-----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, WetwwTqtgG/FgaDozUXKXbRDS7G2Jh9QIavDxxoPGORUkLi1Wl97/TnLRexDAhxR fVYdDStRZGbYtmh0hYWNpA== 0000950144-01-001488.txt : 20010129 0000950144-01-001488.hdr.sgml : 20010129 ACCESSION NUMBER: 0000950144-01-001488 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 20001031 FILED AS OF DATE: 20010125 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: SEC FILE NUMBER: 001-06196 FILM NUMBER: 1514810 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 g66462e10-k405.txt PIEDMONT NATURAL GAS COMPANY, INC. 1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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, 2000 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 11, 2001. Common Stock, no par value -- $1,089,155,628 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 11, 2001 ----- ------------------------------- Common Stock, no par value 32,003,458
DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Shareholders on February 23, 2001, are incorporated by reference into Part III. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 Piedmont Natural Gas Company, Inc. 2000 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 7 Part II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 8 Item 6. Selected Financial Data 9 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 9 Item 7A. Quantitative and Qualitative Disclosure about Market Risk 22 Item 8. Financial Statements and Supplementary Data 22 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 48 Part III. Item 10. Directors and Executive Officers of the Registrant 49 Item 11. Executive Compensation 51 Item 12. Security Ownership of Certain Beneficial Owners and Management 52 Item 13. Certain Relationships and Related Transactions 52 Part IV. Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K 53 Signatures 63 3 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 over 690,000 residential, commercial and industrial customers in North Carolina, South Carolina and Tennessee. We are the second-largest natural gas utility in the southeast. 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 and Hickory in North Carolina. In Tennessee, our service area is the metropolitan area of Nashville. Effective January 1, 2001, we closed the purchase of the natural gas distribution business of Atmos Energy Corporation located in Gaffney and Cherokee County, South Carolina. For further information, see "Note 2. Regulatory Matters" in Item 8 of this report on page 32. We have one reportable business segment, domestic natural gas distribution. This business is conducted by the parent company and two wholly owned subsidiaries of Piedmont Energy Partners -- Piedmont Intrastate Pipeline Company and Piedmont Interstate Pipeline Company. Piedmont Intrastate is a member of Cardinal Pipeline Company, L.L.C., which owns and operates an intrastate natural gas pipeline in North Carolina. Piedmont Interstate is a member of Pine Needle LNG Company, L.L.C., which owns an interstate liquified natural gas (LNG) peak-demand facility in North Carolina. All of our other activities are conducted by two wholly owned subsidiaries of Piedmont Energy Partners -- Piedmont Propane Company and Piedmont Energy Company. Piedmont Propane owns 20.69% of the membership interest in US Propane, L.P., which owns all of the general partnership interest and approximately 34% of the limited partnership interest in Heritage Propane Partners, L.P. (NYSE:HPG). Heritage is the nation's fourth-largest propane distributor serving more than 490,000 customers in 28 states. Piedmont Energy has a 30% equity interest in SouthStar Energy Services LLC which offers a combination of unregulated energy products and services to industrial, commercial and residential customers in the southeastern United States. Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. The cost of purchased gas (which has increased significantly in recent months) is 1 4 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, 2000, totaled $830.4 million, of which 41% was from residential customers, 25% from commercial customers, 24% from industrial customers, 9% from secondary market activity and 1% from various other sources. Revenues from non-utility operations, less related costs and income taxes, are shown in the consolidated financial statements 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 42. 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 80 communities we serve, with expiration dates from 2000 to 2050. One franchise for a major service area and one franchise for a smaller area that expired in 2000 are currently being negotiated. We believe that these franchises will be renewed with no material adverse impact to us. The franchises are adequate for operation of our gas distribution business and do not contain restrictions which are of a materially burdensome nature. 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 2000, the amount of natural gas in storage varied from 11.8 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 22.7 million dekatherms, and the aggregate commodity cost of this gas in storage varied from $29.6 million to $57.4 million. 2 5 The following is a five-year comparison of gas sales and other statistics for the years ended October 31, 1996 through 2000:
2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- OPERATING REVENUES (in thousands): Sales and Transportation: Residential $343,476 $295,108 $323,777 $319,722 $292,010 Commercial 207,087 168,731 189,341 195,862 180,415 Industrial 202,120 143,129 162,336 191,565 184,118 For Resale 249 254 87 266 2,748 -------- ------- -------- -------- -------- Total 752,932 607,222 675,541 707,415 659,291 Secondary Market Sales 73,505 75,734 86,333 64,411 22,152 Miscellaneous 3,940 3,514 3,403 3,691 3,612 -------- -------- -------- -------- -------- Total $830,377 $686,470 $765,277 $775,517 $685,055 ======== ======== ======== ======== ======== GAS VOLUMES - DEKATHERMS (in thousands): System Throughput: Residential 40,520 38,111 41,142 38,339 43,357 Commercial 29,315 26,668 28,528 28,476 31,040 Industrial 61,144 64,171 64,165 65,000 62,434 For Power Generation 4,081 6,991 9,141 3,236 1,620 For Resale 20 29 17 27 581 -------- ------- ------- ------- ------- Total 135,080 135,970 142,993 135,078 139,032 ======= ======= ======= ======= ======= Secondary Market Sales 21,072 34,792 33,953 24,547 9,724 NUMBER OF RETAIL CUSTOMERS BILLED (12 month average): Residential 577,314 549,610 522,874 495,739 468,803 Commercial 68,879 66,409 63,878 62,258 59,905 Industrial 2,702 2,764 2,778 2,697 2,687 -------- ------- ------- ------- ------- Total 648,895 618,783 589,530 560,694 531,395 ======= ======= ======= ======= ======= AVERAGE PER RESIDENTIAL CUSTOMER: Gas Used - Dekatherms 70.19 69.34 78.69 77.34 92.48 Revenue $594.95 $536.94 $619.23 $644.94 $622.88 Revenue Per Dekatherm $8.48 $7.74 $7.87 $8.34 $6.73 COST OF GAS (in thousands): Natural Gas Purchased $426,329 $290,501 $337,400 $362,249 $327,968 Liquefied Petroleum Gas (LPG) - - - 77 160 Transportation Gas Received (Not Delivered) (868) (1,236) 339 (1,840) 1,024 Natural Gas Withdrawn from (Injected into) Storage, net (20,144) (3,111) (2,750) 2,597 (8,078) Other Storage (4,937) (4,937) 333 318 (40) Other Adjustments 111,666 84,745 107,100 97,264 73,099 -------- ------- -------- -------- -------- Total $512,046 $365,962 $442,422 $460,665 $394,133 ======== ======== ======== ======== ======== COST OF GAS PER DEKATHERM OF GAS SOLD $4.17 $3.05 $3.45 $3.81 $3.17 SUPPLY AVAILABLE FOR DISTRIBUTION - DEKATHERMS (in thousands): Natural Gas Purchased 126,228 130,633 138,870 129,797 127,799 LPG - - - 10 121 Transportation Gas 31,896 44,322 42,091 32,026 24,550 Natural Gas Withdrawn from (Injected into) Storage, net (712) (373) (3,301) (3) (1,142) Other Storage (259) (2,132) 27 16 16 Company Use (161) (154) (110) (121) (152) ------- ------- ------- ------- ------- Total 156,992 172,296 177,577 161,725 151,192 ======= ======= ======= ======= ======= UTILITY CAPITAL EXPENDITURES (in thousands) $108,650 $102,020 $93,513 $93,482 $98,258 GAS MAINS - MILES OF 3" EQUIVALENT 18,900 18,400 18,200 17,800 16,900
3 6
2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- DEGREE DAYS - SYSTEM AVERAGE: Actual 3,097 3,124 3,339 3,471 3,993 Normal 3,563 3,597 3,612 3,611 3,606 Percentage of Actual to Normal 87% 87% 92% 96% 111%
During 2000, we delivered 135.1 million dekatherms of natural gas to our customers, of which 32 million dekatherms were transported for large industrial customers. This compares with 136 million dekatherms delivered in 1999, of which 44.6 million dekatherms were transported. In addition to this system throughput, secondary-market sales volumes totaled 21.1 million dekatherms in 2000, compared with 34.8 million dekatherms in 1999. Sales to temperature-sensitive customers, whose consumption varies with the weather, were 69.8 million dekatherms in 2000, compared with 64.8 million dekatherms in 1999. Weather, as measured by degree days, was 13% warmer than normal in 2000 and 1999. We sold or transported 4.1 million dekatherms to power generation customers in 2000, compared with 7 million dekatherms in 1999. We sold or transported 61.1 million dekatherms to industrial users in 2000, compared with 64.2 million dekatherms in 1999. Industrial sales are the most price-sensitive of our markets and are largely a function of our ability to obtain supplies of natural gas competitively priced with other industrial fuels. 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, 2000, 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) 487,800 Tennessee Pipeline 74,100 Texas Eastern 1,700 Columbia Gas (through arrangements with Transco and Columbia Gulf) 23,000 Columbia Gulf 35,000 ------- Total 621,600 =======
4 7 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. LNG 211,000 Liquefied Petroleum Gas 8,000 Transco Storage 71,400 Columbia Gas Storage 91,200 Tennessee Pipeline Storage 55,900 Dominion Storage 7,000 Pine Needle LNG 222,000 Third-Party City Gate Arrangements 22,000 ------- Total 688,500 ======= 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. In 2000, 126.2 million dekatherms of natural gas were purchased. We own or have under contract 24.7 million dekatherms of storage capacity, either in the form of underground storage or LNG. This capability is used to supplement regular pipeline supplies on colder winter days when demand increases. 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. Approximately 31% of annual gas deliveries in 2000 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 (which has increased significantly in recent months) 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. 5 8 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 2000, our largest customer contributed $18.1 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 had no material effect on capital expenditures, earnings or competitive position during 2000. 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. As of October 31, 2000, we had 1,603 utility employees, compared with 1,615 utility employees as of October 31, 1999. Item 2. Properties Our properties consist primarily of distribution systems and related facilities to serve our utility customers. We have constructed and own approximately 574 miles of lateral pipelines up to 16 inches in diameter which connect our distribution systems with the transmission systems of our pipeline suppliers. Natural gas is distributed through approximately 18,900 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 either 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 6 9 believe is adequate to cover any material judgments which may result from these lawsuits. Item 4. Submission of Matters to a Vote of Security Holders None. 7 10 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, 2000 and 1999. 2000 High Low 1999 High Low - ---------- ---- --- ---------- ---- --- January 31 33.1875 28.2500 January 31 36.6250 30.0625 April 30 29.6875 23.7500 April 30 35.8750 28.6250 July 31 31.3125 26.5625 July 31 34.3750 30.6875 October 31 31.1875 26.5000 October 31 34.1875 30.2500 (b) As of January 11, 2001, our Common Stock was owned by 17,176 shareholders of record. (c) Information with respect to quarterly dividends paid on Common Stock for the years ended October 31, 2000 and 1999, is as follows: Dividends Paid Dividends Paid 2000 Per Share 1999 Per Share - ---------- -------------- ---------- -------------- January 31 34.5(cent) January 31 32.5(cent) April 30 36.5(cent) April 30 34.5(cent) July 31 36.5(cent) July 31 34.5(cent) October 31 36.5(cent) October 31 34.5(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, 2000, all retained earnings were free of such restrictions. 8 11 Item 6. Selected Financial Data Selected financial data for the years ended October 31, 1996 through 2000, is as follows:
2000* 1999 1998 1997 1996 ----- ---- ---- ---- ---- (in thousands except per share amounts) Margin $ 318,331 $ 320,508 $ 322,855 $ 314,852 $ 290,922 Operating Revenues $ 830,377 $ 686,470 $ 765,277 $ 775,517 $ 685,055 Net Income $ 64,031 $ 58,207 $ 60,313 $ 54,074 $ 48,562 Earnings per Share of Common Stock: Basic $ 2.03 $ 1.88 $ 1.98 $ 1.81 $ 1.67 Diluted $ 2.01 $ 1.86 $ 1.96 $ 1.79 $ 1.66 Cash Dividends Per Share of Common Stock $ 1.44 $ 1.36 $ 1.28 $ 1.205 $ 1.145 Average Shares of Common Stock: Basic 31,600 31,013 30,472 29,883 29,161 Diluted 31,779 31,242 30,717 30,229 29,213 Total Assets $1,445,003 $1,288,657 $1,162,844 $1,098,156 $1,067,086 Long-Term Debt (less current maturities) $ 451,000 $ 423,000 $ 371,000 $ 381,000 $ 391,000 Rate of Return on Average Common Equity 12.57% 12.25% 13.74% 13.42% 13.11% Long-Term Debt to Total Capitalization Ratio 46.10% 46.24% 44.74% 47.58% 50.32%
