596) (23,832) Accounts payable (47,169) 23,719 (4,180) Refunds due customers (1,204) 6,685 (2,204) Other liabilities, net 12,916 (8,433) (3,692) --------- --------- --------- Total adjustments 94,920 (9,381) (26,606) --------- --------- --------- Net cash provided by operating activities 160,405 54,650 31,601 --------- --------- --------- Cash Flows from Investing Activities: Utility construction expenditures (83,536) (105,329) (98,576) Investment in propane partnership -- (30,552) -- Proceeds from propane business combination -- 36,748 -- Other (6,986) (909) (1,643) --------- --------- --------- Net cash used in investing activities (90,522) (100,042) (100,219) --------- --------- --------- Cash Flows from Financing Activities: Increase (Decrease) in bank loans, net (67,500) 20,000 47,500 Proceeds from issuance of long-term debt 60,000 60,000 90,000 Retirement of long-term debt (32,000) (2,000) (46,000) Issuance of common stock through dividend reinvestment and employee stock plans 15,389 15,452 15,740 Dividends paid (48,909) (45,487) (42,168) --------- --------- --------- Net cash provided by (used in) financing activities (73,020) 47,965 65,072 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (3,137) 2,573 (3,546) Cash and Cash Equivalents at Beginning of Year 8,747 6,174 9,720 --------- --------- --------- Cash and Cash Equivalents at End of Year $ 5,610 $ 8,747 $ 6,174 ========= ========= ========= Cash Paid During the Year for: Interest $ 39,977 $ 34,971 $ 32,647 Income taxes $ 51,430 $ 85,848 $ 38,983
See notes to consolidated financial statements. 29 STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY For the Years Ended October 31, 2001, 2000 and 1999
Accumulated Other Common Retained Comprehensive In thousands except per share amounts Stock Earnings Income Total ------ -------- ------ ----- Balance, October 31, 1998 $ 279,709 $ 178,559 $ -- $ 458,268 Net Income 58,207 58,207 Common Stock Issued 17,440 17,440 Dividends Declared ($1.36 per share) (42,168) (42,168) --------- --------- -------- --------- Balance, October 31, 1999 297,149 194,598 -- 491,747 Net Income 64,031 64,031 Common Stock Issued 17,081 17,081 Dividends Declared ($1.44 per share) (45,487) (45,487) --------- --------- -------- --------- Balance, October 31, 2000 314,230 213,142 -- 527,372 --------- Comprehensive Income: Net Income 65,485 65,485 Other Comprehensive Income: Equity investments hedging activities, net of tax of ($856) (1,377) (1,377) --------- Total Comprehensive Income 64,108 Common Stock Issued 17,808 17,808 Dividends Declared ($1.52 per share) (48,909) (48,909) --------- --------- -------- --------- Balance, October 31, 2001 $ 332,038 $ 229,718 $ (1,377) $ 560,379 ========= ========= ======== =========
See notes to consolidated financial statements. 30 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies A. Operations and Principles of Consolidation. Piedmont Natural Gas Company, Inc., is an investor-owned public utility primarily engaged in the sale and transportation of natural gas to residential, commercial and industrial customers in the Piedmont region of North Carolina and South Carolina and the metropolitan Nashville, Tennessee, area. Piedmont Energy Partners, Inc., is a wholly owned subsidiary that is a holding company for various other wholly owned non-utility subsidiaries. The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in non-utility activities are accounted for under the equity method. Under the equity method, our ownership interest in each entity is recorded in investments in non-utility activities, at equity, in the consolidated balance sheets. Our ownership percentage is applied to each entity's earnings or losses and is recorded in non-utility activities, at equity, in other income in the statements of consolidated income. Revenues and expenses of all other non-utility activities are included in other, net in other income in the statements of consolidated income. Significant inter-company transactions have been eliminated in consolidation where appropriate. We have not eliminated inter-company profit on sales to affiliates in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting For The Effects of Certain Types of Regulation" (FAS 71). B. Utility Plant and Depreciation. Utility plant is stated at original cost, including direct labor and materials, allocable overheads and an allowance for borrowed and equity funds used during construction (AFUDC). AFUDC totaled $6,677,000 for 2001, $3,321,000 for 2000 and $3,461,000 for 1999. The portion of AFUDC attributable to equity funds is in other income in the statements of consolidated income, and the portion attributable to borrowed funds is shown as a reduction of utility interest charges. The costs of property retired are removed from utility plant and such costs, including removal costs net of salvage, are charged to accumulated depreciation. We compute depreciation expense using the straight-line method. The composite weighted-average depreciation rates were 3.45% for 2001, 3.49% for 2000 and 3.38% for 1999. We review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Our reviews have not resulted in a material effect on results of operations or financial condition. 31 C. Inventories. We maintain inventories on the basis of the average cost charged thereto. D. Deferred Purchased Gas Adjustment. Rate schedules include purchased gas adjustment provisions that permit the recovery of gas costs. We periodically revise rates without formal rate proceedings to reflect changes in the cost of gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are added to or deducted from cost of gas and included in refunds due customers in the consolidated balance sheets. E. Income Taxes. We provide deferred income taxes for differences between the book and tax basis of assets and liabilities, principally attributable to accelerated tax depreciation and the timing of the recording of revenues and cost of gas. We amortize deferred investment tax credits to income over the estimated useful life of the related property. F. Operating Revenues. We recognize revenues from meters read on a monthly cycle basis which results in unrecognized revenue from the cycle date through month end. We defer the cost of gas for volumes delivered to customers but not yet billed under the cycle-billing method. G. Earnings Per Share. We compute basic earnings per share using the weighted average number of shares of Common Stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the years ended October 31, 2001, 2000 and 1999, is presented below: In thousands except per share amounts 2001 2000 1999 ---- ---- ---- Net Income $65,485 $64,031 $58,207 ======= ======= ======= Average shares of Common Stock outstanding for basic earnings per share 32,183 31,600 31,013 Contingently issuable shares under the Long-Term Incentive Plan 237 179 229 ------ ------ ------ Average shares of dilutive stock 32,420 31,779 31,242 ====== ====== ====== Earnings Per Share: Basic $ 2.03 $ 2.03 $ 1.88 Diluted $ 2.02 $ 2.01 $ 1.86 H. Rate-Regulated Basis of Accounting. FAS 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In 32 applying FAS 71, we have capitalized certain costs and benefits as regulatory assets and liabilities, respectively, pursuant to orders of the state utility regulatory commissions, either in general rate proceedings or expense deferral proceedings, in order to provide for recovery of or refunds to utility customers in future periods. We monitor the regulatory and competitive environment in which we operate to determine that our regulatory assets continue to be probable of recovery. If we, at some point in the future, determine that all or a portion of these regulatory assets no longer meet the criteria for continued application of FAS 71, we would write off that portion which we could not recover, net of any regulatory liabilities which would be deemed no longer necessary. The amounts recorded as regulatory assets and liabilities in the consolidated balance sheets at October 31, 2001 and 2000, are summarized as follows: In thousands 2001 2000 ---- ---- Regulatory Assets: Unamortized debt expense $ 4,130 $ 3,938 Environmental 5,767 6,959 Deferred taxes -- 9,990 Demand-side management costs 5,382 4,676 Deferred Year 2000 costs 391 603 Deferred pension expense 745 948 Other 2,163 2,519 ------- ------- Total $18,578 $29,633 ======= ======= Regulatory Liabilities: Refunds due customers $31,685 $32,889 Deferred taxes 13,037 -- Deferred incentive plan -- 507 ------- ------- Total $44,722 $33,396 ======= ======= I. Statement of Cash Flows. For purposes of reporting cash flows, we consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. J. Other Recently Issued Accounting Standards. Effective November 1, 2000, we adopted SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (FAS 140), which clarifies issues regarding securitizations of financial assets and special purpose entities and collateralizations of transferred financial assets. FAS 140 is effective for transfers after March 31, 2001, and for disclosures relating to securitization transactions and collateral for fiscal years ending after December 15, 2000. The adoption of FAS 140 did not have a material effect on results of operations or financial position. 