-----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, RbF/eNClv4MtMHf1YyDoLjypu0AJGlzwNl0oMIi1ASgtO6tKhC0XWnJDSzuXiorS 1Y+rFgmLR1Mwx8SpfBcjKA== 0000950144-02-006459.txt : 20020612 0000950144-02-006459.hdr.sgml : 20020612 20020612112431 ACCESSION NUMBER: 0000950144-02-006459 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20020430 FILED AS OF DATE: 20020612 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-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-06196 FILM NUMBER: 02677012 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-Q 1 g76784e10vq.txt PIEDMONT NATURAL GAS COMPANY, INC. ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended April 30, 2002 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 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 incorporation or organization) Identification No.) 1915 Rexford Road, Charlotte, North Carolina 28211 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (704) 364-3120 ------------------ 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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at June 3, 2002 - --------------------------- --------------------------- Common Stock, no par value 32,792,921 =============================================================================== Page 1 of 25 pages PART 1. FINANCIAL INFORMATION Item 1. Financial Statements - ----------------------------- PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Consolidated Balance Sheets (In thousands)
April 30, October 31, 2002 2001 Unaudited Audited ----------- ----------- ASSETS ------ Utility Plant, at original cost $ 1,662,917 $ 1,626,176 Less accumulated depreciation 536,890 511,477 ----------- ----------- Utility plant, net 1,126,027 1,114,699 ----------- ----------- Other Physical Property (net of accumulated depreciation of $1,433 in 2002 and $1,341 in 2001) 1,139 1,163 ----------- ----------- Current Assets: Cash and cash equivalents 73,477 5,610 Restricted cash 4,130 7,064 Receivables (less allowance for doubtful accounts of $2,634 in 2002 and $592 in 2001) 58,617 25,898 Gas in storage 19,091 70,220 Deferred cost of gas 8,201 16,310 Refundable income taxes 1,212 22,271 Prepayments and other 20,586 27,928 ----------- ----------- Total current assets 185,314 175,301 ----------- ----------- Investments, Deferred Charges and Other Assets: Investments in non-utility activities, at equity 101,023 82,287 Unamortized debt expense 4,026 4,130 Other 15,012 16,078 ----------- ----------- Total investments, deferred charges and other assets 120,061 102,495 ----------- ----------- Total $ 1,432,541 $ 1,393,658 =========== =========== CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock equity: Common stock $ 342,544 $ 332,038 Retained earnings 287,131 229,718 Accumulated other comprehensive income (554) (1,377) ----------- ----------- Total common stock equity 629,121 560,379 Long-term debt 509,000 509,000 ----------- ----------- Total capitalization 1,138,121 1,069,379 ----------- ----------- Current Liabilities: Current maturities of long-term debt and sinking fund requirements 2,000 2,000 Notes payable -- 32,000 Accounts payable 51,739 41,144 Deferred income taxes 3,152 2,344 Income taxes accrued 2,044 -- General taxes accrued 7,627 14,544 Refunds due customers 28,135 31,685 Other 23,554 25,510 ----------- ----------- Total current liabilities 118,251 149,227 ----------- ----------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 143,679 143,211 Unamortized federal investment tax credits 5,869 6,149 Other 26,621 25,692 ----------- ----------- Total deferred credits and other liabilities 176,169 175,052 ----------- ----------- Total $ 1,432,541 $ 1,393,658 =========== ===========
See notes to condensed consolidated financial statements. -2- PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Condensed Statements of Consolidated Income (Unaudited) (In thousands)