*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 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, we can give no assurances that these expectations will be achieved. 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, o Industrial, commercial and residential growth in the 9 12 service territories, o Deregulation, unanticipated impacts of restructuring and increased competition in the energy industry, o The potential loss of large-volume industrial customers due to bypass or the shift by such customers to special competitive contracts at lower per-unit margins, o Economic and capital market conditions, o The ability to meet internal performance goals, o The capital intensive nature of our business, including development project delays or changes in project costs, o Changes in the availability and price of natural gas, o Changes in demographic patterns and weather conditions, and o Changes in environmental requirements and cost of compliance. LIQUIDITY AND CAPITAL RESOURCES The gas distribution business is highly weather sensitive and seasonal. This weather sensitivity and seasonality cause short-term cash requirements to vary significantly during the year. We finance current cash requirements through operating cash flows, the issuance of new common stock through dividend reinvestment and employee stock purchase plans and short-term borrowings. 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 to cover cash requirements when market or other conditions are favorable for such long-term financing. Various banks provide lines of credit totaling $75 million for these direct short-term borrowings. Additional lines are also available on an as needed, if available, basis. These short-term borrowings include open-ended loans based on the Federal Reserve funds rate, transactional borrowings, LIBOR cost-plus loans 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. Outstanding short-term borrowings during 2000 ranged from zero to a high of $156 million and interest rates ranged from 4.5% to 7.313% during the year. At October 31, 2000, $99.5 million of short-term debt was outstanding at a weighted average interest rate of 7.03%. We had $483 million of long-term debt outstanding at October 31, 2000. Annual sinking fund requirements and maturities of this 10 13 debt are $32 million in 2001, $2 million in 2002, $47 million in 2003, $2 million in 2004 and zero in 2005. We retired $2 million of long-term debt in 2000. On September 29, 2000, we issued $60 million of 7.80% medium-term notes remaining under a shelf registration statement for $150 million of debt securities that was filed with the Securities and Exchange Commission in 1997. The note is to be redeemed in a single payment at maturity in 2010. At October 31, 2000, our capitalization ratio consisted of 46% long-term debt and 54% common equity. The embedded cost of long-term debt at that date was 7.99%. The return on average common equity in 2000 was 12.57%. 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 $109.6 million, payments of debt principal and interest of $37 million and dividend payments to shareholders of $45.5 million. We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our 5% current annual growth in customer base. Utility capital expenditures for 2000 were $108.6 million. Non-utility capital expenditures in 2000 were $869,000. Utility capital expenditures totaling $116.2 million, primarily to serve customer growth, are budgeted for 2001. COMPETITION AND ACCOUNTING FOR REGULATED ACTIVITIES The natural gas industry, including producers, pipelines and local gas distribution companies, has undergone significant changes in recent years in moving toward a less-regulated marketplace. In response to the changing competitive situation, 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. 11 14 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 impact 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 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 sheet 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 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 deliverability 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 12 15 that may be incurred under orders or regulations of the Federal Energy Regulatory Commission (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; however, such review is not required in Tennessee. For the most recent twelve-month period, the NCUC and the PSCSC found us to be prudent in our gas purchasing practices and allowed 100% recovery of our actual gas costs. In 1996, the TRA approved a performance incentive plan effective July 1, 1996, which eliminated annual prudence reviews 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 ratepayers and potential earnings to shareholders by sharing in gas cost reductions. Initially approved for a two-year period, the plan now continues each July 1 until we notify the TRA of termination 90 days before the end of a plan year or until the plan is modified, amended or terminated by the TRA. Secondary market transactions permit us to market 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 rate-sharing mechanism under the performance incentive plan. Approximately 31% of annual gas deliveries in 2000 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 13 16 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. The NCUC has authorized us to use $38.5 million of the expansion funds to extend natural gas service to the counties of Avery, Mitchell and Yancey, of which $3 million has been used as of October 31, 2000. The total cost of the project is estimated to be $44.5 million. As of October 31, 2000, the North Carolina State Treasurer held $39.9 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 sheet. On December 30, 1999, we filed with the TRA for a general rate increase of $10.7 million annually. On May 18, 2000, we filed with the TRA a stipulation with the Consumer Advocate Division of the Attorney General of the State of Tennessee that would permit us to increase our rates by $4.9 million annually. The TRA approved the settlement on June 5 and issued an order on July 28. New rates became effective on July 1, 2000. On March 1, 2000, we filed with the NCUC for a general rate increase of $19 million annually, including an increase in customers' rates of $14.5 million. We, the Public Staff of the NCUC and Carolina Utility Customers Association, Inc. (an association of industrial users), presented a stipulated agreement on all issues in the case to the NCUC at a hearing on September 5. Among other things, the stipulation called for a margin increase of $9.7 million including a rate increase to customers of $6 million. The NCUC issued an order approving the stipulation on October 5. New rates are effective November 1, 2000. 14 17 On October 11, 2000, we signed an agreement with Atmos Energy Corporation to purchase their natural gas distribution assets located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition will be at net book value of approximately $6.6 million and will add 5,400 customers and $2.2 million of margin to our operations. The acquisition is subject to the approval of the PSCSC which has set the matter for hearing on December 27, 2000. If approved, closing is anticipated to be effective on January 1, 2001. RESULTS OF OPERATIONS Net income for 2000 was $64 million, compared with $58.2 million in 1999 and $60.3 million in 1998. 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. o General taxes decreased. 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. Net income for 1999 decreased $2.1 million from 1998 primarily for the reasons listed below. o Sales decreased in all customer classes. o Earnings from propane operations decreased. o Earnings from unregulated retail energy marketing services decreased. o Depreciation expense increased. 15 18 These decreases were partially offset for the reasons listed below. o Operations expenses decreased. o General taxes decreased. o Utility interest charges decreased. Compared with the prior year, weather in our service area was 1% warmer in 2000, 6% warmer in 1999 and 4% warmer in 1998. Volumes of gas delivered to customers, which we refer to as system throughput, were 135.1 million dekatherms in 2000, compared with 136 million dekatherms in 1999, a decrease of 1%, and 143 million dekatherms in 1998. In addition to this system throughput, secondary-market sales volumes decreased to 21.1 million dekatherms in 2000, compared with 34.8 million dekatherms in 1999 and 34 million dekatherms in 1998. Operating revenues were $830.4 million in 2000, $686.5 million in 1999 and $765.3 million in 1998. Operating revenues for 2000 increased by $143.9 million from 1999 primarily for the reasons listed below. o An increase in the commodity cost of gas which is a component of revenue. o The shift from transportation of gas to sales of gas on which there is a commodity cost included in revenues. o Increased volumes sold to residential and commercial customers. Operating revenues for 1999 decreased by $78.8 million from 1998 primarily for the reasons listed below. o Sales to residential, commercial and industrial customers decreased due to warmer weather. o North Carolina gross receipts taxes were eliminated from rates during 1999 (see discussion of General Taxes below). o Revenues from secondary market activity decreased even though volumes increased. The weather normalization adjustment mechanism (WNA) generated revenues of $19.3 million, $19.7 million and $5 million in 2000, 1999 and 1998, respectively. The WNA in effect in all three states is designed to offset the impact that unusually cold 16 19 or warm weather has on residential and commercial customer billings and margin. Weather 13% warmer than normal was experienced in 2000 and 1999, compared with 8% warmer-than-normal weather in 1998. 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. Each commission has also authorized us to negotiate lower rates to certain of our industrial customers when necessary to remain competitive. We are generally permitted to recover margin losses resulting from these negotiated transactions through rates. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals. Cost of gas was $512 million in 2000, $366 million in 1999 and $442.4 million in 1998. Cost of gas for 2000 increased $146 million from 1999 primarily due to increases in commodity gas costs related to increased rates charged to customers as well as an increase in volumes sold to residential, commercial and industrial customers who shifted from transportation gas. Cost of gas for 1999 decreased $76.4 million from 1998 primarily for the reasons listed below. o Decreases in demand and commodity gas costs. o Increased volumes in secondary market sales at wholesale market rates which are lower than retail tariff rates. o Increases in capacity release transactions. 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 purchased gas adjustment procedures. Margin was $318.3 million in 2000, $320.5 million in 1999 and $322.9 million in 1998. Margin increased or decreased due to the changes in revenues and cost of gas noted above. As explained in General Taxes below, operating revenues, and therefore margin, included North Carolina gross receipts taxes of $9.6 million in 1999 and $13 million in 1998. The margin earned per dekatherm of system throughput did not change in 2000 from 1999 and increased 17 20 by $.10 in 1999 over 1998. Operations and maintenance expenses were $127 million in 2000, $116.8 million in 1999 and $119.6 million in 1998. Operations and maintenance expenses for 2000 increased $10.2 million, compared with 1999, primarily due to the following reasons. o Increase in payroll expense. o Increase in risk insurance expense. o Increase in advertising expense. o Increase in the provision for uncollectibles. o Increase in outside consultants expense. o Increase in employee benefits expense. A decrease in outside labor expense partially offset these increases in 2000. Operations and maintenance expenses for 1999 decreased $2.8 million, compared with 1998, primarily for the reasons listed below. o Decrease in risk insurance expense. o Decrease in office supplies expense. o Decrease in payroll expense. o Decrease in employee benefits expense. o Decrease in the provision for uncollectibles. Increases in outside labor expense and advertising expense partially offset these decreases in 1999. Depreciation expense increased from $42.2 million to $48.9 million over the three-year period 1998 to 2000 primarily due to the growth in plant in service. General taxes decreased from $32.6 million to $18.8 million over the three-year period 1998 to 2000 primarily due to the elimination of North Carolina gross receipts taxes explained below. Effective July 1, 1999, for bills rendered after August 1, 1999, we began charging a new excise tax on piped natural gas used 18 21 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 excise tax was not intended to increase or decrease taxes, but to replace the combination of the sales and use tax and gross receipts tax. 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 and thus margin (revenues less cost of gas) and general taxes for all periods prior to the change. Other income, net of income taxes, increased to $11.3 million in 2000 compared with a loss of $1.1 million in 1999 and income of $2.3 million in 1998, 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. o Gain on sale of propane assets. A decrease in the allowance for funds used during construction partially offset these increases in other income. Prior to August 10, 2000, Piedmont Propane Company, a wholly owned subsidiary, 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 and Piedmont Propane Company now owns 20.69% of the membership interest in US Propane. On August 10, 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 for $181.4 million in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage for 19 22 $120 million. This combination, including a gain on the transfer of the propane assets, transaction costs and certain employee benefit plans' gains and charges, resulted in $5.1 million of net income or earnings per share of $.16. US Propane owns all of the general partnership interest and approximately 34% of the limited partnership interest in Heritage. Utility interest charges were $37 million in 2000, $32.4 million in 1999 and $33.2 million in 1998. 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. o Increase in interest on short-term debt due to higher balances outstanding at slightly higher rates. An increase in the portion of the allowance for funds used during construction attributable to borrowed funds partially offset these increases in 2000. Utility interest charges for 1999 decreased $800,000, compared with 1998, primarily due to the following reasons. o Decrease in interest on long-term debt due to lower balances outstanding over the period. o Decrease in interest charged on refunds due customers from lower balances outstanding. o Increase in the portion of the allowance for funds used during construction attributable to borrowed funds. An increase in interest on short-term debt due to greater balances outstanding, even at slightly lower interest rates, partially offset these decreases in 1999. 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. As of October 31, 2000, we had an environmental liability of $1.4 million for the remaining three MGP sites not covered by the settlement. This liability is 20 23 estimated based on a generic MGP site study as we have not performed site-specific evaluations. During 2000, we learned that a tract of land in North Carolina that was owned by us during the period 1951 through 1956 has been identified as a possible MGP site. Based on information available to us and due to the small size of the tract, we do not believe that the tract ever contained an MGP. A third party is in the process of evaluating this site. Until the third party completes its evaluation, we are unable to determine if we may have any potential liability with respect to this site. However, due to the size of and our limited connection with this site, we do not expect any such liability to be material. 