33 Effective November 1, 2002, we will adopt SFAS No. 141, "Business Combinations" (FAS 141). With FAS 141, business combinations must be accounted for under the purchase method; the pooling of interests method has been discontinued. FAS 141 also establishes new rules for recognizing intangible assets resulting from a purchase business combination and requires greater disclosure about a business combination. We believe the adoption of FAS 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" (FAS 142). FAS 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 accounted for subsequent to their initial recognition. We are currently evaluating the effects of FAS 142 but do not believe its adoption will 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" (FAS 143). FAS 143 establishes standards of accounting for an asset retirement obligation (ARO) arising from the acquisition, construction, development and operation of a long-lived asset. Rate-regulated entities must recognize a regulatory asset or liability for differences in the timing of period costs of AROs due to the ability to recover costs related to retirement of long-lived assets through rates charged to customers. We are currently evaluating the effects of FAS 143 and have formed no opinion as to its effect on financial position or results of operations. Effective November 1, 2002, we will adopt SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS 144). FAS 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. We are currently evaluating the effects of FAS 144 and have formed no opinion as to its effect on financial position or results of operations. K. Use of Estimates. We make estimates and assumptions when preparing the consolidated financial statements. Those estimates and assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. L. Reclassifications. We have reclassified certain financial statement items for 2000 and 1999 to conform with the 2001 presentation. 34 2. Regulatory Matters 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. 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 and approved initial funding with supplier refunds due customers. The NCUC decides the use of these funds as we file individual project applications for unserved areas. From August 2000 through September 2001, we received $38,527,000 from the expansion fund to extend natural gas service to the counties of Avery, Mitchell and Yancey. As of October 31, 2001, the North Carolina State Treasurer held $5,579,000 in our expansion fund account. This amount along with other supplier refunds, including interest earned to date, is included in restricted cash in the consolidated balance sheets. Effective January 1, 2001, we purchased 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 $6,600,000 and added 5,400 customers and $1,475,000 of margin to our operations. 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 $1,290,000. The NCUC did not approve our request but stated that we could seek recovery of the gas cost portion of these excess write-offs in our next annual gas cost review proceeding. 35 3. Long-Term Debt Long-term debt at October 31, 2001 and 2000, is summarized as follows: In thousands 2001 2000 ---- ---- Senior Notes: 9.19%, due 2001 $ -- $ 30,000 10.06%, due 2004 6,000 8,000 9.44%, due 2006 35,000 35,000 8.51%, due 2017 35,000 35,000 Medium-Term Notes: 6.23%, due 2003 45,000 45,000 7.35%, due 2009 30,000 30,000 7.80%, due 2010 60,000 60,000 6.55%, due 2011 60,000 -- 6.87%, due 2023 45,000 45,000 8.45%, due 2024 40,000 40,000 7.40%, due 2025 55,000 55,000 7.50%, due 2026 40,000 40,000 7.95%, due 2029 60,000 60,000 -------- -------- Total 511,000 483,000 Less current maturities 2,000 32,000 -------- -------- Total $509,000 $451,000 ======== ======== Annual sinking fund requirements and maturities through 2006 are $2,000,000 in 2002, $47,000,000 in 2003, $2,000,000 in 2004, zero in 2005 and $35,000,000 in 2006. On September 26, 2001, we issued $60,000,000 of 6.55% medium-term notes under a shelf registration statement for $250,000,000 of debt and equity securities that was filed with the Securities and Exchange Commission in June 2001. The note is to be redeemed in a single payment at maturity in 2011. 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, 2001, all retained earnings were free of such restrictions. 4. Capital Stock The changes in Common Stock for the years ended October 31, 1999, 2000 and 2001, are summarized as follows: 36 In thousands Shares Amount ------ ------ Balance, October 31, 1998 30,738 $279,709 Issue to participants in the Employee Stock Purchase Plan (SPP) 26 777 Issue to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 479 14,963 Issue to participants in the Long-Term Incentive Plan (LTIP) 52 1,700 ------ -------- Balance, October 31, 1999 31,295 297,149 Issue to SPP 20 517 Issue to DRIP 548 14,935 Issue to LTIP 51 1,629 ------ -------- Balance, October 31, 2000 31,914 314,230 Issue to SPP 16 476 Issue to DRIP 461 14,913 Issue to LTIP 72 2,419 ------ -------- Balance, October 31, 2001 32,463 $332,038 ====== ======== At October 31, 2001, 2,102,000 shares of Common Stock were reserved for issuance as follows: SPP 165,000 DRIP 1,119,000 LTIP 818,000 --------- Total 2,102,000 ========= 5. Financial Instruments and Related Fair Value Various banks provide lines of credit totaling $150,000,000 to finance current cash requirements. Additional lines are also available on an as needed, if available, basis. Short-term borrowings under the lines, with maturity dates of less than 90 days, include open-ended loans based on the Federal Reserve funds rate, 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. At October 31, 2001, the lines of credit were on a fee basis. At October 31, 2001, outstanding notes payable consisted of $22,500,000 in LIBOR cost-plus loans and $9,500,000 in overnight cost-plus loans. The weighted average interest rate on such borrowings was 2.74%. Our principal business activity is the distribution of natural gas to customers located in North Carolina, South Carolina and Tennessee. At October 31, 2001, gas receivables totaled $23,144,000 and other receivables totaled $3,346,000. The uncollected balance of installment receivables that were transferred with recourse to a third party was $17,184,000 and $18,699,000 at October 31, 2001 and 2000, respectively. We have provided an adequate allowance for any receivables which may not be ultimately collected, including the receivables transferred with recourse. 37 During 1999 and 2000, Piedmont Energy Company, a wholly owned subsidiary which is a member of SouthStar Energy Services LLC (SouthStar), made loans to SouthStar in accordance with a loan agreement between SouthStar and its members. Loans were funded by the members based on ownership percentage and our loans were limited to $22,500,000. Interest was charged on the outstanding principal balance of each loan. In October 2000, SouthStar repaid all outstanding loans plus interest, less $7,500,000 which was retained as a capital contribution. During the years ended October 31, 2000 and 1999, Piedmont Energy received $1,852,000 and $265,000, respectively, in interest income on the loans. Effective August 2000, the members of SouthStar entered into a capital contributions agreement which requires each member to contribute additional capital for SouthStar to pay invoices for goods or services provided from any entity affiliated as a member whenever funds are not available to pay these invoices. The capital contributions to pay affiliated invoices will be repaid as funds become available, but are subordinate to SouthStar's revolving line of credit with a bank. During 2001, we contributed $13,800,000 under this agreement, of which $6,000,000 was repaid. The carrying amounts in the consolidated balance sheets of cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximate their fair values due to the short-term maturities of these financial instruments. Based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings, the estimated fair values of long-term debt at October 31, 2001 and 2000, including current portion, were as follows: 2001 2000 ----------------- ------------------ Carrying Fair Carrying Fair In thousands Amount Value Amount Value -------- ----- -------- ----- Long-term debt $511,000 $565,161 $483,000 $480,092 The use of different market assumptions or estimation methodologies could have a material effect on the estimated fair values. The fair value amounts are not intended to reflect principal amounts that we will ultimately be required to pay. Effective November 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging Activities." Adoption did not have a material impact on our financial condition or results of operations. We purchase natural gas for our regulated operations for resale under tariffs approved by the state commissions having jurisdiction over the service territory where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas adjustment mechanisms. We structure the pricing and performance of gas supply contracts to 38 maximize flexibility and minimize cost and risk for the customer. Our risk management policies allow us to use financial instruments for trading purposes and to hedge risks. For the year ended October 31, 2001, we purchased financial call options for natural gas for delivery in December 2001 and January 2002 for our Tennessee gas purchase portfolio. The cost of these options and all gas costs incurred become a component of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark rates. These differences, after applying a monthly 1% positive or negative deadband, together with income from marketing transportation and capacity in the secondary market and income (margin) from secondary market sales of gas, are subject to an overall annual cap of $1,600,000 for shareholder gains or losses. The net gains or losses on gas procurement costs within the deadband (99%-101% of the benchmark) are not subject to sharing under the Incentive Plan. Any net gains or losses on gas procurement costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders. This amount is subject to the overall annual cap and is placed in a regulatory asset to be surcharged or refunded to customers. 6. Employee Benefit Plans We have a defined-benefit pension plan for the benefit of substantially all full-time regular employees. Plan benefits are generally based on credited years of service and the level of compensation during the five consecutive years of the last ten years prior to retirement during which the participant received the highest compensation. Our policy is to fund the plan in an amount not in excess of the amount that is deductible for income tax purposes. Plan assets consist primarily of marketable securities and cash equivalents. We amend the plan from time to time in accordance with changes in tax law. We provide certain postretirement health care and life insurance benefits to substantially all full-time regular employees. The liability associated with such benefits is funded in irrevocable trust funds which can only be used to pay the benefits. A reconciliation of the changes in the plans' benefit obligations and fair value of assets for the years ended October 31, 2001 and 2000, and a statement of the funded status as recognized in the consolidated balance sheets at October 31, 2001 and 2000, are presented below: 39