Three Months Six Months Twelve Months Ended Ended Ended April 30 April 30 April 30 --------------------- --------------------- --------------------- 2002 2001 2002 2001 2002 2001 ---- ---- ---- ---- ---- ---- Operating Revenues $293,865 $ 408,012 $582,622 $ 875,585 $814,893 $1,154,360 Cost of Gas 175,297 288,382 340,852 627,353 483,376 820,032 -------- --------- -------- --------- -------- ---------- Margin 118,568 119,630 241,770 248,232 331,517 334,328 -------- --------- -------- --------- -------- ---------- Other Operating Expenses: Operations 27,681 27,915 56,631 58,158 112,831 113,340 Maintenance 4,898 4,975 9,657 9,295 19,426 18,298 Depreciation 14,253 12,803 28,349 25,552 54,857 50,463 General Taxes 7,127 5,546 12,382 11,152 25,183 20,013 Income Taxes 21,497 23,210 45,034 49,249 30,727 36,742 -------- --------- -------- --------- -------- ---------- Total other operating expenses 75,456 74,449 152,053 153,406 243,024 238,856 -------- --------- -------- --------- -------- ---------- Operating Income 43,112 45,181 89,717 94,826 88,493 95,472 -------- --------- -------- --------- -------- ---------- Other Income (Expense), Net of Taxes: Non-utility activities, at equity 8,371 4,695 12,799 14,944 7,606 12,637 Allowance for equity funds used during construction 164 -- 311 -- 817 -- Other, net 43 (424) 237 (290) 638 3,203 -------- --------- -------- --------- -------- ---------- Total other income, net of taxes 8,578 4,271 13,347 14,654 9,061 15,840 -------- --------- -------- --------- -------- ---------- Income Before Utility Interest Charges 51,690 49,452 103,064 109,480 97,554 111,312 Utility Interest Charges 9,845 9,583 20,049 19,309 39,225 38,640 -------- --------- -------- --------- -------- ---------- Net Income $ 41,845 $ 39,869 $ 83,015 $ 90,171 $ 58,329 $ 72,672 ======== ========= ======== ========= ======== ========== Average Shares of Common Stock: Basic 32,689 32,126 32,624 32,056 32,464 31,900 Diluted 32,861 32,357 32,796 32,302 32,668 32,174 Earnings Per Share of Common Stock: Basic $ 1.28 $ 1.24 $ 2.54 $ 2.81 $ 1.80 $ 2.28 Diluted $ 1.27 $ 1.23 $ 2.53 $ 2.79 $ 1.79 $ 2.26 Cash Dividends Per Share of Common Stock $ 0.40 $ 0.385 $ 0.785 $ 0.75 $ 1.555 $ 1.48
See notes to condensed consolidated financial statements. -3- PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Condensed Statements of Consolidated Cash Flows (Unaudited) (in thousands) -----------------------------------------------------------
Three Months Six Months Twelve Months Ended Ended Ended April 30 April 30 April 30 -------------------- ----------- -------- --------------------- 2002 2001 2002 2001 2002 2001 ---- ---- ---- ---- ---- ---- Cash Flows from Operating Activities: Net income $ 41,845 $ 39,869 $ 83,015 $ 90,171 $ 58,329 $ 72,672 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 14,443 13,079 28,733 26,161 55,748 52,346 Other, net (3,018) 20,719 (1,758) (9,238) (1,615) 16,172 Net gain on propane business combination, net of tax -- -- -- -- -- (5,063) Change in operating assets and liabilities 73,436 (19,761) 44,749 28,118 67,470 (58,675) -------- -------- -------- -------- -------- --------- Net cash provided by operating activities 126,706 53,906 154,739 135,212 179,932 77,452 -------- -------- -------- -------- -------- --------- Cash Flows from Investing Activities: Utility construction expenditures (20,423) (14,035) (37,736) (40,522) (80,750) (104,920) Investment in propane partnership -- -- -- -- -- (30,552) Proceeds from propane business combination -- -- -- -- -- 36,748 Other (34) (59) (71) (6,691) (367) (7,005) -------- -------- -------- -------- -------- --------- Net cash used in investing activities (20,457) (14,094) (37,807) (47,213) (81,117) (105,729) -------- -------- -------- -------- -------- --------- Cash Flows from Financing Activities: Increase (Decrease) in bank loans, net (33,000) (31,015) (32,000) (65,515) (33,985) 3,985 Issuance of long-term debt -- -- -- -- 60,000 60,000 Retirement of long-term debt -- -- -- -- (32,000) (2,000) Issuance of common stock through dividend reinvestment and employee stock plans 4,407 3,871 8,537 7,418 16,508 14,941 Dividends paid (13,071) (12,363) (25,602) (24,044) (50,466) (47,206) -------- -------- -------- -------- -------- --------- Net cash provided by (used in) financing activities (41,664) (39,507) (49,065) (82,141) (39,943) 29,720 -------- -------- -------- -------- -------- --------- Net Increase in Cash and Cash Equivalents 64,585 305 67,867 5,858 58,872 1,443 Cash and Cash Equivalents at Beginning of Period 8,892 14,300 5,610 8,747 14,605 13,162 -------- -------- ------ -------- -------- --------- Cash and Cash Equivalents at End of Period $ 73,477 $ 14,605 $ 73,477 $ 14,605 $ 73,477 $ 14,605 ======== ======== ======== ======== ======== ========= Cash Paid During the Period for: Interest $ 3,765 $ 2,720 $ 19,932 $ 19,628 $ 40,281 $ 38,103 Income taxes $ 29,290 $ 48,685 $ 29,957 $ 48,745 $ 32,642 $ 81,570