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. In connection with the settlement noted above and the estimated liability for the three remaining sites, we have recorded a regulatory asset of $6.6 million. As of October 31, 2000, we had an additional regulatory asset in the amount of $349,000, net of recoveries from customers, for other environmental costs, primarily legal fees and engineering assessments. In connection with the general rate case in North Carolina discussed in Note 2 to the consolidated financial statements, the NCUC allowed the recovery of the North Carolina portion of these assets, totaling $3.8 million, over the three-year period beginning November 1, 2000. Further evaluations of the three remaining sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on financial position or results of operations. ACCOUNTING PRONOUNCEMENTS Effective November 1, 2000, we will adopt SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging Activities". We have evaluated current gas supply and insurance contracts and leases. We believe the adoption of FAS 133 will not have a material effect on financial position or results of operations. 21 24 SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (FAS 140), replaces FAS 125. FAS 140 clarifies issues that arose from FAS 125 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. We believe the adoption of FAS 140 will not have a material effect on results of operations or financial position. In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin 101, "Revenue Recognition in Financial Statements" (SAB 101), to provide guidance on the recognition, presentation and disclosure of revenue in the financial statements. For us, the effective date is the fourth quarter of fiscal 2001. We believe the adoption of SAB 101 will not have a material effect on results of operations. Item 7A. Quantitative and Qualitative Disclosures about Market Risk The information required by this item is set forth in Note 5, Financial Instruments and Related Fair Value, in Item 8 of this report on page 35. 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 53. 22 25 BLANK PAGE 23 26 CONSOLIDATED BALANCE SHEETS October 31, 2000 and 1999 ASSETS
2000 1999 ---------- ---------- (in thousands) Utility Plant: Utility plant in service $1,464,392 $1,378,241 Less accumulated depreciation 462,955 420,140 ---------- ---------- Utility plant in service, net 1,001,437 958,101 Construction work in progress 69,570 63,081 ---------- ---------- Total utility plant, net 1,071,007 1,021,182 ---------- ---------- Other Physical Property, at cost (net of accumulated depreciation of $1,187,000 in 2000 and $18,967,000 in 1999) 976 25,793 ---------- ---------- Current Assets: Cash and cash equivalents 8,747 6,174 Restricted cash 39,796 40,156 Receivables (less allowance for doubtful accounts of $482,000 in 2000 and $864,000 in 1999) 55,145 32,106 Receivables from affiliate -- 22,354 Inventories: Gas in storage 67,709 48,685 Materials, supplies and merchandise 6,041 6,294 Deferred cost of gas 13,228 8,267 Refundable income taxes 69,118 17,670 Prepayments 24,451 16,689 ---------- ---------- Total current assets 284,235 198,395 ---------- ---------- Deferred Charges and Other Assets: Unamortized debt expense (amortized over life of related debt on a straight-line basis) 3,938 4,009 Investments in non-utility activities 67,175 29,115 Other 17,672 10,163 ---------- ---------- Total deferred charges and other assets 88,785 43,287 ---------- ---------- Total $1,445,003 $1,288,657 ========== ==========
See notes to consolidated financial statements. 24 27
CAPITALIZATION AND LIABILITIES 2000 1999 ---------- ---------- (in thousands) Capitalization: Stockholders' equity: Cumulative preferred stock - no par value - 175,000 shares authorized $ -- $ -- Common stock - no par value - 100,000,000 shares authorized; outstanding, 31,914,191 shares in 2000 and 31,294,955 in 1999 314,230 297,149 Retained earnings 213,142 194,598 ---------- ---------- Total stockholders' equity 527,372 491,747 Long-term debt 451,000 423,000 ---------- ---------- Total capitalization 978,372 914,747 ---------- ---------- Current Liabilities: Current maturities of long-term debt and sinking fund requirements 32,000 2,000 Notes payable 99,500 79,500 Accounts payable 87,604 63,116 Customers' deposits 9,110 8,477 Deferred income taxes 8,678 23,002 General taxes accrued 11,205 11,904 Refunds due customers 32,889 26,204 Other 16,011 12,501 ---------- ---------- Total current liabilities 296,997 226,704 ---------- ---------- Deferred Credits and Other Liabilities: Unamortized federal investment tax credits 6,707 7,265 Accumulated deferred income taxes 145,070 116,134 Other 17,857 23,807 ---------- ---------- Total deferred credits and other liabilities 169,634 147,206 ---------- ---------- Total $1,445,003 $1,288,657 ========== ==========
See notes to consolidated financial statements. 25 28 STATEMENTS OF CONSOLIDATED INCOME For the Years Ended October 31, 2000, 1999 and 1998
2000 1999 1998 --------- --------- --------- (in thousands except per share amounts) Operating Revenues $ 830,377 $ 686,470 $ 765,277 Cost of Gas 512,046 365,962 442,422 --------- --------- --------- Margin 318,331 320,508 322,855 --------- --------- --------- Other Operating Expenses: Operations 109,942 101,263 104,933 Maintenance 17,059 15,562 14,708 Depreciation 48,894 44,131 42,175 General taxes 18,761 29,465 32,633 Income taxes 33,975 38,365 37,249 --------- --------- --------- Total other operating expenses 228,631 228,786 231,698 --------- --------- --------- Operating Income 89,700 91,722 91,157 --------- --------- --------- Other Income (Expense): Non-utility activities, net of income taxes 11,523 (2,007) 684 Other, net of income taxes (241) 863 1,659 --------- --------- --------- Total other income (expense) 11,282 (1,144) 2,343 --------- --------- --------- Income Before Utility Interest Charges 100,982 90,578 93,500 --------- --------- --------- Utility Interest Charges: Interest on long-term debt 33,890 31,005 31,507 Allowance for borrowed funds used during construction (credit) (3,321) (2,027) (1,242) Other interest 6,382 3,393 2,922 --------- --------- --------- Total utility interest charges 36,951 32,371 33,187 --------- --------- --------- Net Income $ 64,031 $ 58,207 $ 60,313 ========= ========= ========= Average Shares of Common Stock: Basic 31,600 31,013 30,472 Diluted 31,779 31,242 30,717 Earnings Per Share of Common Stock: Basic $ 2.03 $ 1.88 $ 1.98 Diluted $ 2.01 $ 1.86 $ 1.96
See notes to consolidated financial statements. 26 29 STATEMENTS OF CONSOLIDATED CASH FLOWS For the Years Ended October 31, 2000, 1999 and 1998
2000 1999 1998 --------- --------- --------- (in thousands) Cash Flows from Operating Activities: Net income $ 64,031 $ 58,207 $ 60,313 --------- --------- --------- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 52,090 47,917 46,113 Deferred income taxes 14,612 12,918 10,693 Amortization of investment tax credits (558) (558) (558) Allowance for funds used during construction (3,321) (3,461) (2,611) Net gain on propane business combination, net of tax (5,063) -- -- Changes in assets and liabilities: Restricted cash 360 (12,672) (6,099) Receivables (22,677) (7,647) 7,908 Receivables from affiliate 22,354 (22,354) -- Inventories (18,553) (6,841) 6,319 Other assets, net (70,596) (23,832) (19,706) Accounts payable 23,719 (4,180) 2,193 Refunds due customers 6,685 (2,204) 13,311 Other liabilities, net (8,433) (3,692) 5,512 --------- --------- --------- Total adjustments (9,381) (26,606) 63,075 --------- --------- --------- Net cash provided by operating activities 54,650 31,601 123,388 --------- --------- --------- Cash Flows from Investing Activities: Utility construction expenditures (105,329) (98,576) (90,898) Investment in propane partnership (30,552) -- -- Proceeds from propane business combination 36,748 -- -- Other (909) (1,643) (1,112) --------- --------- --------- Net cash used in investing activities (100,042) (100,219) (92,010) --------- --------- --------- Cash Flows from Financing Activities: Increase in bank loans, net 20,000 47,500 7,000 Proceeds from issuance of long-term debt 60,000 90,000 -- Retirement of long-term debt (2,000) (46,000) (10,000) Issuance of common stock through dividend reinvestment and employee stock plans 15,452 15,740 15,136 Dividends paid (45,487) (42,168) (39,004) --------- --------- --------- Net cash provided by (used in) financing activities 47,965 65,072 (26,868) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 2,573 (3,546) 4,510 Cash and Cash Equivalents at Beginning of Year 6,174 9,720 5,210 --------- --------- --------- Cash and Cash Equivalents at End of Year $ 8,747 $ 6,174 $ 9,720 ========= ========= ========= Cash Paid During the Year for: Interest $ 34,971 $ 32,647 $ 33,226 Income taxes $ 85,848 $ 38,983 $ 47,139
See notes to consolidated financial statements. 27 30 STATEMENTS OF CONSOLIDATED RETAINED EARNINGS For the Years Ended October 31, 2000, 1999 and 1998 2000 1999 1998 -------- -------- -------- (in thousands) Balance at Beginning of Year $194,598 $178,559 $157,250 Net Income 64,031 58,207 60,313 -------- -------- -------- Total 258,629 236,766 217,563 Deduct: Dividends declared on common stock ($1.44 a share in 2000, $1.36 in 1999 and $1.28 in 1998) 45,487 42,168 39,004 -------- -------- -------- Balance at End of Year $213,142 $194,598 $178,559 ======== ======== ======== See notes to consolidated financial statements. 28 31 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 our wholly owned subsidiaries. All revenues and expenses of non-state-regulated operations are included in other income in the consolidated income statements. Significant intercompany transactions have been eliminated in consolidation where appropriate. 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 $3,321,000 for 2000, $3,461,000 for 1999 and $2,611,000 for 1998. The portion of AFUDC attributable to equity funds is included in other 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 3.49% for 2000, 3.38% for 1999 and 3.43% for 1998. 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 review did not result in a material effect on results of operations or financial condition. 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 29 32 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 financial statements. 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, 2000, 1999 and 1998, is presented below: 2000 1999 1998 ------- ------- ------- (in thousands except per share amounts) Net Income $64,031 $58,207 $60,313 ======= ======= ======= Average shares of Common Stock outstanding for basic earnings per share 31,600 31,013 30,472 Contingently issuable shares under the Long-Term Incentive Plan 179 229 245 ------- ------- ------- Average shares of dilutive stock 31,779 31,242 30,717 ======= ======= ======= Earnings Per Share: Basic $ 2.03 $ 1.88 $ 1.98 Diluted $ 2.01 $ 1.86 $ 1.96 H. Rate-Regulated Basis of Accounting. Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71), provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner 30 33 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 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, 2000 and 1999, are summarized as follows: 2000 1999 ------- ------- (in thousands) Regulatory Assets Unamortized debt expense $ 3,938 $ 4,009 Environmental 6,959 6,987 Deferred taxes 9,990 -- Demand-side management costs 4,676 3,937 Deferred Year 2000 costs 603 1,321 Deferred pension expense 948 1,016 Other 2,519 1,171 ------- ------- Total $29,633 $18,441 ======= ======= Regulatory Liabilities Refunds due customers $32,889 $26,204 Deferred taxes -- 7,971 Deferred incentive plan 507 110 ------- ------- Total $33,396 $34,285 ======= ======= 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. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 138, requires all derivative instruments to be recognized on the balance sheet at their fair value. Changes in the fair value of derivatives are to be recorded each period either in other comprehensive income or in 31 34 current earnings depending on the use of the derivative and whether it qualifies for hedge accounting. FAS 133, as amended by SFAS No. 137, which deferred the effective date, is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. We will adopt FAS 133 on November 1, 2000. We have evaluated current gas supply and insurance contracts and leases. We believe the adoption of FAS 133 will not have a material effect on results of operations or financial position. SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (FAS 140), replaces FAS 125. FAS 140 clarifies issues that arose from FAS 125 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. We believe the adoption of FAS 140 will not have a material effect on results of operations or financial position. In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin 101, "Revenue Recognition in Financial Statements" (SAB 101), to provide guidance on the recognition, presentation and disclosure of revenue in the financial statements. For us, the effective date is the fourth quarter of fiscal 2001. We believe the adoption of SAB 101 will not have a material effect on results of operations. K. Use of Estimates. We make estimates and assumptions when preparing 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 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 1999 and 1998 to conform with the 2000 presentation. 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 32 35 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. The NCUC has authorized us to use $38,527,000 of the expansion funds to extend natural gas service to the counties of Avery, Mitchell and Yancey, of which $3,000,000 has been used as of October 31, 2000. The total cost of the project is estimated to be $44,534,000. As of October 31, 2000, the North Carolina State Treasurer held $39,911,000 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 sheet. On December 30, 1999, we filed with the TRA for a general rate increase of $10,688,000 annually. On May 18, 2000, we filed with the TRA a stipulation with the Consumer Advocate Division of the Attorney General of the State of Tennessee that would permit us to increase our rates by $4,944,000 annually. The TRA approved the settlement on June 5 and issued an order on July 28. New rates became effective on July 1, 2000. On March 1, 2000, we filed with the NCUC for a general rate increase of $19,007,000 annually, including an increase in customers' rates of $14,505,000. We, the Public Staff of the NCUC and Carolina Utility Customers Association, Inc. (an association of industrial users), presented a stipulated agreement on all issues in the case to the NCUC at a hearing on September 5. Among other things, the stipulation called for a margin increase of $9,722,000, including a rate increase to customers of $6,001,000. The NCUC issued an order approving the stipulation on October 5. New rates are effective on November 1, 2000. On October 11, 2000, we signed an agreement with Atmos Energy Corporation to purchase their natural gas distribution assets located in the city of Gaffney and portions of Cherokee County, South Carolina. The acquisition will be at net book value of approximately $6,600,000 and will add 5,400 customers and $2,200,000 of margin to our operations. The acquisition is subject to the approval of the PSCSC which has set the matter for hearing on December 27, 2000. If approved, closing is anticipated to be effective on January 1, 2001. 