2001 2000 2001 2000 ---- ---- ---- ---- In thousands Pension Benefits Other Benefits ---------------- -------------- Change in benefit obligation: Obligation at beginning of year $ 122,712 $ 115,593 $ 21,868 $ 23,972 Service cost 4,890 5,203 573 581 Interest cost 9,279 9,040 1,636 1,793 Plan amendments -- 4,433 -- -- Curtailment gain -- (1,938) -- (48) Actuarial (gain) loss 18,056 (449) 3,235 (2,741) Benefit payments (6,926) (9,170) (2,325) (1,689) --------- --------- -------- -------- Obligation at end of year $ 148,011 $ 122,712 $ 24,987 $ 21,868 ========= ========= ======== ======== Change in fair value of plan assets: Fair value of plan assets at beginning of year $ 161,034 $ 161,915 $ 10,355 $ 8,574 Actual return (loss) on plan assets (18,127) 8,289 484 534 Employer contributions -- -- 2,110 2,332 Benefit payments (6,926) (9,170) (1,740) (1,085) --------- --------- -------- -------- Fair value of plan assets at end of year $ 135,981 $ 161,034 $ 11,209 $ 10,355 ========= ========= ======== ======== Funded status: Funded status at end of year $ (12,030) $ 38,322 $(13,777) $(11,513) Unrecognized transition obligation 27 41 10,550 11,429 Unrecognized prior-service cost 6,519 7,281 -- -- Unrecognized (gain) loss (225) (52,549) 2,887 (701) --------- --------- -------- -------- Accrued benefit liability $ (5,709) $ (6,905) $ (340) $ (785) ========= ========= ======== ========
Net periodic benefit cost for the years ended October 31, 2001, 2000 and 1999, includes the following components:
2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- In thousands Pension Benefits Other Benefits ---------------- -------------- Service cost $ 4,890 $ 5,203 $ 5,388 $ 573 $ 581 $ 648 Interest cost 9,278 9,040 7,309 1,636 1,793 1,443 Expected return on plan assets (14,359) (13,488) (12,079) (839) (568) (497) Amortization of transition obligation 14 15 15 879 930 930 Amortization of prior-service cost 762 824 543 -- -- -- Curtailment expense -- -- -- -- 660 -- Amortization of net (gain) loss (1,781) (1,651) (959) -- 42 232 -------- -------- -------- ------- ------- ------- Net periodic benefit cost $ (1,196) $ (57) $ 217 $ 2,249 $ 3,438 $ 2,756 ======== ======== ======== ======= ======= =======
40 The curtailment gain included in the 2000 accumulated pension and postretirement health care benefit obligation and the curtailment expense included in net periodic health care benefit cost were a result of the contribution of substantially all of Piedmont Propane Company's assets in exchange for a partnership interest in Heritage Propane Partners, L.P., as discussed in Note 8. We amortize unrecognized prior-service cost over the average remaining service period for active employees. We amortize the unrecognized net transition obligation over the average remaining service period for active employees expected to receive benefits under the plan as of the date of transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation and the market-related value of assets over the average remaining service period of active employees. The method of amortization in all cases is straight-line. The weighted average assumptions used in the measurement of the benefit obligation at October 31, 2001, 2000 and 1999, are presented below: 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- Pension Benefits Other Benefits ---------------- -------------- Discount rate 6.75% 7.5% 7.5% 7.0% 7.75% 7.75% Expected long-term rate of return on plan assets 9.5% 9.5% 9.5% 9.25% 9.5% 9.5% Rate of compensation increase 4.75% 5.5% 5.5% 4.5% 4.5% 4.5% The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation for the medical plans for participants aged less than 65 are 13% for 2001 and 11.5% for 2002, declining gradually to 4.25% in 2011 and remaining at that level thereafter. For those participants aged greater than 65, the assumed health care cost trend rates are 16% for 2001 and 14.5% for 2002, declining gradually to 4.25% in 2014 and remaining at that level thereafter. The health care cost trend rate assumptions have a significant effect on the amounts reported. A one-percentage point change in the assumed health care cost trend rates would have the following effects: In thousands 1% Increase 1% Decrease ----------- ----------- Effect on total of service and interest cost components of net periodic postretirement health care benefit cost for the year ended October 31, 2001 $ 79 $ (70) Effect on the health care component of the accumulated postretirement benefit obligation as of October 31, 2001 $1,275 $(1,130) 41 We maintain salary investment plans which are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), which include qualified cash or deferred arrangements under Tax Code Section 401(k). Employees who have completed six months of service are eligible to participate. Participants are permitted to defer a portion of their base salary to the plans and we match a portion of the participants' contributions. All contributions vest immediately. For the years ended October 31, 2001, 2000 and 1999, we contributed $2,189,000, $2,273,000 and $2,298,000, respectively, in matching contributions to the plans. 7. Income Taxes The components of income tax expense for the years ended October 31, 2001, 2000 and 1999, are as follows:
2001 2000 1999 ---- ---- ---- In thousands Federal State Federal State Federal State ------- ----- ------- ----- ------- ----- Income taxes charged to operations: Current $ 23,959 $4,558 $ 21,675 $4,615 $ 28,005 $ 5,972 Deferred 4,933 1,683 6,784 1,459 4,071 875 Amortization of investment tax credits (558) -- (558) -- (558) -- -------- ------ -------- ------ -------- ------- Total 28,334 6,241 27,901 6,074 31,518 6,847 -------- ------ -------- ------ -------- ------- Income taxes charged to other income: Current 4,685 1,036 829 183 (591) (129) Deferred 1,299 280 5,242 1,127 -- -- -------- ------ -------- ------ -------- ------- Total 5,984 1,316 6,071 1,310 (591) (129) -------- ------ -------- ------ -------- ------- Total income tax expense $ 34,318 $7,557 $ 33,972 $7,384 $ 30,927 $ 6,718 ======== ====== ======== ====== ======== =======
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2001, 2000 and 1999, is as follows: In thousands 2001 2000 1999 ---- ---- ---- Federal taxes at 35% $ 37,576 $ 36,892 $ 33,566 State income taxes, net of federal benefit 4,912 4,800 4,367 Amortization of investment tax credits (558) (558) (558) Other, net (55) 222 270 -------- -------- -------- Total income tax expense $ 41,875 $ 41,356 $ 37,645 ======== ======== ======== At October 31, 2001 and 2000, deferred income taxes consist of the following temporary differences: 42 In thousands 2001 2000 ---- ---- Excess of utility tax over book depreciation and tax and book asset basis differences $ 139,481 $133,338 Revenues and cost of gas 9,839 14,526 Other, net (3,765) 5,884 --------- -------- Net deferred income taxes $ 145,555 $153,748 ========= ======== Total deferred income tax liabilities were $154,950,000 and $159,975,000 and total deferred income tax assets were $9,395,000 and $6,227,000 at October 31, 2001 and 2000, respectively. 8. Business Segments and Non-Utility Activities Business Segments We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Operations of our domestic natural gas distribution segment are conducted by the parent company and by limited liability companies of which two wholly owned subsidiaries of our wholly owned subsidiary, Piedmont Energy Partners, are members. Operations of our retail energy marketing services segment are conducted by a limited liability company of which a wholly owned subsidiary of Piedmont Energy Partners is a member. Our activities included in Other in the segment tables consist primarily of propane operations conducted by a master limited partnership of which a wholly owned subsidiary of Piedmont Energy Partners has an equity interest. All of our activities other than the utility operations of the parent are included in other income in the statements of consolidated income. Our domestic natural gas distribution business is operated and managed in three strategic business units and is organized based on products and services and regulatory environments. This business is conducted through the following three companies: o Piedmont Natural Gas Company, the parent company, is primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in the Piedmont region of North Carolina and South Carolina and the metropolitan Nashville, Tennessee, area. o Piedmont Intrastate Pipeline Company, a wholly owned subsidiary of Piedmont Energy Partners, is a 16.45% member of Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina. Prior to November 1, 1999, our investment in Cardinal was treated as utility assets for ratemaking purposes and we included our share of the assets and operations of Cardinal in utility operations. Effective November 1, 1999, with the completion of an extension of the pipeline, the NCUC began 43 regulating Cardinal and we began accounting for our share of its operations in non-utility activities. o Piedmont Interstate Pipeline Company, a wholly owned subsidiary of Piedmont Energy Partners, is a 35% member of Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns a liquefied natural gas (LNG) peak-demand facility in North Carolina. Our retail energy marketing services segment is conducted through Piedmont Energy Company, a wholly owned subsidiary of Piedmont Energy Partners. Piedmont Energy has a 30% equity interest in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar offers a combination of unregulated energy products and services to industrial, commercial and residential customers in the southeastern United States. The accounting policies of our reportable segments are described in the summary of significant accounting policies in Note 1. We evaluate performance based on margin, operations and maintenance expenses, operating income and income before taxes. All of our operations are within the United States. No single customer's revenues exceed 10% of our consolidated revenues. Included in Other in the segment tables are the activities of Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners. Piedmont Propane owns 20.69% of the membership interest in US Propane, L.P. US Propane was formed in 2000 to combine our propane operations with the propane operations of three other companies. In August 2000, US Propane combined with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P., by contributing all of its assets to Heritage Holdings for $181,395,000 in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage Holdings for $120,000,000. This combination, including a gain on the transfer of the propane assets, transaction costs and certain employee benefit plans' gains and charges, resulted in $5,063,000 of net income, or earnings per share of $.16, in 2000. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners. Continuing operations by segment for the years ended October 31, 2001, 2000 and 1999, are presented below: 44 Domestic Retail Natural Gas Energy In thousands Distribution Marketing Other Total ------------ --------- ----- ----- 2001 - ---- Revenues from external customers $1,107,856 $ -- $ -- $1,107,856 Margin 337,978 -- (264) 337,714 Operations and maintenance expenses 133,422 37 277 133,736 Depreciation and amortization 52,060 -- 5 52,065 Operating income 93,944 (29) (493) 93,422 Interest expense 39,414 465 -- 39,879 Other income 8,611 9,021 1,552 19,184 Income before income taxes 97,750 8,526 1,084 107,360 Total assets 1,384,952 24,717 27,050 1,436,719 Capital expenditures 90,573 -- -- 90,573 2000 - ---- Revenues from external customers $ 830,377 $ -- $29,967 $ 860,344 Margin 318,331 (9) 11,926 330,248 Operations and maintenance expenses 127,004 6 8,998 136,008 Depreciation and amortization 48,894 -- 1,744 50,638 Operating income 90,971 (34) 651 91,588 Interest expense 40,272 358 340 40,970 Other income 9,863 1,200 8,859 19,922 Income before income taxes 93,258 2,732 9,397 105,387 Total assets 1,437,950 9,055 34,959 1,481,964 Capital expenditures 108,804 -- 755 109,559 1999 - ---- Revenues from external customers $ 686,470 $ 1 $28,249 $ 714,720 Margin 320,508 29 13,867 334,404 Operations and maintenance expenses 116,825 4 9,054 125,883 Depreciation and amortization 44,131 -- 2,133 46,264 Operating income 91,706 18 2,028 93,752 Interest expense 32,371 36 407 32,814 Other income 4,915 (8,951) 109 (3,927) Income before income taxes 102,657 (8,680) 1,875 95,852 Total assets 1,304,453 21,629 38,368 1,364,450 Capital expenditures 102,235 -- 1,429 103,664 A reconciliation to the consolidated financial statements for the years ended October 31, 2001, 2000 and 1999, is presented below: 45 In thousands 2001 2000 1999 ---- ---- ---- Consolidated Revenues (1): Revenues for reportable segments $ 1,107,856 $ 830,377 $ 686,471 =========== =========== =========== Net Income: Income before income taxes for reportable segments $ 106,276 $ 95,990 $ 93,977 Income before income taxes for other non-utility activities 1,084 9,397 1,875 Income taxes 41,875 41,356 37,645 ----------- ----------- ----------- Net income $ 65,485 $ 64,031 $ 58,207 =========== =========== =========== Consolidated Assets: Total assets for reportable segments $ 1,409,669 $ 1,447,005 $ 1,326,082 Other assets 27,050 34,959 38,368 Eliminations/Adjustments (43,061) (36,961) (75,793) ----------- ----------- ----------- Consolidated assets $ 1,393,658 $ 1,445,003 $ 1,288,657 =========== =========== =========== (1) Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. Risks of Equity Investments Piedmont Intrastate -- Cardinal is regulated by the NCUC. Cardinal has long-term service agreements with local distribution companies for 100% of the 270 million cubic feet per day of firm transportation capacity on the pipeline. Cardinal is dependent on the interstate pipeline company serving North Carolina to deliver gas into its system for service to these companies. Cardinal's long-term debt is secured by an interest in Cardinal's contracts and by pledges of the equity membership interests. Piedmont Interstate -- Pine Needle is regulated by the Federal Energy Regulatory Commission. 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 long-term 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. The members of Pine Needle have pledged their membership interests as a guarantee of Pine Needle's long-term debt. Pine Needle has also pledged to the lender all its rights in long-term contracts to buy natural gas. Piedmont Propane -- Heritage Propane Partners is a marketer of propane through a nationwide retail distribution network in 29 states. Heritage 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 purchases propane at numerous supply 46 points for delivery to Heritage primarily via railroad tank cars and common carrier transport. Heritage's profitability is sensitive to changes in the wholesale price of propane. Heritage utilizes hedging transactions to provide price protection against significant fluctuations in prices. Piedmont Energy -- SouthStar was formed and began marketing energy services in Georgia in 1998 when that state became the first in the Southeast to fully open to retail competition. After three years of deregulation, a study committee has been appointed to reevaluate the deregulation of the Georgia natural gas market. Some of the proposals could have a substantial impact on the business and earnings of SouthStar. We do not have sufficient information to permit us to predict the outcome of this study or any legislation or regulation that may result from the study. SouthStar manages commodity price risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. Related Party Transactions The utility has related party transactions with three of its subsidiaries and their investees that result in either gas sales or gas costs. The utility records as gas costs the fixed storage cost charged by Pine Needle. These accrued gas costs were $11,266,000, $10,581,000 and $5,080,000 in 2001, 2000 and 1999, respectively. We owed Pine Needle $920,000 and $957,000 at October 31, 2001 and 2000, respectively. The utility records as gas costs demand charges to Cardinal as determined by the NCUC. These accrued gas costs were $1,475,000 in 2001 and 2000. We owed Cardinal $123,000 at October 31, 2001 and 2000. The utility sells gas to SouthStar at prevailing market rates. Operating revenues from these sales totaled $12,192,000, $8,680,000 and $23,016,000 in 2001, 2000 and 1999, respectively. SouthStar owed us $1,015,000, $36,900 and $2,488,000 at October 31, 2001, 2000 and 1999, respectively. 9. Environmental Matters We have owned, leased or operated manufactured gas plant (MGP) facilities at 12 sites in our three-state service area. In 1997, we entered into a settlement with a third party with respect to nine of these sites. At October 31, 2001, we had an undiscounted environmental liability of $1,360,000 for the remaining three MGP sites not covered by the settlement. This liability is estimated based on the minimum of the range of a 47 generic MGP site study as we have not performed site-specific evaluations and is not net of any related recoveries. Our three state regulatory commissions authorized us to utilize deferral accounting, or to create a regulatory asset, for expenditures made in connection with environmental matters. At October 31, 2001, we had a regulatory asset in the amount of $5,767,000, net of recoveries from customers, in connection with the settlement noted above and the estimated liability for the remaining sites and for other environmental costs, primarily legal fees and engineering assessments. The North Carolina portion of this asset is being amortized as recovered from customers over the three-year period beginning November 1, 2000. Further evaluations of the three remaining sites could 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. 48 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The management of Piedmont Natural Gas Company is responsible for the preparation and integrity of the accompanying consolidated financial statements and related notes. We prepared the statements in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and included amounts which are necessarily based on our best estimates and judgments made with due consideration to materiality. Financial information presented elsewhere in this report is consistent with that in the consolidated financial statements. We have established and are responsible for maintaining a comprehensive system of internal accounting controls which we believe provides reasonable assurance that policies and procedures are complied with, assets are safeguarded and transactions are executed according to management's authorization. We continually review this system for effectiveness and modify it in response to changing business conditions and operations and as a result of recommendations by internal and external auditors. The Audit Committee of the Board of Directors, consisting solely of outside Directors, meets periodically with Deloitte & Touche LLP, the internal auditors and representatives of management to discuss auditing and financial reporting matters. The Audit Committee reviews audit plans and results and accounting, financial reporting and internal control practices, procedures and results. Both Deloitte & Touche LLP and the internal auditors have full and free access to all levels of management. /s/ Barry L. Guy - ----------------------------- Barry L. Guy Vice President and Controller 49 INDEPENDENT AUDITORS' REPORT Piedmont Natural Gas Company, Inc. We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc. and subsidiaries (the Company) as of October 31, 2001 and 2000, and the related statements of consolidated income, stockholders' equity and cash flows for each of the three years in the period ended October 31, 2001. Our audits also included the supplemental