33 36 3. Long-Term Debt Long-term debt at October 31, 2000 and 1999, is summarized as follows: 2000 1999 -------- -------- (in thousands) Senior Notes: 9.19%, due 2001 $ 30,000 $ 30,000 10.06%, due 2004 8,000 10,000 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 -- 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 483,000 425,000 Less current maturities 32,000 2,000 -------- -------- Total $451,000 $423,000 ======== ======== Annual sinking fund requirements and maturities through 2005 are $32,000,000 in 2001, $2,000,000 in 2002, $47,000,000 in 2003, $2,000,000 in 2004 and zero in 2005. On September 29, 2000, we issued $60,000,000 of 7.80% medium-term notes remaining under a shelf registration statement for $150,000,000 of debt securities that was filed with the Securities and Exchange Commission in 1997. The note is to be redeemed in a single payment at maturity in 2010. 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, 2000, all retained earnings were free of such restrictions. 4. Capital Stock The changes in Common Stock for the years ended October 31, 1998, 1999 and 2000, are summarized as follows: 34 37 Shares Amount ---------- ---------- (in thousands) Balance, October 31, 1997 30,193,014 $ 262,576 Issue to participants in the Employee Stock Purchase Plan (SPP) 18,668 555 Issue to the Dividend Reinvestment and Stock Purchase Plan (DRIP) 464,040 14,582 Issue to participants in the Long-Term Incentive Plan (LTIP) 62,261 1,996 ---------- ---------- Balance, October 31, 1998 30,737,983 279,709 Issue to SPP 25,945 777 Issue to DRIP 479,507 14,963 Issue to LTIP 51,520 1,700 ---------- ---------- Balance, October 31, 1999 31,294,955 297,149 Issue to SPP 20,219 517 Issue to DRIP 547,918 14,935 Issue to LTIP 51,099 1,629 ---------- ---------- Balance, October 31, 2000 31,914,191 $ 314,230 ========== ========== At October 31, 2000, 2,650,625 shares of Common Stock were reserved for issuance as follows: SPP 180,796 DRIP 1,580,448 LTIP 889,381 --------- Total 2,650,625 ========= 5. Financial Instruments and Related Fair Value Various banks provide lines of credit totaling $75,000,000 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, 2000, the lines of credit were on a fee basis. At October 31, 2000, outstanding notes payable consisted of $30,000,000 in discounted bank loans, $35,000,000 in LIBOR cost-plus loans and $34,500,000 in overnight cost-plus loans. The weighted average interest rate on such borrowings was 7.03%. Our principal business activity is the distribution of natural gas to customers located in North Carolina, South Carolina and Tennessee. At October 31, 2000, gas receivables totaled $46,342,000 and other receivables totaled $9,285,000. The uncollected balance of installment receivables that were 35 38 transferred with recourse was $18,699,000 at October 31, 2000 and 1999. We have provided an adequate allowance for any receivables which may not be ultimately collected, including the receivables transferred with recourse. During 1999 and 2000, Piedmont Energy Company, a wholly owned subsidiary, who 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 at an annual fixed rate equal to LIBOR plus 85 basis points, with interest payable quarterly, until June 27, 2000, when the interest rate changed to prime plus 200 basis points. On October 20, 2000, SouthStar repaid all outstanding loans plus interest, less $7,500,000 which was retained as a capital contribution. During the twelve months 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 provided for each member to contribute additional capital during August and 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. The carrying amounts in the consolidated balance sheets of cash and cash equivalents, restricted cash, receivables, notes payable and accounts payable approximated 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, 2000 and 1999, including current portion, were as follows: 2000 1999 ----------------- ----------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- ----- -------- ----- (in thousands) Long-term debt $483,000 $480,092 $425,000 $427,936 36 39 The use of different market assumptions or estimation methodologies may 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. We engage in minimal derivative products activities, such as exchange-traded futures and over-the-counter forward contracts, to manage commodity price and basis risk when appropriate. The hedging activities permit us to translate physical market activities into a common pricing index against which transaction values will be measured at the margin. Under internal guidelines, we utilize limited speculative positions in the derivatives market or in the form of fixed-price gas supply contracts. Our derivative products activity is not material to financial position or results of operations. We believe the accounting for this derivative activity will not be impacted materially by the adoption of FAS 133 on November 1, 2000. 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. As of October 31, 2000, the liability associated with such benefits was 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, 2000 and 1999, and a statement of the funded status as recognized in the consolidated balance sheets as of October 31, 2000 and 1999, are presented below: 37 40
Pension Benefits Other Benefits -------------------------- -------------------------- 2000 1999 2000 1999 --------- --------- --------- --------- (in thousands) Change in benefit obligation Obligation at beginning of year $ 115,593 $ 119,572 $ 23,972 $ 22,936 Service cost 5,203 5,388 581 648 Interest cost 9,040 7,309 1,793 1,443 Plan amendments 4,433 -- -- -- Curtailment gain (1,938) -- (48) -- Actuarial (gain) loss (449) (9,761) (2,741) 871 Benefit payments (9,170) (6,915) (1,689) (1,926) --------- --------- --------- --------- Obligation at end of year $ 122,712 $ 115,593 $ 21,868 $ 23,972 ========= ========= ========= ========= Change in fair value of plan assets Fair value of plan assets at beginning of year $ 161,915 $ 149,453 $ 8,574 $ 7,172 Actual return on plan assets 8,289 19,377 534 287 Employer contributions -- -- 2,332 2,789 Benefit payments (9,170) (6,915) (1,085) (1,674) --------- --------- --------- --------- Fair value of plan assets at end of year $ 161,034 $ 161,915 $ 10,355 $ 8,574 ========= ========= ========= ========= Funded status Funded status at end of year $ 38,322 $ 46,322 $ (11,513) $ (15,398) Unrecognized transition obligation 41 60 11,429 13,018 Unrecognized prior-service cost 7,281 4,426 -- -- Unrecognized (gain) loss (52,549) (58,949) (701) 2,096 --------- --------- --------- --------- Accrued benefit liability $ (6,905) $ (8,141) $ (785) $ (284) ========= ========= ========= =========
Net periodic benefit cost for the years ended October 31, 2000, 1999 and 1998, includes the following components: 38 41
Pension Benefits Other Benefits ---------------------------------------- ---------------------------------------- 2000 1999 1998 2000 1999 1998 -------- -------- -------- -------- -------- -------- (in thousands) Service cost $ 5,203 $ 5,388 $ 5,228 $ 581 $ 648 $ 620 Interest cost 9,040 7,309 7,663 1,793 1,443 1,489 Expected return on plan assets (13,488) (12,079) (11,474) (568) (497) (393) Amortization of transition obligation 15 15 15 930 930 930 Amortization of prior-service cost 824 543 459 -- -- -- Curtailment expense -- -- -- 660 -- -- Amortization of net (gain) loss (1,651) (959) (565) 42 232 108 -------- -------- -------- -------- -------- -------- Net periodic benefit cost $ (57) $ 217 $ 1,326 $ 3,438 $ 2,756 $ 2,754 ======== ======== ======== ======== ======== ========
The curtailment gain included in the 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 asset 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 as of October 31, 2000, 1999 and 1998, are presented below: 39 42
Pension Benefits Other Benefits -------------------------------- ---------------------------------- 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- Discount rate 7.5% 7.5% 6.5% 7.75% 7.75% 6.75% Expected long-term rate of return on plan assets 9.5% 9.5% 9.5% 9.5% 9.5% 9.5% Rate of compensation increase 5.5% 5.5% 4.5% 4.5% 4.5% 4.5%
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation for participants aged less than 65 for the medical plans is 6.75% for 2000, declining gradually to 5% in 2003 and remaining at that level thereafter. For those participants aged greater than 65, the assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation for the medical plans is 9.75% for 2000, declining gradually to 5% in 2007 and remaining at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage point change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease ----------- ----------- (in thousands) Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 94 $ (83) Effect on the health care component of the accumulated postretirement benefit obligation $1,020 $ (902) 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, 2000, 1999 and 1998, we contributed $2,273,000, $2,298,000 and $2,135,000, respectively, in matching contributions to the plans. 40 43 7. Income Taxes The components of income tax expense for the years ended October 31, 2000, 1999 and 1998, are as follows:
2000 1999 1998 ----------------------- ----------------------- ----------------------- Federal State Federal State Federal State -------- -------- -------- -------- -------- -------- (in thousands) Income taxes charged To operations: Current $ 21,675 $ 4,615 $ 28,005 $ 5,972 $ 23,101 $ 4,912 Deferred 6,784 1,459 4,071 875 8,035 1,759 Amortization of investment tax credits (558) -- (558) -- (558) -- -------- -------- -------- -------- -------- -------- Total 27,901 6,074 31,518 6,847 30,578 6,671 -------- -------- -------- -------- -------- -------- Income taxes charged To other income: Current 829 183 (591) (129) 451 208 Deferred 5,242 1,127 -- -- 834 65 -------- -------- -------- -------- -------- -------- Total 6,071 1,310 (591) (129) 1,285 273 -------- -------- -------- -------- -------- -------- Total income tax expense $ 33,972 $ 7,384 $ 30,927 $ 6,718 $ 31,863 $ 6,944 ======== ======== ======== ======== ======== ========
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended October 31, 2000, 1999 and 1998, is as follows:
2000 1999 1998 -------- -------- -------- (in thousands) Federal taxes at 35% $ 36,892 $ 33,566 $ 34,692 State income taxes, net of federal benefit 4,800 4,367 4,510 Amortization of investment tax credits (558) (558) (558) Other, net 222 270 163 -------- -------- -------- Total income tax expense $ 41,356 $ 37,645 $ 38,807 ======== ======== ========
At October 31, 2000 and 1999, deferred income taxes consist of the following temporary differences: 2000 1999 --------- --------- (in thousands) Excess of utility tax over book depreciation And tax and book asset basis differences $ 133,338 $ 124,177 Revenues and cost of gas 14,526 21,550 Other, net 5,884 (6,591) --------- --------- Net deferred income taxes $ 153,748 $ 139,136 ========= ========= Total deferred income tax liabilities were $159,975,000 and $151,824,000 and total deferred income tax assets were $6,227,000 and $12,688,000 at October 31, 2000 and 1999, respectively. 41 44 8. Business Segments and Other Non-Utility Activities We have one reportable segment, domestic natural gas distribution. Our reportable segment is operated and managed as three strategic business units and is organized based on products and services and regulatory environments. Our domestic natural gas distribution 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. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates a 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. Since November 1, 1999, our share of the operations of Cardinal is accounted for in non-utility operations. 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. (Pine Needle), a North Carolina limited liability company. Pine Needle owns a liquified natural gas (LNG) peak-demand facility in North Carolina. Storage capacity is four billion cubic feet with vaporization capability of 400 million cubic feet per day. We subscribe to one-half of this capacity to provide gas for peak-use periods when demand is the highest. The accounting policies of our domestic natural gas distribution segment are described in the summary of significant accounting policies in Note 1. Performance is evaluated 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 exceeded 10% or more of our consolidated revenues. 42 45 All of our other activities are included in Other in the segment tables and consist of the following: o Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners, 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. On August 10, 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 for $181,395,000 in cash, assumed debt and common and limited partnership units and purchasing all of the outstanding stock of Heritage 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. US Propane owns all of the general partnership interest and approximately 34% of the limited partnership interest in Heritage. Heritage distributes propane through a nationwide retail distribution network consisting of over 225 customer service locations in 28 states. o Piedmont Energy Company, a wholly owned subsidiary of Piedmont Energy Partners, 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. Continuing operations by segment for the years ended October 31, 2000, 1999 and 1998, are presented below:
Domestic Natural Gas Distribution Other Total ------------ ----------- ----------- (in thousands) 2000 Revenues from external customers $ 830,377 $ 29,967 $ 860,344 Margin 318,331 11,917 330,248 Operations and maintenance expenses 127,004 9,004 136,008 Depreciation and amortization 48,894 1,744 50,638 Operating income 90,971 617 91,588 Interest expense 40,272 698 40,970 Other income 9,863 10,059 19,922 Income before income taxes 93,258 12,129 105,387 Total assets 1,437,950 44,014 1,481,964 Capital expenditures 108,804 755 109,559
43 46 1999 Revenues from external customers $ 686,470 $ 28,250 $ 714,720 Margin 320,508 13,896 334,404 Operations and maintenance expenses 116,825 9,058 125,883 Depreciation and amortization 44,131 2,133 46,264 Operating income 91,706 2,046 93,752 Interest expense 32,371 443 32,814 Other income 4,915 (8,842) (3,927) Income before income taxes 102,657 (6,805) 95,852 Total assets 1,304,453 59,997 1,364,450 Capital expenditures 102,235 1,429 103,664 1998 Revenues from external customers $ 765,277 $ 32,911 $ 798,188 Margin 322,855 14,512 337,367 Operations and maintenance expenses 119,641 10,116 129,757 Depreciation and amortization 42,175 2,184 44,359 Operating income 91,107 1,506 92,613 Interest expense 33,187 622 33,809 Other income 4,699 (1,631) 3,068 Income before income taxes 99,868 (747) 99,121 Total assets 1,155,866 41,223 1,197,089 Capital expenditures 93,520 1,105 94,625
A reconciliation to the consolidated financial statements for the years ended October 31, 2000, 1999 and 1998, is presented below:
2000 1999 1998 ----------- ----------- ----------- (in thousands) Consolidated Revenues (1): Revenues for reportable segments $ 830,377 $ 686,470 $ 765,277 Net Income: Income before income taxes for Reportable segments $ 93,258 $ 102,657 $ 99,868 Income before income taxes for Other non-utility activities 12,129 (6,805) (747) Income taxes 41,356 37,645 38,808 ----------- ----------- ----------- Net income $ 64,031 $ 58,207 $ 60,313 =========== =========== =========== Consolidated Assets: Total assets for reportable Segments $ 1,437,950 $ 1,304,453 $ 1,155,866 Other assets 44,014 59,997 41,223 Eliminations/Adjustments (36,961) (75,793) (34,245) ----------- ----------- ----------- Consolidated assets $ 1,445,003 $ 1,288,657 $ 1,162,844 =========== =========== ===========
(1) Operating revenues shown in the consolidated financial statements represent revenues from utility operations only. 44 47 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. As of October 31, 2000, we had an environmental liability of $1,360,000 for the remaining three MGP sites not covered by the settlement. This liability is estimated based on a generic MGP site study as we have not performed site-specific evaluations. During 2000, we learned that a tract of land in North Carolina that was owned by us during the period 1951 through 1956 has been identified as a possible MGP site. Based on information available to us and due to the small size of the tract, we do not believe that the tract ever contained an MGP. A third party is in the process of evaluating this site. Until the third party completes its evaluation, we are unable to determine if we may have any potential liability with respect to this site. However, due to the size of and our limited connection with this site, we do not expect any such liability to be material. 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. In connection with the settlement noted above and the estimated liability for the remaining sites, we have recorded a regulatory asset of $6,610,000. As of October 31, 2000, we had an additional regulatory asset in the amount of $349,000, net of recoveries from customers, for other environmental costs, primarily legal fees and engineering assessments. In connection with the general rate case in North Carolina discussed in Note 2, the NCUC allowed the recovery of the North Carolina portion of these assets, totaling $3,808,000, over the three-year period beginning November 1, 2000. Further evaluations of the three remaining sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on financial position or results of operations. 45 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 generally accepted accounting principles 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 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 46 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, 2000 and 1999, and the related statements of consolidated income, retained earnings and cash flows for each of the three years in the period ended October 31, 2000. Our audits also included the supplemental consolidated financial statement schedule listed in 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 and financial statement schedule 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended October 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /s/ DELOITTE & TOUCHE LLP Charlotte, North Carolina December 8, 2000 47 50 QUARTERLY FINANCIAL DATA Quarterly financial data for 2000 and 1999 is summarized as follows:
Earnings Per Share of Operating Operating Net Common Stock Revenues Margin Income Income Basic Diluted - ----------------------------------------------------------------------------------------------------- (in thousands except per share amounts) 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* $147,563 $ 42,624 $ (716) $ (7,253) $ (.23) $ (.23) 1999 January 31 $255,742 $121,556 $ 47,506 $ 40,564 $ 1.32 $ 1.31 April 30 $239,247 $113,774 $ 42,201 $ 34,667 $ 1.12 $ 1.11 July 31 $ 96,728 $ 44,425 $ 1,860 $ (8,216) $ (.26) $ (.26) October 31 $ 94,753 $ 40,753 $ 155 $ (8,808) $ (.28) $ (.28)
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. *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. 48 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 17, 2001, and is incorporated herein by reference. All of our officers' names, ages and positions as of October 31, 2000, 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, 2000. Business Experience Name, Age and Position During Past Five Years - ---------------------- ---------------------- Ware F. Schiefer, 62 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, 49 Elected in 1995. Senior Vice President and Chief Financial Officer 49 52 Ray B. Killough, 52 Elected in 1993. Senior Vice President - Operations Thomas E. Skains, 44 Elected in 1995. Senior Vice President - Marketing and Supply Services John L. Clark, Jr., 57 Elected in 1998. Prior to Vice President - Tennessee his election, he was Operations Vice President - Operations of the Nashville Division. Ted C. Coble, 57 Elected in 1982. Vice President and Treasurer, and Assistant Secretary Stephen D. Conner, 52 Elected in 1990. Vice President - Corporate Communications Nicholas Emanuel, 51 Elected in 1998. Prior to Vice President - Engineering his election, he was Director - Engineering. Charles W. Fleenor, 50 Elected in 1987. Vice President - Gas Services Paul C. Gibson, 61 Elected in 1986. Vice President - Rates Barry L. Guy, 56 Elected in 1986. Vice President and Controller Donald F. Harrow, 45 Elected in 1992. Vice President - Governmental Relations Dale C. Hewitt, 55 Elected in 1993. Vice President - North Carolina Operations Richard A. Linville, 53 Elected in 1997. Prior to Vice President - Human Resources his election, he was Vice President - Human 50 53 Resources of Harriet and Henderson Yarns, Inc., Henderson, North Carolina. June B. Moore, 47 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, 42 Elected in 1993. Vice President - Corporate Planning Martin C. Ruegsegger, 50 Elected in 1997. Prior to Vice President, Corporate Counsel his election, he was and Secretary Corporate Secretary. David L. Trusty, 43 Elected in 1997. Prior to Vice President - Marketing his election, he was Vice President - Marketing of the Nashville Division. Ronald J. Turner, 54 Elected in 1976. Assistant Treasurer Ranelle Q. Warfield, 43 Elected in 1997. Prior to Vice President - Sales her election, she was Director - Marketing. William D. Workman, III, 60 Elected in 1993. Vice President - South Carolina Operations Item 11. Executive Compensation Information required under this item is contained in our proxy statement filed with the SEC on or about January 17, 2001, and is incorporated herein by reference. 51 54 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 17, 2001, and is incorporated herein by reference. (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 17, 2001, 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 17, 2001, and is incorporated herein by reference. 52 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, 2000, are included in Item 8 of this report as follows: Page ---- Consolidated Balance Sheets - October 31, 2000 and 1999 24 Statements of Consolidated Income - Years Ended October 31, 2000, 1999 and 1998 26 Statements of Consolidated Cash Flows - Years Ended October 31, 2000, 1999 and 1998 27 Statements of Consolidated Retained Earnings - Years Ended October 31, 2000, 1999 and 1998 28 Notes to Consolidated Financial Statements 29 Management's Responsibility for Financial Reporting 46 Independent Auditors' Report 47 (a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULE Page ---- II Valuation and Qualifying Accounts 65 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 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. 53 56 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). 3.2 By-Laws of the Company, as amended, dated February 25, 2000 (Exhibit No. 3.1, Form 10-Q for the quarter ended January 31, 2000). 3.3 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). 54 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). 10.1 Executive Long-Term Incentive Plan (Exhibit 99.1, Registration Statement No. 333-34435). 10.2 Articles of Merger of Cardinal Extension Company, LLC, and Cardinal Pipeline Company, LLC, dated October 27, 1999 (Exhibit 10.7, Form 10-K for the fiscal year ended October 31, 1999). 10.3 Service Agreement under Rate Schedule LG-A, dated January 15, 1971, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 67, Registration Statement No. 2-59631). 55 58 10.4 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). 10.5 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). 10.6 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). 10.7 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). 10.8 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). 10.9 Gas Transportation Agreement for Use Under FT-A Rate Schedule (Contract No. 237) (FTA, 130,000 Dt/day), dated September 1, 1993, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.30, Form 10-K for the fiscal year ended October 31, 1993). 10.10 Gas Storage Contract for Use Under Rate Schedule FS (Contract No. 2400) (672,091 Dt total capacity), dated September 1, 1993, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.31, Form 10-K for the fiscal year ended October 31, 1993). 10.11 FTS Service Agreement (23,000 Dt/day), dated November 1, 1993, between the Company and Columbia Gas Transmission 56 59 Corporation (Exhibit 10.24, Form 10-K for the fiscal year ended October 31, 1994). 10.12 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). 10.13 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). 10.14 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). 10.15 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). 10.16 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). 10.17 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). 10.18 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). 57 60 10.19 Letter of Agreement of Amendment No. 1 to Gas Storage Service Agreement (50,798 Mcf maximum storage withdrawal per day) (Contract No. 6815), dated July 1, 1995, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.24, Form 10-K for the fiscal year ended October 31, 1996). 10.20 Letter of Agreement of Amendment No. 1 to Gas Storage Service Agreement (6,190 Mcf maximum storage withdrawal per day) (Contract No. 2400), dated July 1, 1995, between the Company and Tennessee Gas Pipeline Company (Exhibit 10.25, Form 10-K for the fiscal year ended October 31, 1996). 10.21 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). 10.22 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). 10.23 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). 10.24 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). 10.25 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). 58 61 10.26 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). 10.27 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). 10.28 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). 10.29 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). 10.30 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). 10.31 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). 10.32 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). 10.33 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). 10.34 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). 10.35 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). 59 62 10.36 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, 2000). 10.37 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). 10.38 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). 10.39 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). 10.40 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). 10.41 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). 10.42 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). 60 63 10.43 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). 10.44 Loan Agreement between SouthStar Energy Services, LLC, Georgia Natural Gas Company, Piedmont Energy Company and Dynegy Hub Services Inc., dated June 30, 1999 (Exhibit 10.52, Form 10-K for the fiscal year ended October 31, 1999). 10.45 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). 10.46 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). 10.47 Amendment to Service Agreement under Rate Schedule LG-A (Storage of 72,770 Mcf), dated August 30, 1996, between the Company and Transcontinental Gas Pipe Line Corporation (Exhibit 10.56, Form 10-K for the fiscal year ended October 31, 1999). 10.48 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). 10.49 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). 10.50 Service Agreement (15,000 dekatherms per day), dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC. 61 64 10.51 Letter of Right of First Refusal, dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC. 10.52 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. 10.53 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. 10.54 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. 10.55 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. 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 On August 22, 2000, we filed a Form 8-K reporting the August 10 closing of the combination of US Propane, L.P., with Heritage Holdings, Inc., the general partner of Heritage Propane Partners, L.P. (NYSE: HPG), to create the fourth-largest retail propane distributor in the United States. 62 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, 2001. 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, 2001. 