consolidated financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at October 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. /s/ DELOITTE & TOUCHE LLP Charlotte, North Carolina December 7, 2001 50 QUARTERLY FINANCIAL DATA (Unaudited) (In thousands except per share amounts) Earnings Per Share of Common Stock Operating Operating Net ------------ Revenues Margin Income Income Basic Diluted -------- ------ ------ ------ ----- ------- 2001 January 31 $467,573 $128,602 $ 49,645 $ 50,302 $1.57 $1.56 April 30 $408,012 $119,630 $ 45,181 $ 39,869 $1.24 $1.23 July 31(a) $121,779 $ 43,637 $ (916) $(16,805) $(.52) $(.52) October 31 $110,492 $ 46,109 $ 59 $ (7,881) $(.24) $(.24) 2000 January 31 $268,648 $117,073 $ 45,760 $ 44,094 $1.41 $1.40 April 30 $282,955 $115,163 $ 43,582 $ 37,436 $1.19 $1.18 July 31 $131,211 $ 43,471 $ 1,074 $(10,246) $(.32) $(.32) October 31(b) $147,563 $ 42,624 $ (716) $ (7,253) $(.23) $(.23) The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions generally result in greater earnings during the winter months. Basic earnings per share are calculated using the weighted average number of shares outstanding during the quarter. The annual amount may differ from the total of the quarterly amounts due to changes in the number of shares outstanding during the year. (a) The results for 2001 were impacted by a change in estimate for lost and unaccounted for gas in unbilled revenues by SouthStar Energy Services LLC, of which we own a 30% interest and account for under the equity accounting method. Our portion of the adjustment was ($5) million, net of tax, or ($.15) per share. (b) 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 9. Changes in and Disagreements with Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure - -------------------- None. 51 PART III Item 10. Directors and Executive Officers of the Registrant - ------------------------------------------------------------ Information required under this item with respect to directors is contained in our proxy statement filed with the Securities and Exchange Commission (SEC) on or about January 22, 2002, and is incorporated herein by reference. All of our officers' names, ages and positions as of October 31, 2001, are listed below along with their business experience during the past five years. So far as practicable, all elected officers are elected at the first meeting of the Board of Directors held following the annual meeting of shareholders in each year and hold office until the meeting of the Board following the annual meeting of shareholders in the next subsequent year and until their respective successors are elected and qualify. All other officers hold office during the pleasure of the Board. There are no family relationships among these officers. There are no arrangements or understandings between any officer and any other person pursuant to which the officer was selected except for employment agreements and severance agreements with Messrs. Dzuricky, Killough, Schiefer and Skains which were in effect during the year ended October 31, 2001. Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Ware F. Schiefer, 63 Elected February 2000. President and Chief Executive From 1999 to 2000, he Officer was President and Chief Operating Officer. Prior to 1999, he was Executive Vice President. David J. Dzuricky, 50 Elected in 1995. Senior Vice President and Chief Financial Officer Ray B. Killough, 53 Elected in 1993. Senior Vice President - Operations 52 Thomas E. Skains, 45 Elected in 1995. Senior Vice President - Marketing and Supply Services John L. Clark, Jr., 58 Elected in 1998. Prior to Vice President - Tennessee his election, he was Operations Vice President - Operations of the Nashville Division. Ted C. Coble, 58 Elected in 1982. Vice President and Treasurer, and Assistant Secretary Stephen D. Conner, 53 Elected in 1990. Vice President - Corporate Communications Nick Emanuel, 52 Elected in 1998. Prior to Vice President - Engineering his election, he was Director - Engineering. Charles W. Fleenor, 51 Elected in 1987. Vice President - Gas Services Paul C. Gibson, 62 Elected in 1986. Vice President - Rates Barry L. Guy, 57 Elected in 1986. Vice President and Controller Donald F. Harrow, 46 Elected in 1992. Vice President - Governmental Relations Dale C. Hewitt, 56 Elected in 1993. Vice President - North Carolina Operations Richard A. Linville, 54 Elected in 1997. Prior to Vice President - Human Resources his election, he was Vice President - Human Resources of Harriet and Henderson Yarns, Inc., Henderson, North Carolina. 53 June B. Moore, 48 Elected in August 2000. Vice President - Information From 1997 to her election, Services she was Director - Information Architecture Group. Prior to 1997, she was Director - Application Systems. Kevin M. O'Hara, 43 Elected in 1993. Vice President - Corporate Planning Martin C. Ruegsegger, 51 Elected in 1997. Prior to Vice President, Corporate Counsel his election, he was and Secretary Corporate Secretary. David L. Trusty, 44 Elected in 1997. Prior to Vice President - Marketing his election, he was Vice President - Marketing of the Nashville Division. Ranelle Q. Warfield, 44 Elected in 1997. Prior to Vice President - Sales her election, she was Director - Marketing. William D. Workman III, 61 Elected in 1993. Vice President - South Carolina Operations Ronald J. Turner, 55 Elected in 1976. Assistant Treasurer Item 11. Executive Compensation - -------------------------------- Information required under this item is contained in our proxy statement filed with the SEC on or about January 22, 2002, and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------ (a) Security Ownership of Certain Beneficial Owners Information with respect to security ownership of certain beneficial owners is contained in our proxy statement filed with the SEC on or about January 22, 2002, and is incorporated herein by reference. 54 (b) Security Ownership of Management Information with respect to security ownership of directors and officers is contained in our proxy statement filed with the SEC on or about January 22, 2002, and is incorporated herein by reference. (c) Changes in Control We know of no arrangements or pledges which may result in a change in control. Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Information with respect to certain transactions with directors is contained in our proxy statement filed with the SEC on or about January 22, 2002, and is incorporated herein by reference. 55 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - -------------------------------------------------------------------------- (a) 1. FINANCIAL STATEMENTS -------------------- The following consolidated financial statements of the Company and its subsidiaries and the related independent auditors' report for the year ended October 31, 2001, are included in Item 8 of this report as follows: Page ---- Consolidated Balance Sheets - October 31, 2001 and 2000 26 Statements of Consolidated Income - Years Ended October 31, 2001, 2000 and 1999 28 Statements of Consolidated Cash Flows - Years Ended October 31, 2001, 2000 and 1999 29 Statements of Consolidated Stockholders' Equity - Years Ended October 31, 2001, 2000 and 1999 30 Notes to Consolidated Financial Statements 31 Management's Responsibility for Financial Reporting 49 Independent Auditors' Report 50 (a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULE ------------------------------------------------------ Page ---- Schedule II Valuation and Qualifying Accounts 68 Schedules other than those listed above and certain other information are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto. (a) 3. EXHIBITS -------- Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses. Upon written request of a shareholder, the Company will provide a copy of the exhibit at a nominal charge. 3.1 Articles of Incorporation of the Company, filed in the Department of State of the State of North Carolina on December 14, 1993 (Exhibit No. 2, Registration Statement on Form 8-B, dated March 2, 1994). 56 3.2 Copy of Certificate of Merger (New York) and Articles of Merger (North Carolina), each dated March 1, 1994, evidencing merger of Piedmont Natural Gas Company, Inc., with and into PNG Acquisition Company, with PNG Acquisition Company being renamed "Piedmont Natural Gas Company, Inc." (Exhibits 3.2 and 3.1 to the Registration Statement on Form 8-B, dated March 2, 1994). 3.3 By-Laws of the Company, as amended, dated February 25, 2001 (Exhibit No. 3.1, Form 10-Q for the quarter ended January 31, 2001). 3.4 Articles of Amendment of the Company (Exhibit No. 3, Amendment to Form 10-Q for the period ended April 30, 1997). 4.1 Note Agreement, dated as of June 15, 1989, between the Company and The Mutual Life Insurance Company of New York (Exhibit 4.27, Form 10-K for the fiscal year ended October 31, 1989). 4.2 Note Agreement, dated as of July 30, 1991, between the Company and The Prudential Insurance Company of America (Exhibit 4.29, Form 10-K for the fiscal year ended October 31, 1991). 4.3 Note Agreement, dated as of September 21, 1992, between the Company and Provident Life and Accident Insurance Company (Exhibit 4.30, Form 10-K for the fiscal year ended October 31, 1992). 4.4 Indenture, dated as of April 1, 1993, between the Company and Citibank, N.A., Trustee (Exhibit 4.1, Registration Statement No. 33-60108). 4.5 Medium-Term Note, Series A, dated as of July 23, 1993 (Exhibit 4.7, Form 10-K for the fiscal year ended October 31, 1993). 4.6 Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8, Form 10-K for the fiscal year ended October 31, 1993). 4.7 Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit 4.9, Form 10-K for the fiscal year ended October 31, 1994). 57 4.8 Pricing Supplement of Medium-Term Notes, Series B, dated October 3, 1995 (Exhibit 4.10, Form 10-K for the fiscal year ended October 31, 1995). 4.9 Pricing Supplement of Medium-Term Notes, Series B, dated October 4, 1996 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31, 1996). 4.10 Rights Agreement, dated as of February 27, 1998, between the Company and Wachovia Bank, N.A., as Rights Agent, including the Rights Certificate (Exhibit 10.1, Current Report on Form 8-K dated February 27, 1998). 