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 63 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/ Sam J. DiGiovanni Director - ----------------------------- Sam J. DiGiovanni /s/ John W. Harris Director - ----------------------------- John W. Harris /s/ Muriel W. Helms Director - ----------------------------- Muriel W. Helms /s/ Ned R. McWherter Director - ----------------------------- Ned R. McWherter /s/ John H. Maxheim Chairman of the Board and Director - ----------------------------- John H. Maxheim /s/ Walter S. Montgomery, Jr. Director - ----------------------------- Walter S. Montgomery, Jr. Director - ----------------------------- Donald S. Russell, Jr. /s/ John E. Simkins, Jr. Director - ----------------------------- John E. Simkins, Jr. 64 67 Schedule II Piedmont Natural Gas Company, Inc. and Subsidiaries Valuation and Qualifying Accounts For the Years Ended October 31, 2000, 1999 and 1998 - -------------------------------------------------------------------------------- Balance at Additions Balance Beginning Charged to Deductions at End Description of Period Costs and Expenses (A) of Period - -------------------------------------------------------------------------------- (in thousands) Allowance for doubtful accounts: 2000 $ 864 $3,224 $3,606 $ 482 1999 2,314 705 2,155 864 1998 2,027 2,508 2,221 2,314 (A) Uncollectible accounts written off, net of recoveries and adjustments. 65 68 Piedmont Natural Gas Company, Inc. Form 10-K For the Fiscal Year Ended October 31, 2000 Exhibits 10.50 Service Agreement (15,000 dekatherms per day), dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC. 10.51 Letter of Right of First Refusal, dated September 13, 2000, between the Company and Pine Needle LNG Company, LLC. 10.52 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. 10.53 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. 10.54 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. 10.55 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. 12 Computation of Ratio of Earnings to Fixed Charges. 23 Independent Auditors' Consent. 99 Annual Report on Form 11-K. EX-10.50 2 g66462ex10-50.txt SERVICE AGREEMENT DATED 9/13/2000 1 Exhibit 10.50 Contract # 3.6724 SERVICE AGREEMENT between PINE NEEDLE LNG COMPANY, LLC and PIEDMONT NATURAL GAS COMPANY, INC. September 13, 2000 2 SERVICE AGREEMENT THIS AGREEMENT is entered into as of the 13th day of September, 2000, by and between Pine Needle LNG Company, LLC, a North Carolina limited liability company, hereinafter referred to as Pine Needle, and Piedmont Natural Gas Company, Inc., hereinafter referred to as Customer, W I T N E S S E T H: WHEREAS, Customer has requested firm storage service under Pine Needle's Rate Schedule LNG-1; and WHEREAS, Pine Needle is willing to provide the requested firm storage service for Customer pursuant to the terms and provisions of this Service Agreement and Rate Schedule LNG-1. NOW, THEREFORE, Pine Needle and Customer agree as follows: ARTICLE I SERVICE TO BE RENDERED Subject to the terms and provisions of this agreement and of Pine Needle's Rate Schedule LNG-1, as amended from time to time, Pine Needle agrees to receive and liquefy natural gas; store such gas in liquefied form; and vaporize and deliver such gas to Customer or for Customer's account, as follows: To withdraw from storage, vaporize and deliver the gas stored in liquefied form by Pine Needle for Customer's account up to a maximum quantity on any day of 15,000 dt, which quantity shall be Customer's Vaporization Quantity.* To receive and liquefy natural gas for Customer up to a maximum quantity on any day of 750 dt, which shall be Customer's Liquefaction Quantity.* To store in liquefied form for Customer's account up to a total quantity of 150,000 dt, which quantity shall be Customer's Storage Capacity. - ------------------ * In addition to these quantities, Pine Needle shall retain quantities of gas for fuel and gas otherwise used or lost and unaccounted for pursuant to Rate Schedule LNG-1. 3 SERVICE AGREEMENT (CONTINUED) ARTICLE II POINT OF RECEIPT AND DELIVERY 1. The Point of Receipt for all gas tendered to Pine Needle for liquefaction hereunder shall be at the following point: The interconnection between Pine Needle's 10-inch inlet pipeline and Transcontinental Gas Pipe Line Corporation's (Transco) mainline system at mile post 1356.95 on Transco's mainline in Guilford County, North Caroline. 2. The Point of Delivery for all gas delivered by Pine Needle to Customer or for the account of Customer shall be at the following point: The interconnection between Pine Needle's 24-inch outlet pipeline and Transco's mainline system at milepost 1356.95 in Guilford County, North Caroline. ARTICLE III TERM OF AGREEMENT This agreement shall be effective as of October 1, 2000 and shall remain in force and effect until March 31, 2005, and year to year thereafter, subject to termination by either party upon two (2) years prior written notice to the other. ARTICLE IV RATE SCHEDULE AND PRICE 1. Customer shall pay Pine Needle for service rendered hereunder in accordance with Pine Needle's Rate Schedule LNG-1 and the applicable provisions of the General Terms and Conditions of Pine Needle's Original Volume No. 1 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. 2. Pine Needle shall have the unilateral right to propose, file and make effective with the Federal Energy Regulatory Commission, or other regulatory authority having jurisdiction, changes and revisions to the rates and rate design proposed pursuant to Section 4 of the Natural Gas Act, or to propose, file and make effective superseding rates or rate schedules, for the purposes of changing the rates, charges, rate design, terms and conditions of service and other provisions thereof effective as to Customer; provided however that the (i) firm character of service, (ii) term of agreement (as set forth in Article III above), (iii) quantities, and (iv) points of receipt and delivery shall not be subject to unilateral change under this paragraph. Customer shall have the right to file with the Commission or other regulatory authority in opposition to any such filings or proposals by Pine Needle. 4 SERVICE AGREEMENT (CONTINUED) 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 the interpretation of the same. 2. This agreement supersedes and cancels as of the effective date hereof the following contracts between the parties hereto: (None) 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 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 North Carolina. 5. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns. 6. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address: (a) If to Pine Needle: Pine Needle LNG Company, LLC c/o Pine Needle Operating Company P.O. Box 1396 2800 Post Oak Boulevard 77056 Houston, Texas 77251-1396 Attention: Director - Customer Service and Scheduling (b) If to Customer: Piedmont Natural Gas Company, Inc. P. O. Box 33068 (1915 Rexford Road 28211) Charlotte, North Carolina 28233 Attention: Director - Federal Regulatory and Supply Planning Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party. 5 SERVICE AGREEMENT (CONTINUED) IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized on the day and year above written. PINE NEEDLE LNG COMPANY, LLC by its agent PINE NEEDLE OPERATING COMPANY By /s/ Frank J. Ferazzi ------------------------------- Frank J. Ferazzi Vice President PIEDMONT NATURAL GAS COMPANY,INC. By /s/ Thomas E. Skains ------------------------------- Thomas E. Skains Senior Vice President Gas Supply and Services EX-10.51 3 g66462ex10-51.txt LETTER OF RIGHT OF FIRST REFUSAL DATED 9/13/2000 1 Exhibit 10.51 PINE NEEDLE LNG COMPANY, LLC 2800 Post Oak Boulevard (77056) P. O. Box 1396 Houston, Texas 77251-1396 713/215-2000 September 13, 2000 Mr. Thomas Skains Senior Vice President - Marketing and Supply Services Piedmont Natural Gas Company, Inc. 1915 Rexford Road Charlotte, NC 28233 Re: Pine Needle LNG-1 Service Agreement Dear Mr. Skains: Pine Needle LNG Company, LLC ("Pine Needle") and Piedmont Natural Gas Company, Inc. ("Customer") are parties to that certain Service Agreement, dated September 13th, 2000 ("Service Agreement"), wherein the Customer shall receive up to 15,000 Dt per day of LNG vaporization service pursuant to Rate Schedule LNG-1. The parties herein desire to amend the Service Agreement to change the term provision. Accordingly, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: 1. Effective as of October 1, 2000 Article III of the Service Agreement shall be deleted in its entirety, and substituted therefor shall be the following: "TERM OF AGREEMENT This agreement shall be effective on October 1, 2000, and shall remain in force and effect until March 31, 2005. Notwithstanding the fact that Customer shall pay a discounted rate for service under the Service Agreement, Pine Needle hereby grants to Customer a contractual Right of First Refusal ("ROFR"). This ROFR will be procedurally administered in accordance with Section 23 of the General Terms and Conditions of Pine Needle's FERC Gas Tariff, as amended from time to time; provided that, in any event, Pine Needle shall provide notice of termination to Customer 180 days prior to the expiration of the Service Agreement to trigger the ROFR. Notwithstanding anything to the contrary in Pine Needle's FERC Gas Tariff, in order to retain service beyond the termination date pursuant its ROFR, Customer will required to match up to the maximum Pine Needle rate and the maximum contractual term with a five (5) year matching cap, as is allowed under a regulatory ROFR, of any bids submitted during an open season for this service." 2 Except as amended herein, all terms and conditions of the Service Agreement shall remain in full force and effect as written. If the foregoing is in accordance with your understanding of our agreement, please so indicate by executing both originals of this agreement in the space provided blow. Very truly yours, PINE NEEDLE LNG COMPANY By: /s/ Frank J. Ferazzi -------------------- Frank J. Ferazzi Vice President September 13, 2000 ACCEPTED AND AGREED: PIEDMONT NATURAL GAS COMPANY By: /s/ Thomas E. Skains -------------------- Thomas E. Skains Senior Vice President - Marketing and Supply Services September 13, 2000 EX-10.52 4 g66462ex10-52.txt LETTER OF AGREEMENT OF AMENDMENT NO. 343 1 Exhibit 10.52 August 3, 1998 Piedmont Natural Gas Company, Inc. 1915 Rexford Drive Charlotte, NC 28233 ATTN: Mr. Ken Valentine RE: AMENDMENT NO. 343 PURSUANT TO GAS TRANSPORTATION AGREEMENT DATED SEPTEMBER 1, 1993 SERVICE PACKAGE NO. 237 Dear Ken: Tennessee Gas Pipeline Company ("Tennessee") and PIEDMONT NATURAL GAS COMPANY, INC. ("Shipper") agree to amend the above-referenced Agreement ("Agreement") effective NOVEMBER 1, 2000, as reflected in the attached revised "Exhibit A" and as follows: The opening paragraph is deleted in its entirety and replaced by the following: THIS AGREEMENT is made and entered into as of the 1st day of September, 1993, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware corporation, hereinafter referred to as "Transporter" and PIEDMONT NATURAL GAS COMPANY, INC., a North Carolina corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to as the "Parties." ARTICLE I - DEFINITIONS, Section 1.1 is deleted in its entirety and replaced by the following: 1.1 TRANSPORTATION QUANTITY - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof which shall be 74,100 dekatherms (Dth). Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit A attached hereto. 2 Piedmont Natural Gas Company, Inc. Service Package No. 237 August 3, 1998 Page 2 ARTICLE XI - WARRANTIES, Section 11.2 is deleted in its entirety and replaced by the following: 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty by Shipper. Article XII - Term, Section 12.1 is deleted in its entirety and replaced by the following: Pursuant to the terms of the 1997 Stipulation and Agreement in Docket No. RP93-151, et al. ("Restructuring Cost Settlement") and Shipper's election to extend its firm service Agreement referenced on Appendix F to the Restructuring Cost Settlement, this Agreement shall be extended in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions as OF NOVEMBER 1, 2000, and shall remain in full force and effect until OCTOBER 31, 2004 ("Primary Extended Term"). Upon written notice given no later than twelve months before expiration of the Primary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement for a term of less than or equal to five years ("Secondary Extended Term") and for any Transportation Quantity up to the maximum daily quantity specified in Exhibit A hereto at the time of Shipper's election of the Secondary Extended Term in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Primary Extended Term to terminate this Agreement or to elect to extend the term of this Agreement for a term of less than or equal to five years, then the Secondary Extended term shall be for five years at the applicable maximum rates shown in the summary of Rates and Charges in Transporter's effective FERC Gas Tariff subject to the Rate Cap set forth in Article VIII of the Restructuring Cost Settlement during the period that such Rate Cap is in effect. Upon written notice given no later than twelve months before expiration of the Secondary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement. If Shipper elects to extend this Agreement, the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Secondary Extended Term to either terminate this Agreement or to elect to extend the term of this Agreement, then the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and 3 Piedmont Natural Gas Company, Inc. Service Package No. 237 August 3, 1998 Page 3 Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions. ARTICLE VIII - NOTICE, notices to Shipper shall be amended as follows: "Director - Federal Regulatory and Supply Planning" shall be substituted for "Keith Maust "Director - Gas Accounting" shall be substituted for "Ann Boggs" Except as specifically amended hereby, all terms and provisions of the Agreement shall remain in full force and effect as written. If the foregoing is in accordance with your understanding of our Agreement, please so indicate by signing and returning both originals of this letter to my attention. Upon Tennessee's execution, an original will be forwarded to PIEDMONT NATURAL GAS COMPANY, INC. for your files. Should you have any questions, please do not hesitate to contact me at (713) 757-6774. Best regards, TENNESSEE GAS PIPELINE COMPANY /s/ David L. Bowmaster David L. Bowmaster Account Manager ACCEPTED AND AGREED ACCEPTED AND AGREED BY: /s/ J. P. DICKERSON BY: /s/ C. W. FLEENOR ---------------------------- ------------------------------- NAME: J. P. DICKERSON NAME: C. W. FLEENOR --------------------------- ------------------------------ TITLE: DIRECTOR, MARKETING TITLE: VP GAS SERVICES -------------------------- ----------------------------- 4 GAS TRANSPORTATION AGREEMENT EXHIBIT "A" AMENDMENT #343 TO GAS TRANSPORTATION AGREEMENT DATED September 1, 1993 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND PIEDMONT NATURAL GAS COMPANY INC PIEDMONT NATURAL GAS COMPANY INC EFFECTIVE DATE OF AMENDMENT: November 1, 2000 RATE SCHEDULE: FT-A SERVICE PACKAGE: 237 SERVICE PACKAGE TQ: 74,100 Dth
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TQ BILLABLE-TQ - ----------------------------------------------------------------------------------------------------------------------------------- 001231 BRAZOS BLOCK 1338B TRANSCONTINENTAL GAS PIPE LINE OFFSHORE FEDERA OT 00 R 100 5,132 5,132 001419 BRAZOS 105 TRANSCONTINENTAL GAS PIPE LINE BRAZOS-SOUTH OT 00 R 100 1,054 1,054 010672 SOUTH PASS BLOCK 24 2 DEHYDRAT OCEAN ENERGY, INC. OFFSHORE-FEDERA OL 0L R 500 4,905 4,905 011119 CHEVRON-S MARSH IS BLK 61 C CHEVRON USA INC. OFFSHORE-FEDERA OL 0L R 500 13,244 13,244 011752 SCHOENFIELD DEHYDRATION #1 SANTA FE ENERGY RESOURCES INC MONTGOMERY TX 00 R 100 714 714 011844 UMC-BRIDGELINE-WEST CAMERSON BL ENERGY RESOURCE TECHNOLOGY, IN OFFSHORE-FEDERA OL 0L R 800 5,000 5,000 011978 VICTORIA -KENLON FIELD-MELTON CROSSTEX ENERGY SERVICES, LTD. JACKSON TX 00 R 100 243 243 011989 CHEVRON-SOUTH MARSH ISLAND 2 CHEVRON USA INC. OFFSHORE-FEDERA OL 0L R 800 6,321 6,321 012002 CHALKLEY TRANSPORT (Bi 20598 ANR PIPELINE CO JEFFERSON DAVIS LA 0L R 800 5,000 5,000 012087 VASTAR - MIAMI CORP DEHYD VASTAR GAS MARKETING, INC. CAMERON LA 0L R 800 5,000 5,000 012088 VALERO - MONTE CHRISTO EXCHANG VALERO TRANSMISSION LP HIDALGO TX 00 R 100 10,535 10,535 012123 VICTORIA - JACK STARR FIELD CROSSTEX ENERGY SERVICES, LTD. JACKSON TX 00 R 100 1,458 1,458 012138 VICTORIA - TEXAS GARDENS DEHYD CROSSTEX ENERGY SERVICES, LTD. HIDALGO TX 00 R 100 486 486 012157 ASSOCIATED - FENNER #1 DEHYD ASSOCIATED NATURAL GAS INC JACKSON TX 00 R 100 972 972 012169 COKINOS - DECKER'S PRAIRIE DEH MARINER ENERGY, INC. MONTGOMERY TX 00 R 100 1,841 1,841 012292 KOCH - SHELL-SOUTHTIMB. BLK 2 SHELL OFFSHORE INC OFFSHORE-FEDERA OL 0L R 500 5,095 5,095 012308 CHEVRON-S. TIMBALIER 23-CC CHEVRON USA INC. OFFSHORE-FEDERA OL 0L R 500 4,960 4,960 018055 VERMILLION 221 SHELL OFFSHORE INC OFFSHORE-FEDERA OL 0L R 800 2,140 2,140 Total Receipt TQ: 74,100 74,100 020312 NASHVILLE-NASHVILLE 2 TENN PIEDMONT NATURAL GAS COMPANY I ROBERTSON TN 01 D 500 74,100 74,100 020702 PETAL MISS STG TRANS (Bi 1-20 HATTIESBURG GAS STORAGE COMPAN FORREST MS 01 D 500 20,000 20,000 060020 TGP - PORTLAND STORAGE INJECTI TENNESSEE GAS PIPELINE COMPANY SUMNER TN 01 D 100 23,827 23,827
NUMBER OF RECEIPT POINTS AFFECTED: 18 NUMBER OF DELIVERY POINTS AFFECTED: 4 NOTE: EXHIBIT "A" IS A REFLECTION OF THE CONTRACT AND ALL AMENDMENTS AS OF THE AMENDMENT EFFECTIVE DATE. EX-10.53 5 g66462ex10-53.txt LETTER OF AGREEMENT OF AMEND. NO. 2A DATED 9/1/93 1 Exhibit 10.53 August 3, 1998 Piedmont Natural Gas Company, Inc. 1915 Rexford Drive Charlotte, NC 28233 ATTN: Ken Valentine RE: AMENDMENT NO. 2A TO GAS STORAGE CONTRACT DATED SEPTEMBER 1, 1993 SERVICE PACKAGE NO. 2400 Dear Ken: Tennessee Gas Pipeline Company ("Tennessee") and PIEDMONT NATURAL GAS COMPANY, INC. ("Shipper") agree to amend the above-referenced Agreement ("Agreement") effective NOVEMBER 1, 2000, as reflected in the attached revised "Exhibit A" and as follows: Article V - Term of Contract, is deleted in its entirety and replaced by the following: Pursuant to the terms of the 1997 Stipulation and Agreement in Docket No. RP93-151, et al. ("Restructuring Cost Settlement") and Shipper's election to extend its firm service Agreement referenced on Appendix F to the Restructuring Cost Settlement, this Agreement shall be extended in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions as OF NOVEMBER 1, 2000, and shall remain in full force and effect until OCTOBER 31, 2005 ("Primary Extended Term"). Upon written notice given no later than twelve months before expiration of the Primary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement for a term of less than or equal to five years ("Secondary Extended Term") and for any Storage Quantity up to the maximum daily quantity specified in Exhibit A hereto at the time of Shipper's election of the Secondary Extended Term in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Primary Extended Term to terminate this Agreement or to elect to extend the term of this Agreement for a term of less than or equal to five years, then the Secondary Extended Term shall be for five years at the applicable maximum rates shown in the summary of Rates and 2 Piedmont Natural Gas Company, Inc. Service Package No. 2400 August 3, 1998 Page 2 Charges in Transporter's effective FERC Gas Tariff subject to the Rate Cap set forth in Article VIII of the Restructuring Cost Settlement during the period that such Rate Cap is in effect. Upon written notice given no later than twelve months before expiration of the Secondary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement. If Shipper elects to extend this Agreement, the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Secondary Extended Term to either terminate this Agreement or to elect to extend the term of this Agreement, then the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. This Agreement will terminate upon notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accordance with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE VI - NOTICES, notices to Shipper shall be amended as follows: "Director - Federal Regulatory and Supply Planning" shall be substituted for "C. W. Fleenor" "Director - Gas Accounting" shall be substituted for "C. W. Fleenor" Except as specifically amended hereby, all terms and provisions of the Agreement shall remain in full force and effect as written. If the foregoing is in accordance with your understanding of our Agreement, please so indicate by signing and returning both originals of this letter to my attention. Upon Tennessee's execution, an original will be forwarded to PIEDMONT NATURAL GAS COMPANY, INC. for your files. 3 Piedmont Natural Gas Company, Inc. Service Package No. 2400 August 3, 1998 Page 3 Should you have any questions, please do not hesitate to contact me at (713) 757-6774. Best regards, TENNESSEE GAS PIPELINE COMPANY /s/ David L. Bowmaster David L. Bowmaster Account Manager ACCEPTED AND AGREED ACCEPTED AND AGREED BY: /s/ J. P. DICKERSON BY: /s/ C. W. FLEENOR ---------------------------- ------------------------------- NAME: J. P. DICKERSON NAME: C. W. FLEENOR --------------------------- ------------------------------ TITLE: DIRECTOR, MARKETING TITLE: VP GAS SERVICES -------------------------- ----------------------------- 4 GAS STORAGE SERVICE AGREEMENT EXHIBIT "A" AMENDMENT #2A TO GAS STORAGE SERVICE AGREEMENT DATED September 1, 1993 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND PIEDMONT NATURAL GAS COMPANY INC PIEDMONT NATURAL GAS COMPANY INC EFFECTIVE DATE OF AMENDMENT: November 1, 2000 RATE SCHEDULE: FS SERVICE PACKAGE: 2400 SERVICE PACKAGE MSQ: 672,091 INJECTION QUANTITY: 4,480 WITHDRAWAL QUANTITY: 6,190 SERVICE POINT: Compressor Station 087 - PORTLAND Storage
METER METER NAME COUNTY ST ZONE I/W LEG BILLABLE-TQ TOTAL-TQ - ------------------------------------------------------------------------------------------------------------------ 060020 TGP-PORTLAND STORAGE INJECTION SUMNER TN 01 I 100 4,480 4,480 Total Injection TQ: 4,480 4,480 070020 TGP PORTLAND STORAGE WITHDRAWAL SUMNER TN 01 W 100 6,190 6,190 Total Withdrawal TQ: 6,190 6,190
NUMBER OF INJECTION POINTS: 2 NUMBER OF WITHDRAWAL POINTS: 2 NOTE: EXHIBIT "A" IS A REFLECTION OF THE CONTRACT AND ALL AMENDMENTS AS OF THE AMENDMENT EFFECTIVE DATE. EX-10.54 6 g66462ex10-54.txt LETTER OF AGREEMENT OF AMEND. NO. 2A DATED 5/1/94 1 Exhibit 10.54 August 3, 1998 Piedmont Natural Gas Company, Inc. 1915 Rexford Drive Charlotte, NC 28233 ATTN: Ken Valentine RE: AMENDMENT NO. 2A PURSUANT TO GAS STORAGE CONTRACT DATED MAY 1, 1994 SERVICE PACKAGE NO. 6815 Dear Mr. Valentine: Tennessee Gas Pipeline Company ("Tennessee") and PIEDMONT NATURAL GAS COMPANY, INC. ("Shipper") agree to amend the above-referenced Agreement ("Agreement") effective NOVEMBER 1, 2000, as reflected in the attached revised "Exhibit A" and as follows: Article V - Term of Contract, is deleted in its entirety and replaced by the following: Pursuant to the terms of the 1997 Stipulation and Agreement in Docket No. RP93-151, et al. ("Restructuring Cost Settlement") and Shipper's election to extend its firm service Agreement referenced on Appendix F to the Restructuring Cost Settlement, this Agreement shall be extended in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions as OF NOVEMBER 1, 2000, and shall remain in full force and effect until OCTOBER 31, 2005 ("Primary Extended Term"). Upon written notice given no later than twelve months before expiration of the Primary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement for a term of less than or equal to five years ("Secondary Extended Term") and for any Storage Quantity up to the maximum daily quantity specified in Exhibit A hereto at the time of Shipper's election of the Secondary Extended Term in accordance with the provisions of Section 10.5 of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Primary Extended Term to terminate this Agreement or to elect to extend the term of this Agreement for a term of less than or 2 Piedmont Natural Gas Company, Inc. Service Package No. 6815 August 3, 1998 Page 2 equal to five years, then the Secondary Extended Term shall be for five years at the applicable maximum rates shown in the summary of Rates and Charges in Transporter's effective FERC Gas Tariff subject to the Rate Cap set forth in Article VIII of the Restructuring Cost Settlement during the period that such Rate Cap is in effect. Upon written notice given no later than twelve months before expiration of the Secondary Extended Term, Shipper may elect to terminate this Agreement or to extend the term of this Agreement. If Shipper elects to extend this Agreement, the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions. In the event Shipper fails to give written notice no later than twelve months before expiration of the Secondary Extended Term to either terminate this Agreement or to elect to extend the term of this Agreement, then the extension shall be governed by the procedures set forth in Section 10.4 of Article III of Transporter's General Terms and Conditions subject to Section 10.5 (d) and (e) of Article III of Transporter's General Terms and Conditions; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. This Agreement will terminate upon notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accordance with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE VI - NOTICES, notices to Shipper shall be amended as follows: "Director - Federal Regulatory and Supply Planning" shall be substituted for "C.W. Fleenor" "Director - Gas Accounting" shall be substituted for "C. W. Fleenor" Except as specifically amended hereby, all terms and provisions of the Agreement shall remain in full force and effect as written. If the foregoing is in accordance with your understanding of our Agreement, please so indicate by signing and returning both originals of this letter to my attention. 3 Piedmont Natural Gas Company, Inc. Service Package No. 6815 August 3, 1998 Page 2 Upon Tennessee's execution, an original will be forwarded to PIEDMONT NATURAL GAS COMPANY, INC. for your files. Should you have any questions, please do not hesitate to contact me at (713) 757-6774. Best regards, TENNESSEE GAS PIPELINE COMPANY /s/ David L. Bowmaster David L. Bowmaster Account Manager ACCEPTED AND AGREED ACCEPTED AND AGREED BY: /s/ J. P. DICKERSON BY: /s/ C. W. FLEENOR ---------------------------- ----------------------------- NAME: J. P. DICKERSON NAME: C. W. FLEENOR -------------------------- --------------------------- TITLE: DIRECTOR, MARKETING TITLE: VP GAS SERVICES ------------------------- -------------------------- 4 GAS STORAGE SERVICE AGREEMENT EXHIBIT "A" AMENDMENT #2A TO GAS STORAGE SERVICE AGREEMENT DATED May 1, 1994 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND PIEDMONT NATURAL GAS COMPANY INC PIEDMONT NATURAL GAS COMPANY INC EFFECTIVE DATE OF AMENDMENT: November 1, 2000 RATE SCHEDULE: FS SERVICE PACKAGE: 6815 SERVICE PACKAGE MSQ: 2,901,943 INJECTION QUANTITY: 19,347 WITHDRAWAL QUANTITY: 0 SERVICE POINT: Compressor Station 087 - PORTLAND Storage
METER METER NAME COUNTY ST ZONE I/W LEG BILLABLE-TQ TOTAL-TQ - -------------------------------------------------------------------------------------------------------------- 060020 TGP - PORTLAND STORAGE INJECTION SUMNER TN 01 I 100 19,347 19,347 Total Injection TQ: 19,347 19,347 070025 TGP - PORTLAND STORAGE W/DRAWAL - MA SUMNER TN 01 W 100 50,798 50,798 Total Withdrawal TQ: 50,798 50,798
NUMBER OF INJECTION POINTS: 2 NUMBEROF WITHDRAWAL POINTS: 2 NOTE: EXHIBIT "A" IS A REFLECTION OF THE CONTRACT AND ALL AMENDMENTS AS OF THE AMENDMENT EFFECTIVE DATE. EX-10.55 7 g66462ex10-55.txt SERVICE AGREEMENT UNDER FT-A RATE SCHEDULE 1 EXHIBIT 10.55 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) THIS AGREEMENT is made and entered into as of the 1st day of November, 2000, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and PIEDMONT NATURAL GAS COMPANY INC, a NORTH CAROLINA Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties." ARTICLE I DEFINITIONS 1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof, which shall be 55,900 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit "A" attached hereto. 1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff ARTICLE II TRANSPORTATION Transportation Service - Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas. ARTICLE III POINT(S) OF RECEIPT AND DELIVERY The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit "A" attached hereto ARTICLE IV All facilities are in place to render the service provided for in this Agreement. 2 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE V QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT For all gas received, transported and delivered hereunder the Parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. To the extent that no new measurement facilities are installed to provide service hereunder, measurement operations will continue in the manner in which they have previously been handled. In the event that such facilities are not operated by Transporter or a downstream pipeline, then responsibility for operations shall be deemed to be Shipper's. ARTICLE VI RATES AND CHARGES FOR GAS TRANSPORTATION 6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges, and surcharges to be paid by Shipper to Transporter for the transportation service provided herein shall be in accordance with Transporter's Rate Schedule FT-A and the General Terms and conditions of Transporter's FERC Gas Tariff. 6.2 INCIDENTAL CHARGES-Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid for by Shipper, which Transporter incurs in rendering service hereunder. 6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. ARTICLE VII BILLINGS AND PAYMENTS Transporter shall bill and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of the FERC Gas Tariff. 