4.11 Form of Master Global Note (executed September 9, 1999, substantially as filed as Exhibit 4.4, Registration Statement No. 333-26161). 4.12 Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Registration Statement Nos. 33-59369 and 333-26161). 4.13 Pricing Supplement of Medium-Term Notes, Series C, dated September 15, 1999 (Rule 424(b)(3) Pricing Supplement to Registration Statement Nos. 33-59369 and 333-26161). 4.14 Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated September 26, 2000 (Rule 424(b)(3) Pricing Supplement to Registration Statement No. 333-26161). 4.15 Form of Master Global Note (executed June 4, 2001, substantially as filed as Exhibit 4.4, Registration Statement No. 333-62222). 4.16 Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated September 18, 2001 (Rule 424(b)(3) Pricing Supplement to Registration Statement No. 333-62222). 10.1 Executive Long-Term Incentive Plan (Exhibit 99.1, Registration Statement No. 333-34435). 10.2 Service Agreement (5,900 Mcf per day) (Contract No. 4995), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.20, Form 10-K for the fiscal year ended October 31, 1991). 58 10.3 Service Agreement under Rate Schedule WSS (69,701 Mcf per day) (Contract No. 26419-001), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.10, Form 10-K for the fiscal year ended October 31, 1995). 10.4 Service Agreement FT-Incremental Mainline (6,222 Mcf per day) (Contract No. 2268), dated August 1, 1991, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.16, Form 10-K for the fiscal year ended October 31, 1992). 10.5 Service Agreement (FT, 205,200 Mcf per day) (Contract No. 3702), dated February 1, 1992, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.20, Form 10-K for the fiscal year ended October 31, 1992). 10.6 Service Agreement (Contract #800059) (SCT, 1,677 dt/day), dated June 1, 1993, between the Company and Texas Eastern Transmission Corporation (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 1993). 10.7 FTS Service Agreement (23,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.24, Form 10-K for the fiscal year ended October 31, 1994). 10.8 Service Agreement under Rate Schedule FSS (2,263,920 dekatherm storage capacity quantity, 37,000 dekatherm maximum daily storage deliverability) (Contract No. 38015), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.25, Form 10-K for the fiscal year ended October 31, 1994). 10.9 Service Agreement under Rate Schedule SST (Winter: 10,000 Dt/day; Summer: 5,000 Dt/day) (Contract No. 38052), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1994). 10.10 FSS Service Agreement (10,000 dekatherms per day daily storage quantity) (Contract No. 38017), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1995). 59 10.11 SST Service Agreement (37,000 dekatherms per day) (Contract No. 38054), dated November 1, 1993, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.27, Form 10-K for the fiscal year ended October 31, 1995). 10.12 Service Agreement (20,504 Mcf per day), dated June 6, 1994, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 1995). 10.13 FTS-1 Service Agreement (5,000 dekatherms per day) (Contract No. 43462), dated September 14, 1994, between the Company and Columbia Gulf Transmission Company (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 1995). 10.14 FTS 1 Service Agreement (23,455 Dt per day)(Contract No. 43461), dated September 14, 1994, between the Company and Columbia Gulf Transmission Company (Exhibit 10.23, Form 10-K for the fiscal year ended October 31, 1996). 10.15 Firm Transportation Agreement (FT/NT), dated September 22, 1995, between the Company and Texas Gas Transmission Corporation (Exhibit 10.26, Form 10-K for the fiscal year ended October 31, 1996). 10.16 Service Agreement Applicable to Transportation of Natural Gas Under Rate Schedule FT (X-74 Assignment) (12,875 Dt per day), dated October 18, 1995, between the Company and CNG Transmission Corporation (Exhibit 10.27, Form 10-K for the fiscal year ended October 31, 1996). 10.17 FT Service Agreement #01632 (24,995 Dt per day, NIPPS), dated October 18, 1995, between the Company and National Fuel Gas Supply Corporation (Exhibit 10.28, Form 10-K for the fiscal year ended October 31, 1996). 10.18 Service Agreement (Southern Expansion, FT 53,000 Mcf per day peak winter months, 47,700 Mcf per day shoulder winter months) (Contract No. 0.4189), dated November 1, 1995, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.29, Form 10-K for the fiscal year ended October 31, 1996). 60 10.19 Service Agreement (24,140 Mcf per day) (Contract No. 1.1996 NIPPS), dated November 1, 1995, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 1996). 10.20 Service Agreement (12,785 Mcf per day) (Contract No. 1.1994, FT/NT), dated November 1, 1995, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.31, Form 10-K for the fiscal year ended October 31, 1996). 10.21 Rate Schedule GSS Service Agreement, dated May 15, 1996, between the Company and CNG Transmission Corporation (Exhibit 10.32, Form 10-K for the fiscal year ended October 31, 1996). 10.22 Employment Agreement between the Company and David J. Dzuricky, dated December 1, 1999 (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1999). 10.23 Employment Agreement between the Company and Ray B. Killough, dated December 1, 1999 (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1999). 10.24 Employment Agreement between the Company and Ware F. Schiefer, dated December 1, 1999 (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1999). 10.25 Employment Agreement between the Company and Thomas E. Skains, dated December 1, 1999 (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1999). 10.26 Severance Agreement between the Company and David J. Dzuricky, dated December 1, 1999 (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1999). 10.27 Severance Agreement between the Company and Ray B. Killough, dated December 1, 1999 (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1999). 10.28 Severance Agreement between the Company and Ware F. Schiefer, dated December 1, 1999 (Exhibit 10.43, Form 10-K for the fiscal year ended October 31, 1999). 10.29 Severance Agreement between the Company and Thomas E. Skains, dated December 1, 1999 (Exhibit 10.44, Form 10-K for the fiscal year ended October 31, 1999). 61 10.30 Consulting Agreement between the Company and John H. Maxheim, dated March 1, 2000 (Exhibit 10.1, Form 10-Q for the quarter ended January 31, 2001). 10.31 Service Agreement (SE95/96), dated June 25,1996, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.37, Form 10-K for the fiscal year ended October 31, 1996). 10.32 FSS Service Agreement (25,000 dekatherms per day) (Contract No. 49775), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.38, Form 10-K for the fiscal year ended October 31, 1997). 10.33 SST Service Agreement (25,000 dekatherms per day peak winter months, 12,500 dekatherms per day shoulder months) (Contract No. 49773), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1997). 10.34 FSS Service Agreement (1,150,166 dekatherms storage capacity quantity, 19,169 dekatherms maximum daily storage deliverability) (Contract No. 49777), dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.39, Form 10-K for the fiscal year ended October 31, 1998). 10.35 Columbia Gas SST Service Agreement (19,169 dekatherms per day) dated November 22, 1995, between the Company and Columbia Gas Transmission Corporation (Exhibit 10.40, Form 10-K for the fiscal year ended October 31, 1998). 10.36 Transco Sunbelt Service Agreement & Precedent Agreement (41,400 dekatherms of transportation contract quantity per day), dated January 24, 1997, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.41, Form 10-K for the fiscal year ended October 31, 1998). 10.37 CNG Service Agreement (7,000 dekatherms per day), dated May 15, 1996, between the Company and CNG Transmission Corporation (Exhibit 10.42, Form 10-K for the fiscal year ended October 31, 1998). 62 10.38 Form of Director Retirement Benefits Agreement between the Company and its outside directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 1999). 10.39 Service Agreement under Rate Schedule GSS (Storage withdrawal of 68,955 Mcf per day, Storage capacity of 3,858,940 Mcf), dated July 1, 1996, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.55, Form 10-K for the fiscal year ended October 31, 1999). 10.40 Service Agreement, dated January 29, 1997, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.57, Form 10-K for the fiscal year ended October 31, 1999). 10.41 Firm Transportation Agreement (60,000 Mcf per day), dated June 26, 1998, between the Company and Cardinal Extension Company, LLC (Exhibit 10.58, Form 10-K for the fiscal year ended October 31, 1999). 10.42 Service Agreement (15,000 dekatherms per day), dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.50, Form 10-K for the fiscal year ended October 31, 2000). 10.43 Letter of Right of First Refusal, dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC (Exhibit 10.51, Form 10-K for the fiscal year ended October 31, 2000). 10.44 Letter of Agreement of Amendment No. 343 to Gas Transportation Agreement (dated September 1, 1993 - Contract No. 237) (FTA, 74,100 dekatherms per day), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.52, Form 10-K for the fiscal year ended October 31, 2000). 10.45 Letter of Agreement of Amendment No. 2A to Gas Storage Contract (dated September 1, 1993 - Contract No. 2400), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.53, Form 10-K for the fiscal year ended October 31, 2000). 63 10.46 Letter of Agreement of Amendment No. 2A to Gas Storage Contract (dated May 1, 1994 - Contract No. 6815), dated August 3, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.54, Form 10-K for the fiscal year ended October 31, 2000). 10.47 Service Agreement under FT-A Rate Schedule (Contract No. 24706) (55,900 dekatherms per day), dated August 12, 1998, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.55, Form 10-K for the fiscal year ended October 31, 2000). 10.48 Service Agreement under Rate Schedule WSS - Open Access (Contract No. 3.8399) (75,206 dekatherms per day maximum withdrawal quantity; storage capacity quantity of 6,392,383 dekatherms), dated April 1, 2001, between the Company and Transcontinental Gas Pipe Line Corporation. 12 Computation of Ratio of Earnings to Fixed Charges. 23 Independent Auditors' Consent. 99 Annual Report on Form 11-K. (b) Reports on Form 8-K ------------------- The following Form 8-K reports were filed in the fourth quarter ended October 31, 2001. On August 2, 2001, we filed a report on Form 8-K reporting that we issued a press release on July 30, 2001, concerning a lawsuit filed by an affiliate of AGL Resources against Dynegy Marketing and Trade. The lawsuit purports to be "a derivative complaint on behalf of SouthStar Energy Services LLC." Our subsidiary is a 30% owner of SouthStar along with affiliates of AGL Resources and Dynegy. On August 7, 2001, we filed a report on Form 8-K reporting a downward revision of our earnings estimates for the three months ending July 31, 2001, and for the fiscal years ending October 31, 2001 and 2002. On August 27, 2001, we filed a report on Form 8-K reporting that we issued a press release on that date concerning SouthStar. SouthStar's management reported that their net 64 income was overstated due to the manner in which SouthStar estimated unbilled revenues. On December 21, 2001, subsequent to our year end, we filed a report on Form 8-K reporting that we issued a press release on December 13 to announce that our Board of Directors had elected Thomas E. Skains as President and Chief Operating Officer effective at the Annual Meeting of Shareholders on February 22, 2002. Mr. Skains has also been nominated to stand for election to the Board at the Annual Meeting. 65 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on January 25, 2002. Piedmont Natural Gas Company, Inc. ---------------------------------- (Registrant) By: /s/ Ware F. Schiefer ------------------------------------- Ware F. Schiefer President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of January 25, 2002. Signature Title --------- ----- /s/ Ware F. Schiefer President and Chief Executive Officer - ---------------------- and Director Ware F. Schiefer /s/ David J. Dzuricky Senior Vice President and - ---------------------- Chief Financial Officer David J. Dzuricky (Principal Financial Officer) /s/ Barry L. Guy Vice President and Controller - --------------------- (Principal Accounting Officer) Barry L. Guy 66 Signature Title --------- ----- /s/ Jerry W. Amos Director - ------------------------------ Jerry W. Amos /s/ C. M. Butler III Director - ------------------------------ C. M. Butler III /s/ D. Hayes Clement Director - ------------------------------ D. Hayes Clement /s/ John W. Harris Director - ------------------------------ John W. Harris /s/ Muriel W. Helms Director - ------------------------------ Muriel W. Helms /s/ John H. Maxheim Chairman of the Board and Director - ------------------------------ John H.Maxheim /s/ Ned R. McWherter Director - ------------------------------ Ned R. McWherter /s/ Walter S. Montgomery, Jr. Director - ------------------------------ Walter S. Montgomery, Jr. /s/ Donald S. Russell Director - ------------------------------ Donald S. Russell /s/ John E. Simkins Director - ------------------------------ John E. Simkins 67 Schedule II Piedmont Natural Gas Company, Inc. and Subsidiaries Valuation and Qualifying Accounts For the Years Ended October 31, 2001, 2000 and 1999 - ------------------------------------------------------------------------------- Balance at Additions Balance Beginning Charged to Deductions at End Description of Period Costs and Expenses (1) of Period - -------------------------------------------------------------------------------- (in thousands) Allowance for doubtful accounts: 2001 $ 482 $8,172 $8,062 $592 2000 864 3,224 3,606 482 1999 2,314 705 2,155 864 (1) Uncollectible accounts written off net of recoveries and adjustments. 68 Piedmont Natural Gas Company, Inc. Form 10-K For the Fiscal Year Ended October 31, 2001 Exhibits 10.48 Service Agreement (75,206 dekatherms per day maximum withdrawal quantity; storage capacity quantity of 6,392,383 dekatherms), dated April 1, 2001, between the Company and Transcontinental Gas Pipe Line Corporation. 12 Computation of Ratio of Earnings to Fixed Charges. 23 Independent Auditors' Consent. 99 Annual Report on Form 11-K. EX-10.48 3 g73788k5ex10-48.txt SERVICE AGREEMENT (75,206 DEKATHERMS PER DAY MAX Exhibit 10.48 Contract No. 3.8399 SERVICE AGREEMENT between TRANSCONTINENTAL GAS PIPE LINE CORPORATION and PIEDMONT NATURAL GAS COMPANY, INC. DATED APRIL 1, 2001 SERVICE AGREEMENT UNDER RATE SCHEDULE WSS-OPEN ACCESS THIS AGREEMENT entered into this 1st day of April, 2001, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and PIEDMONT NATURAL GAS COMPANY, INC., hereinafter referred to as "Buyer," second party, WITNESSETH: WHEREAS, Seller has made available to Buyer storage capacity from its Washington Storage Field under Part 284 of the Commission's Regulations; and Buyer desires to purchase and Seller desires to sell natural gas storage service under Seller's Rate Schedule WSS-Open Access as set forth herein; NOW, THEREFORE, Seller and Buyer agree as follows: ARTICLE I SERVICE TO BE RENDERED Subject to the terms and provisions of this agreement and of Seller's Rate Schedule WSS-Open Access, Seller agrees to inject into storage for Buyer's account, store and withdraw from storage, quantities of natural gas as follows: To withdraw from storage up to maximum quantity on any day of 75,206 dt, which quantity shall be Buyer's Storage Demand Quantity, as applicable from time to time, pursuant to the terms and conditions of Seller's Rate Schedule WSS-Open Access. To receive and store up to a total quantity at any one time of 6,392,383 dt, which quantity shall be Buyer's Storage Capacity Quantity. ARTICLE II POINT(S) OF RECEIPT AND DELIVERY The Point of Receipt for injection of natural gas delivered to Seller by Buyer and the Point 1 Service Agreement Under Rate Schedule WSS-Open Access (Continued) of Delivery for withdrawal of natural gas delivered by Seller to Buyer under this agreement shall be Seller's Washington Storage Field located at Seller's Station 54 in St. Landry Parish, Louisiana. Gas delivered or received in Seller's pipeline system shall be at the prevailing pressure not to exceed the maximum allowable operating pressure. ARTICLE III TERM OF AGREEMENT This agreement shall be effective April 1, 2001 and shall remain in force and effect until March 31, 2002, and year to year thereafter, subject to termination by either party upon six months written notice to the other party. ARTICLE IV RATE SCHEDULE AND PRICE Buyer shall pay Seller for natural gas service rendered hereunder in accordance with Seller's Rate Schedule WSS-Open Access, and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof. In the event Buyer and Seller mutually agree to a negotiated rate pursuant to the provisions of Section 53 of the General Terms and Conditions and specified term for service hereunder, provisions governing such negotiated rate (including surcharges) and term shall be set forth on Exhibit A to the service agreement. ARTICLE V MISCELLANEOUS 1. The subject headings of the Articles of this agreement are inserted for the purpose of convenient reference and are not intended to be a part of this agreement nor to be considered in any interpretation of the same. 2. This agreement supersedes and cancels as of the effective date hereof the following contracts between the parties hereto: Service Agreements under Rate Schedule WSS dated August 1, 1991 (Seller's system contract numbers 0.0912 and 0.0718). 3. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or 2 Service Agreement Under Rate Schedule WSS-Open Access (Continued) defaults, whether of a like or different character. 4. This agreement shall be interpreted, performed and enforced in accordance with the laws of the State of Texas. 5. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns. IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized. TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Seller) By /s/ Frank J. Ferazzi --------------------------------- Frank J. Ferazzi - Vice President Customer Service and Rates PIEDMONT NATURAL GAS COMPANY, INC. (Buyer) By /s/ Thomas E. Skains --------------------------------- Thomas E. Skains Senior Vice President Marketing And Supply Services 3 Service Agreement Under Rate Schedule WSS-Open Access (Continued) EXHIBIT A --------- Specification of Negotiated Rate and Term - ----------------------------------------- None 4 EX-12 4 g73788k5ex12.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12 PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Computation of Ratio of Earnings to Fixed Charges For Fiscal Years Ended October 31, 1997 through 2001 (in thousands except ratio amounts)
2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- Earnings: Pre-tax income from continuing operations $135,702 $139,520 $137,475 $135,367 $121,193 Distributed income of equity investees 9,470 4,255 - - 9,252 Fixed charges 47,793 44,368 37,978 38,415 39,263 -------- -------- -------- -------- -------- Total Adjusted Earnings $192,965 $188,143 $175,453 $173,782 $169,708 ======== ======== ======== ======== ======== Fixed Charges: Interest $ 45,286 $ 42,010 $ 35,911 $ 36,453 $ 36,949 Amortization of debt expense 420 465 323 304 346 One-third of rental expense 2,087 1,893 1,744 1,658 1,968 -------- -------- -------- -------- -------- Total Fixed Charges $ 47,793 $ 44,368 $ 37,978 $ 38,415 $ 39,263 ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges 4.04 4.24 4.62 4.52 4.32 ==== ==== ==== ==== ====