2 3 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE VIII GENERAL TERMS AND CONDITIONS This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-A and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC. ARTICLE IX REGULATION 9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect it any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 9.2 The transportation service described herein shall be provided subject to Subpart G, Part 284, of the FERC Regulations ARTICLE X RESPONSIBILITY DURING TRANSPORTATION Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE XI WARRANTIES 11.1 In addition to the warranties set forth in Article IX of the General Terms and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the following (a) Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each 3 4 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) point as specified on Exhibit "A" attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to receive or deliver gas as contemplated by this Agreement. (b) shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty by Shipper herein 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty by shipper. ARTICLE XII TERM 12.1 This Agreement shall be effective as of the 1st day of November, 2000, and shall remain in force and effect until the 31st day of October, 2005, ("Primary Term") and on a month to month basis thereafter unless terminated by either Party upon at least thirty (30) days prior written notice to the other Party; provided, however, that if the Primary Term is one year or more, then unless Shipper elects upon one year's prior written notice to Transporter to request a lesser extension term, the Agreement shall automatically extend upon the expiration of the Primary Term for a term of five years and shall automatically extend for successive five year terms thereafter unless Shipper provides notice described above in advance of the expiration of a succeeding term; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. 12.2 Any portions of this Agreement necessary to resolve or cash out imbalances under this Agreement as required by the General Terms and conditions of Transporter's Tariff, shall survive the other parts of this Agreement until such time as such balancing has been accomplished; provided, however, that Transporter notifies Shipper of such imbalance not later than twelve months after the termination of this Agreement. 12.3 This Agreement will terminate automatically upon written notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Gas Tariff. 4 5 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XIII NOTICE Except as otherwise provided in the General Terms and Conditions applicable to this Agreement, any notice under this Agreement shall be in writing and mailed to the post office address of the Party intended to receive the same, as follows; TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY P.O. Box 2511 Houston, Texas 77252-2511 Attention: Director - Transportation Control SHIPPER: NOTICES: PIEDMONT NATURAL GAS COMPANY INC 1915 REXFORD ROAD CHARLOTTE, NC 28211 Attention: Director - Federal Regulatory and Supply Planning BILLING: PIEDMONT NATURAL GAS COMPANY INC 1915 REXFORD ROAD CHARLOTTE, NC 28211 Attention: Director - Gas Accounting or to such other address as either Party shall designate by formal written notice to the other. ARTICLE XIV ASSIGNMENTS 14.1 Either Party may assign or pledge this Agreement and all rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligation under this Agreement, assign any of its rights hereunder to a company with which it is affiliated. Otherwise, Shipper shall not assign this Agreement or any of its rights hereunder, except in accord with Article III, Section 11 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 14.2 Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. 5 6 SERVICE PACKAGE NO. 24706 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XV MISCELLANEOUS 15.1 THE INTERPRETATION AND PERFORMANCE OF THIS CONTRACT SHALL BE IN ACCORDANCE WITH AND CONTROLLED BY THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO THE DOCTRINES GOVERNING CHOICE OF LAW. 15.2 If any provision of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at either Party's option; and if the severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. 15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas Tariff, no modification of or supplement to the terms and provisions stated in this agreement shall be or become effective until Shipper has submitted a request for change through the Electronic Bulletin Board and Shipper has been notified through the Electronic Bulletin Board of Transporter's agreement to such change. 15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a part hereof for all purposes. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written. TENNESSEE GAS PIPELINE COMPANY BY: /s/ J. P. Dickerson ----------------------------------- J.P. Dickerson Agent and Attorney-in-Fact DATE: 8/12/98 ----------------------------------- PIEDMONT NATURAL GAS COMPANY INC BY: /s/ C. W. Fleenor ----------------------------------- TITLE: VP ----------------------------------- DATE: 8/13/98 ----------------------------------- 6 7 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) EXHIBIT "A" AMENDMENT #0 TO GAS TRANSPORTATION AGREEMENT DATED November 1, 2000 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND PIEDMONT NATURAL GAS COMPANY INC PIEDMONT NATURAL GAS COMPANY INC EFFECTIVE DATE OF AMENDMENT: November 1, 2000 RATE SCHEDULE: FT-A SERVICE PACKAGE: 24706 SERVICE PACKAGE TQ: 55,900 Dth
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TQ BILLABLE-TQ - -------------------------------------------------------------------------------------------------------------------------------- 070020 TGP - PORTLAND STORAGE WITHDRA TENNESSEE GAS PIPELINE COMPANY SUMNER TN 01 R 100 6,085 6,085 070025 TGP - PORTLAND STORAGE W/DRAWAL SUMNER TN 01 R 100 49,815 49,815 Total Receipt TQ: 55,900 55,900 020312 NASHVILLE-NASHVILLE 2 TENN PIEDMONT NATURAL GAS COMPANY I ROBERTSON TN 01 D 500 55,900 55,900
NUMBER OF RECEIPT POINTS AFFECTED: 2 NUMBER OF DELIVERY POINTS AFFECTED: 1 NOTE: EXHIBIT "A" IS A REFLECTION OF THE CONTRACT AND ALL AMENDMENTS AS OF THE AMENDMENT EFFECTIVE DATE. EX-12 8 g66462ex12.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 1 Exhibit 12 PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Computation of Ratio of Earnings to Fixed Charges For Fiscal Years Ended October 31, 1996 through 2000 (in thousands except ratio amounts)
2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- Earnings: Net income from continuing operations $ 64,031 $ 58,207 $ 60,313 $ 54,074 $ 48,562 Income taxes 41,356 37,645 38,807 34,650 30,928 Fixed charges 44,368 37,978 38,415 39,263 37,009 -------- -------- -------- -------- -------- Total Adjusted Earnings $149,755 $133,830 $137,535 $127,987 $116,499 ======== ======== ======== ======== ======== Fixed Charges: Interest $ 42,010 $ 35,911 $ 36,453 $ 36,949 $ 34,511 Amortization of debt expense 465 323 304 346 345 One-third of rental expense 1,893 1,744 1,658 1,968 2,153 -------- -------- -------- -------- -------- Total Fixed Charges $ 44,368 $ 37,978 $ 38,415 $ 39,263 $ 37,009 ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges 3.38 3.52 3.58 3.26 3.15 ======== ======== ======== ======== ========
EX-23 9 g66462ex23.txt INDEPENDENT AUDITORS' CONSENT 1 Exhibit 23 INDEPENDENT AUDITORS' CONSENT Piedmont Natural Gas Company, Inc.: We consent to the incorporation by reference in Post-Effective Amendment No. 3 to Registration Statement No. 2-67478 on Form S-8, in Post-Effective Amendment No. 2 to Registration Statement No. 33-3815 on Form S-8, 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. 333-35213 on Form S-3, and in Registration Statement No. 333-86263 on Form S-3 of our report dated December 8, 2000, appearing in the Annual Report on Form 10-K of Piedmont Natural Gas Company, Inc. for the year ended October 31, 2000. /s/ DELOITTE & TOUCHE LLP Charlotte, North Carolina January 25, 2001 EX-99 10 g66462ex99.txt ANNUAL REPORT ON FORM 11-K 1 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, 2000 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 2 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 (DRIP). Quarterly statements are furnished to participants showing the number of shares purchased, the purchase price and the balance in the account. At October 31, 2000, 477 employees were participating in the ESPP. 1 3 Piedmont Natural Gas Company Employee Stock Ownership Plan Statements Of Net Assets Available For Benefits October 31, 2000 and 1999 2000 1999 ---- ---- Assets: Investment in Common Stock of Piedmont Natural Gas Company, Inc., at fair value - 200,496 and 210,511 shares (cost $2,821,737 and $2,782,697) at 2000 and 1999, respectively $6,115,128 $6,736,352 Short-term investment fund, at cost which approximates fair value 528 1,516 Receivable on sale of stock - 198 Other 67 57 ---------- ---------- Net Assets Available for Benefits $6,115,723 $6,738,123 ========== ========== See notes to financial statements. 2 4 Piedmont Natural Gas Company Employee Stock Ownership Plan Statements Of Changes In Net Assets Available For Benefits For the Years Ended October 31, 2000, 1999 and 1998 2000 1999 1998 ---- ---- ---- Dividend and interest income $ 297,312 $ 287,859 $ 288,089 Gain (Loss) on sale of assets (Note 3) 44,672 (55,838) 22,398 Net appreciation (depreciation) in fair value of investment in Common Stock (372,607) (528,700) 1,486,211 Withdrawals by participants (591,777) (517,537) (812,499) ---------- ---------- ---------- Net increase (decrease) (622,400) (814,216) 984,199 Net assets available for benefits: Beginning of year 6,738,123 7,552,339 6,568,140 ---------- ---------- ---------- End of Year $6,115,723 $6,738,123 $7,552,339 ========== ========== ========== See notes to financial statements. 3 5 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 (ESOP) was established to enable employees to acquire Piedmont Common Stock. Through 1986, we contributed to the ESOP amounts equal to a tax credit based on aggregate compensation paid or accrued to all employees under the ESOP. The Tax Reform Act of 1986 eliminated the tax credit allowance, and we have not made contributions since 1987. The ESOP is administered by an Administration Committee approved by our Board of Directors. We pay the administrative expenses of the ESOP. The Trust Client Services department of Wachovia Bank, N.A., serves as trustee and custodian. The ESOP is subject to the provisions of the Employee Retirement Income Security Act of 1974. Prior to 1988, a participant in the ESOP was defined as an active eligible employee with a balance in his or her ESOP 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 we stopped making contributions are not considered participants and no previous contributions have been credited to them. Separate accounts are maintained for each participant to reflect the allocation of contributions and subsequent dividend and investment income. Any income credited to participants is reinvested in Common Stock. The ESOP provides for immediate vesting. Distributions are made either at early retirement (age 55 and 10 years of service), at normal retirement (age 65), at actual retirement for a participant who remains employed after attaining normal retirement age, at permanent disability or at death of the participant. The Administration Committee may direct an earlier distribution following a participant's 4 6 termination of employment for any reason, and this has been our practice. A participant who has reached age 55 and completed ten years of participation has the right to diversify a portion of his or her account balance each year during the qualified election period. We may terminate the ESOP at any time and may either continue operations until the trustee has distributed all benefits or cause the assets to be liquidated and distributed. 2. Basis of Accounting The financial statements are presented on the accrual basis of accounting. We make estimates and assumptions when preparing financial statements. Those estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. The investment in Common Stock is valued at fair value as determined by quoted market prices on the New York Stock Exchange on October 31, 2000 and 1999. Dividend income is accrued on the ex-dividend date. Purchases and sales of securities are recorded on a trade-date basis. Realized gains and losses from security transactions are reported on the average cost method. 3. Gain (Loss) on Sale of Assets The gain (loss) on sale of assets for the years ended October 31, 2000, 1999 and 1998, was computed as follows: 2000 1999 1998 ---- ---- ---- Gross proceeds $452,554 $386,600 $184,200 Historical cost 407,882 442,438 161,802 -------- -------- -------- Gain (Loss) $ 44,672 $(55,838) $ 22,398 ======== ======== ======== 5 7 4. Net Assets Available for Benefits Net assets available for benefits at October 31, 2000 and 1999 were $6,115,723 and $6,738,123, respectively. 5. Tax Status The ESOP is qualified under Sections 401 and 409 of the Internal Revenue Code of 1986, as amended (the Tax Code). The Internal Revenue Service has informed us by letter that the ESOP, as designed, is qualified and the trust established under the ESOP is exempt from income taxes under Section 501(a) of the Tax Code. The ESOP has been amended since receiving the determination letter; however, we believe the ESOP is currently designed and being operated in compliance with applicable requirements of the Tax Code. Distributions are taxed to recipients as ordinary income, with the taxable amount that applies to Common Stock being the lesser of cost or fair market value on the date of distribution. Any increase in the value of Common Stock is not taxed during the period that the stock is held by the trust nor upon its distribution to the participant. If stock is sold after distribution, the sale is subject to capital gain or loss treatment, depending on the sales price of the stock. 6 8 Independent Auditors' Report Piedmont Natural Gas Company Employee Stock Ownership Plan: We have audited the accompanying statements of net assets available for benefits of the Piedmont Natural Gas Company Employee Stock Ownership Plan (the Plan) as of October 31, 2000 and 1999, and the related statements of changes in net assets available for benefits for each of the three years in the period ended October 31, 2000. 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. In our opinion, the financial statements referred to above present fairly, in all material respects, the net assets available for benefits of the Plan as of October 31, 2000 and 1999, and the changes in net assets available for benefits for each of the three years in the period ended October 31, 2000 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, 2001 7 -----END PRIVACY-ENHANCED MESSAGE-----