EX-23 5 g73788k5ex23.txt INDEPENDENT AUDITORS' CONSENT Exhibit 23 INDEPENDENT AUDITORS' CONSENT - ----------------------------- Piedmont Natural Gas Company, Inc.: We consent to the incorporation by reference in Registration Statement No. 33-61093 on Form S-8, in Registration Statement No. 333-34433 on Form S-8, in Registration Statement No. 333-34435 on Form S-8, in Registration Statement No. 333-86263 on Form S-3, in Registration Statement No. 333-62222 on Form S-3, in Registration Statement No. 333-76138 on Form S-8, and in Registration Statement No. 333-76140 on Form S-8 of our report dated December 7, 2001, appearing in the Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc. for the year ended October 31, 2001. /s/ DELOITTE & TOUCHE LLP Charlotte, North Carolina January 25, 2002 EX-99 6 g73788k5ex99.txt ANNUAL REPORT ON FORM 11-K Exhibit 99 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 11-K For Annual Reports of Employee Stock Purchase, Savings and Similar Plans Pursuant to Section 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended October 31, 2001* and for the period November 1, 2000, through October 1, 2001** Commission file number 1-6196 A. Full title of the plans and address of the plans, if different from that of the issuer named below: *Piedmont Natural Gas Company Employee Stock Purchase Plan **Piedmont Natural Gas Company Employee Stock Ownership Plan B. Name of issuer of the securities held pursuant to the plans and the address of its principal executive office: Piedmont Natural Gas Company, Inc. 1915 Rexford Road Charlotte, North Carolina 28211 Piedmont Natural Gas Company Employee Stock Purchase Plan The Employee Stock Purchase Plan (ESPP) has been in effect since 1985. The purposes of the ESPP are to encourage employees to purchase Piedmont common stock, thereby promoting increased interest in the Company, and to encourage employees to remain employed. Participants elect to have a portion of their pay withheld each pay period for quarterly purchases at 90% of the average market price for the month during which the purchase takes place. There are no financial statements for the ESPP. Amounts withheld from participants are recorded as a general liability on Piedmont's books until the purchase dates, which are January 31, April 30, July 31 and October 31. At the purchase date, the liability is reduced to zero and shares are issued to participants' accounts in Piedmont's Dividend Reinvestment and Stock Purchase Plan. Quarterly statements are furnished to participants showing the number of shares purchased, the purchase price and the balance in the account. At October 31, 2001, 461 employees were participating in the ESPP. 1 Piedmont Natural Gas Company Employee Stock Ownership Plan Statements of Net Assets Available for Benefits October 1, 2001 and October 31, 2000 2001 2000 ---- ---- Assets (Note 1): Investment in common stock of Piedmont Natural Gas Company, Inc., at fair value - 200,496 shares (cost $2,821,737) in 2000 $ -- $6,115,128 Short-term investment fund, at cost which approximates fair value -- 528 Other -- 67 ----------- ---------- Net assets available for benefits $ -- $6,115,723 =========== ========== See notes to financial statements. 2 Piedmont Natural Gas Company Employee Stock Ownership Plan Statements of Changes in Net Assets Available for Benefits For the Period November 1, 2000 through October 1, 2001 and the Years Ended October 31, 2000 and 1999 2001 2000 1999 ---- ---- ---- Dividend and interest income $ 299,994 $ 297,312 $ 287,859 Gain (loss) on sale of assets (Note 3) (16,441) 44,672 (55,838) Net depreciation in fair value of investment in common stock of Piedmont Natural Gas Company, Inc. (26,678) (372,607) (528,700) Withdrawals by participants (435,553) (591,777) (517,537) Transfers to other plans (Note 1) (5,937,045) -- -- ----------- ----------- ----------- Net decrease (6,115,723) (622,400) (814,216) Net assets available for benefits: Beginning of period 6,115,723 6,738,123 7,552,339 ----------- ----------- ----------- End of Period $ -- $ 6,115,723 $ 6,738,123 =========== =========== =========== See notes to financial statements. 3 Piedmont Natural Gas Company Employee Stock Ownership Plan Notes to Financial Statements 1. Description of the Plan The Piedmont Natural Gas Company Employee Stock Ownership Plan (the Plan) was established to enable employees to acquire Piedmont common stock. Through 1986, Piedmont contributed to the Plan amounts equal to a tax credit based on aggregate compensation paid or accrued to all employees under the Plan. The Tax Reform Act of 1986 eliminated the tax credit allowance and no contributions have been made since 1987. Piedmont maintains salary investment plans that are profit-sharing plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Tax Code), and include qualified cash or deferred arrangements under Tax Code Section 401(k). Effective October 1, 2001, the Plan was merged into the Piedmont Natural Gas Company, Inc. Payroll Investment Plan (Payroll Plan) and the Piedmont Natural Gas Company, Inc. Salary Investment Plan (Salary Plan). Assets of $730,897 from the bargaining unit component of the Plan were transferred to the Payroll Plan and assets of $5,206,148 from the non-bargaining unit component of the Plan were transferred to the Salary Plan in October. Participants may remain invested in Piedmont common stock or may sell the stock at any time and reinvest the proceeds in another investment option of the 401(k) plans. Effective with the merger and transfer of assets, the Plan no longer exists. All descriptions and disclosures in the notes to financial statements relate to activity prior to October 1, 2001. The Plan was administered by the Administration Committee approved by Piedmont's Board of Directors. Piedmont paid the administrative expenses of the Plan. The Trust Client Services department of Wachovia Bank, N.A., served as trustee and custodian. The Plan was subject to the provisions of the Employee Retirement Income Security Act of 1974. Prior to 1988, a participant in the Plan was defined as an active eligible employee with a balance in his or her Plan account. An employee was eligible to participate following the later of the date of completion of at least 1,000 hours of service during a period of 12 consecutive months or attainment of age 21. However, employees who reached eligibility after contributions stopped were not considered participants and no previous contributions were credited to them. 4 Separate accounts were maintained for each participant to reflect the allocation of contributions and subsequent dividend and investment income. Any income credited to participants was reinvested in Piedmont common stock. The Plan provided for immediate vesting. Distributions to participants were made either at early retirement (age 55 and 10 years of service), at normal retirement (age 65), at actual retirement for a participant who remained employed after attaining normal retirement age, at permanent disability or at death of the participant. The Administration Committee's practice was to make a distribution following a participant's termination of employment for any reason. A participant who reached age 55 and completed ten years of participation had the right to diversify a portion of his or her account balance each year during the qualified election period. 2. Basis of Accounting The financial statements are presented on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America. Estimates and assumptions are made when preparing financial statements. Those estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from these estimates. The investment in Piedmont common stock was valued at fair value as determined by quoted market prices on the New York Stock Exchange at year end. Dividend income was accrued on the ex-dividend date. Purchases and sales of securities were recorded on a trade-date basis. Realized gains and losses from security transactions were reported on the average cost method. 5 3. Gain (Loss) on Sale of Assets The gain (loss) on sale of assets for the period November 1, 2000, through October 1, 2001, and the years ended October 31, 2000 and 1999, was computed as follows: 2001 2000 1999 ---- ---- ---- Gross proceeds $ 302,367 $452,554 $ 386,600 Historical cost 318,808 407,882 442,438 --------- -------- --------- Gain (loss) $ (16,441) $ 44,672 $ (55,838) ========= ======== ========= 4. Tax Status The Internal Revenue Service informed us that the Plan was qualified under Sections 401 and 409 of the Tax Code and the trust established under the Plan was exempt from income taxes under Section 501(a) of the Tax Code. Piedmont amended the Plan since receiving the determination letter; however, Piedmont believes the amended Plan was designed and operated in compliance with the Tax Code. Distributions to recipients were taxed as ordinary income, with the taxable amount that applied to Piedmont common stock being the lesser of cost or fair market value on the distribution date. Any increase in the value of Piedmont common stock during the period that the stock was held by the trust was not taxed. After distribution, the sale of Piedmont common stock was subject to capital gain or loss treatment. 6 Independent Auditors' Report - ---------------------------- To the Trustees and Participants of Piedmont Natural Gas Company Employee Stock Ownership Plan: We have audited the accompanying statements of net assets available for benefits of Piedmont Natural Gas Company Employee Stock Ownership Plan (the Plan) as of October 1, 2001 and October 31, 2000, and the related statements of changes in net assets available for benefits for the period November 1, 2000 through October 1, 2001 and for the years ended October 31, 2000 and 1999. These financial statements are the responsibility of the Plan's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1 to the financial statements, effective October 1, 2001 the Plan was merged into other plans sponsored by Piedmont Natural Gas Company. In our opinion, such financial statements present fairly, in all material respects, the net assets available for benefits of the Plan as of October 1, 2001 and October 31, 2000, and the changes in net assets available for benefits for the period November 1, 2000 through October 1, 2001 and for the years ended October 31, 2000 and 1999 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Charlotte, North Carolina January 4, 2002 7 -----END PRIVACY-ENHANCED MESSAGE-----