See notes to condensed consolidated financial statements. -4- PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Statements of Consolidated Comprehensive Income (Unaudited) (In thousands)
Three Months Six Months Ended April 30 Ended April 30 ------------------ ------------------ 2002 2001 2002 2001 ---- ---- ---- ---- Net Income $41,845 $39,869 $83,015 $90,171 Other Comprehensive Income: Equity investments hedging activities, net of tax of ($272) for the three months and ($498) for the six months in 2002 and ($204) in 2001 431 (311) 823 (311) ------- ------- ------- ------- Total Comprehensive Income $42,276 $39,558 $83,838 $89,860 ======= ======= ======= ======= Reconciliation of Accumulated Other Comprehensive Income: Balance, beginning of period ($985) $ -- ($1,377) $ -- Current period reclassification to earnings 371 -- 557 -- Current period change 60 (311) 266 (311) ------- ------- ------- ------- Balance, end of period ($554) ($311) ($554) ($311) ======= ======= ======= =======
See notes to condensed consolidated financial statements. -5- PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Notes to Condensed Consolidated Financial Statements (Unaudited) 1. Independent auditors have not audited the condensed consolidated financial statements. These financial statements should be read in conjunction with the Notes to Consolidated Financial Statements included in our 2001 Form 10-K Annual Report. 2. In our opinion, the unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at April 30, 2002, and October 31, 2001, and the results of operations and cash flows for the three months, six months and twelve months ended April 30, 2002 and 2001. 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 our estimates. 3. Our business is seasonal in nature. The results of operations for the three-month and six-month periods ended April 30, 2002, do not necessarily reflect the results to be expected for the full year. 4. Basic earnings per share are computed by dividing net income by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur when common stock equivalents are added to common shares outstanding. Shares that may be issued under the long-term incentive plan are our only common stock equivalents. A reconciliation of basic and diluted earnings per share is shown below:
Three Months Six Months Twelve Months Ended Ended Ended April 30 April 30 April 30 In thousands except per share amounts ------------------- ------------------- ------------------- 2002 2001 2002 2001 2002 2001 ---- ---- ---- ---- ---- ---- Net Income $41,845 $39,869 $83,015 $90,171 $58,329 $72,672 ======= ======= ======= ======= ======= ======= Average shares of common stock outstanding for basic earnings per share 32,689 32,126 32,624 32,056 32,464 31,900 Contingently issuable shares under the long-term incentive plan 172 231 172 246 204 274 ------- ------- ------- ------- ------- ------- Average shares of dilutive stock 32,861 32,357 32,796 32,302 32,668 32,174 ======= ======= ======= ======= ======= ======= Earnings Per Share: Basic $1.28 $1.24 $2.54 $2.81 $1.80 $2.28 Diluted $1.27 $1.23 $2.53 $2.79 $1.79 $2.26
-6- 5. Business Segments We have two reportable business segments, domestic natural gas distribution and retail energy marketing services. Operations of our domestic natural gas distribution segment are conducted by the parent company and by Piedmont Intrastate Pipeline Company and Piedmont Interstate Pipeline Company, two wholly owned subsidiaries of our wholly owned subsidiary, Piedmont Energy Partners. Operations of our retail energy marketing services segment are conducted by Piedmont Energy Company, a wholly owned subsidiary of Piedmont Energy Partners, through its ownership of an equity method investment. Our activities included in Other in the segment tables consist primarily of propane operations conducted by Heritage Propane Partners, L.P., a master limited partnership. Piedmont Propane Company, a wholly owned subsidiary of Piedmont Energy Partners, has an equity interest in US Propane, L.P., the general partner and the owner of approximately 31% of the limited partnership interest of Heritage Propane Partners. All of our activities other than the utility operations of the parent are included in other income in the statements of consolidated income. We evaluate performance based on margin, operations and maintenance expenses, operating income and income before taxes. The basis of segmentation and the basis of the measurement of segment profit or loss have not changed from that reported in our audited financial statements for the year ended October 31, 2001. Continuing operations by segment for the three months and six months ended April 30, 2002 and 2001, are presented below:
Domestic Retail Natural Gas Energy In thousands Distribution Marketing Other Total ------------------ ----------------- ----------------- ------------------- Three Months Ended April 30 2002 2001 2002 2001 2002 2001 2002 2001 - --------------------------- ---- ---- ---- ---- ---- ---- ---- ---- Revenues from external customers $293,865 $408,012 $ -- $ -- $ -- $ -- $293,865 $408,012 Margin 118,568 119,630 -- -- -- (264) 118,568 119,366 Operations and maintenance expenses 32,580 32,890 53 -- 140 589 32,773 33,479 Operating income 43,112 45,181 (54) (1) (156) (857) 42,902 44,323 Other income 1,674 1,956 11,143 4,883 1,651 1,221 14,468 8,060 Income before income taxes 56,439 60,773 11,148 4,732 1,494 368 69,081 65,873 Capital expenditures 21,492 15,323 -- -- -- -- 21,492 15,323 Six Months Ended April 30 - ------------------------- Revenues from external customers $582,622 $875,585 $ -- $ -- $ -- $ -- $582,622 $875,585 Margin 241,770 248,232 -- -- -- (264) 241,770 247,968 Operations and maintenance expenses 66,288 67,453 99 1 156 564 66,543 68,018 Operating income 89,668 94,816 (107) 1 (189) (833) 89,372 93,984 Other income 3,527 3,711 17,360 18,439 2,140 3,316 23,027 25,466 Income before income taxes 118,185 128,486 17,221 18,032 1,952 2,490 137,358 149,008 Capital expenditures 39,776 44,109 -- -- -- -- 39,776 44,109
-7- A reconciliation of net income in the condensed consolidated financial statements for the three months and six months ended April 30, 2002 and 2001, is presented below:
Three Months Six Months Ended April 30 Ended April 30 ------------------- --------------------- In thousands 2002 2001 2002 2001 ---- ---- ---- ---- Income before income taxes for reportable segments $67,587 $65,505 $135,406 $146,518 Income before income taxes for other non-utility activities 1,494 368 1,952 2,490 Income taxes 27,236 26,004 54,343 58,837 ------- ------- -------- -------- Net income $41,845 $39,869 $ 83,015 $ 90,171 ======= ======= ======== ========
A reconciliation of consolidated assets in the condensed consolidated financial statements as of April 30, 2002 and October 31, 2001, is presented below: In thousands 2002 2001 ---- ---- Total assets for reportable segments $1,432,367 $1,409,669 Other assets 68,334 27,050 Eliminations/Adjustments (44,146) (43,061) ---------- ---------- Consolidated assets $1,456,555 $1,393,658 ========== ========== Risks of Equity Investments Piedmont Intrastate Pipeline Company is a 16.45% member of Cardinal Pipeline Company, L.L.C. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a 104-mile intrastate natural gas pipeline in North Carolina and is regulated by the North Carolina Utilities Commission (NCUC). Cardinal has long-term service agreements with local distribution companies for 100% of the 270 million cubic feet per day of firm transportation capacity on the pipeline. Cardinal is dependent on the interstate pipeline company serving North Carolina to deliver gas into its system for service to these companies. Cardinal's long-term debt is secured by Cardinal's assets and by the equity membership interests of Cardinal's members. Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company, L.L.C. The other members are subsidiaries of The Williams Companies, Inc., SCANA Corporation, Progress Energy, Inc., and Amerada Hess Corporation and the Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas peaking demand facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). Storage capacity of the facility is four billion cubic feet with vaporization capability of 400 million cubic feet per day and is fully subscribed under long-term service agreements with customers. We subscribe to slightly more than one-half of this capacity to provide gas for peak-use periods when demand is the highest. Pine Needle enters into interest-rate swap agreements to modify the interest characteristics of its long-term debt. Pine Needle's long-term debt is secured by Pine Needle's assets and by the equity membership interests of Pine Needle's members. Piedmont Propane Company owns 20.69% of the membership interest in US Propane, L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources, Inc., and Atmos Energy Corporation. US Propane owns all of the general partnership interest and approximately 31% of the limited partnership interest in Heritage Propane Partners, L.P., a marketer of propane through a nationwide retail distribution -8- network. Heritage competes with electricity, natural gas and fuel oil, as well as with other companies in the retail propane distribution business. The propane business, like natural gas, is seasonal, with weather conditions significantly affecting the demand for propane. Heritage purchases propane at numerous supply points for delivery to Heritage primarily via railroad tank cars and common carrier transport. Heritage's profitability is sensitive to changes in the wholesale prices of propane. Heritage utilizes hedging transactions to provide price protection against significant fluctuations in prices. Heritage also buys and sells financial instruments for trading purposes through a wholly owned subsidiary. Financial instruments used in connection with this liquids trading activity are marked to market. The limited partnership agreement of US Propane requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Our maximum capital account restoration would be $9,980,000. Currently, our capital account is positive. We believe that liquidation is not probable or likely to occur and have not recorded this liability. Piedmont Energy Company has a 30% interest in SouthStar Energy Services LLC. The other members are subsidiaries of AGL Resources, Inc., and Dynegy Holdings, Inc. SouthStar offers a combination of unregulated energy products and services to industrial, commercial and residential customers in the southeastern United States. SouthStar was formed and began marketing energy services in Georgia in 1998 when that state became the first in the Southeast to fully open to natural gas retail competition. After three years of deregulation, the Governor of Georgia appointed a task force to reevaluate the deregulation of the Georgia natural gas market. As a result of the task force report, additional natural gas deregulation legislation was passed by the Georgia House and Senate on March 19, 2002. Among other things, the legislation establishes a consumer bill of rights and a "last resort" gas supplier for the poor and those unable to purchase gas from marketers due to poor credit histories. Non-profit electric membership corporations are also allowed to set up gas marketing affiliates. In May 2002, three companies, including SouthStar, submitted proposals with the Georgia Public Service Commission (GPSC) to be chosen as the "last resort" gas supplier. Only one company will be designated as the "last resort" service provider by the GPSC. A decision by the GPSC is required by July 1, 2002, although an earlier decision is expected. SouthStar manages commodity price and weather risks through hedging activities using derivative financial instruments, physical commodity contracts and option-based weather derivative contracts. Financial contracts in the form of futures, options and swaps are used to hedge the price volatility of natural gas. These derivative transactions qualify as cash flow hedges. Weather derivative contracts are used to preserve margins in the event of warmer-than-normal weather during the winter period. Such contracts are accounted for using the intrinsic value method under the guidelines of EITF 99-2 "Accounting for Weather Derivatives." Based upon the cumulative heating degree days in November 2001 through March 2002, SouthStar received $3,767,000 under the contracts in April. Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary with a 33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier). The other member is a subsidiary of Dominion Resources, Inc. Greenbrier is proposing to build a 263-mile interstate pipeline linking multiple gas supply basins and storage to the growing demand of markets in the Southeast, with initial capacity of 600,000 dekatherms of natural gas per day. The pipeline will originate in Kanawha County, West Virginia, and extend through southwest Virginia to Granville County, North Carolina. The pipeline is expected to cost $497 million, with approximately $150 million of the cost expected to be contributed as equity by the -9- owners and the remainder expected to be provided by project financed debt. As of April 30, 2002, we have made capital contributions to Greenbrier totaling $4,599,000. Related Party Transactions We have related party transactions with three of the entities in which we have minority equity investments. These transactions are recorded on the utility's books either as gas costs, which are subject to gas cost recovery procedures, or as gas sales. The utility records as gas costs the fixed storage costs charged by Pine Needle as determined by the FERC. These gas costs were $2,761,000 and $2,872,000 for the three months ended April 30, 2002 and 2001, respectively, $5,521,000 and $5,745,000 for the six months ended April 30, 2002 and 2001, respectively, and $11,043,000 and $11,246,000 for the twelve months ended April 30, 2002 and 2001, respectively. We owed Pine Needle $920,000 and $957,000 at April 30, 2002 and 2001, respectively. The utility records as gas costs the fixed transportation costs charged by Cardinal as determined by the NCUC. These gas costs were $369,000 for the three months ended April 30, 2002 and 2001, $737,000 for the six months ended April 30, 2002 and 2001, and $1,475,000 for the twelve months ended April 30, 2002 and 2001. We owed Cardinal $123,000 at April 30, 2002 and 2001. The utility sells gas to SouthStar at prevailing market rates. Operating revenues from these sales totaled $2,779,000 and $3,043,000 for the three months ended April 30, 2002 and 2001, respectively, $4,491,000 and $4,685,000 for the six months ended April 30, 2002 and 2001, respectively, and $11,998,000 and $7,721,000 for the twelve months ended April 30, 2002 and 2001, respectively. SouthStar owed us $1,314,000 and $2,541,000 at April 30, 2002 and 2001, respectively. The members of SouthStar have entered into a capital contributions agreement that requires each member to contribute additional capital for SouthStar to pay invoices for goods or services provided from any member or its affiliates whenever funds are not available to pay these invoices. The capital contributions to pay affiliated invoices are repaid as funds become available, but are subordinate to SouthStar's revolving line of credit with a bank. There was no activity related to this agreement during the three months and six months ended April 30, 2002. Summarized unaudited financial information provided to us by Cardinal for their fiscal quarters ended March 31, 2002 and 2001, is presented below. Three Months Six Months Ended March 31 Ended March 31 -------------------- -------------------- In thousands 2002 2001 2002 2001 ---- ---- ---- ---- Revenues $ 4,281 $ 4,281 $ 8,562 $ 8,562 Gross profit -- -- -- -- Income before income taxes 2,349 2,491 4,727 5,137 Total assets 104,967 106,952 104,967 106,952 Summarized unaudited financial information provided to us by Pine Needle for their fiscal quarters ended March 31, 2002 and 2001, is presented below. -10- Three Months Six Months Ended March 31 Ended March 31 -------------------- -------------------- In thousands 2002 2001 2002 2001 ---- ---- ---- ---- Revenues $ 4,949 $ 4,958 $ 10,021 $ 10,008 Gross profit -- -- -- -- Income before income taxes 2,664 2,724 5,390 5,474 Total assets 112,104 116,738 112,104 116,738 Summarized unaudited financial information for Heritage Propane Partners, L.P., for their fiscal quarters ended February 28, 2002 and 2001, as presented in their Form 10-Q quarterly report, is presented below. Three Months Six Months Ended February 28 Ended February 28 -------------------- -------------------- In thousands 2002 2001 2002 2001 ---- ---- ---- ---- Revenues $229,635 $326,760 $391,738 $492,605 Gross profit 132,492 188,054 254,360 283,960 Income before income taxes 30,130 43,330 25,351 45,293 Total assets 779,640 718,575 779,640 718,575 Summarized unaudited financial information provided to us by SouthStar for their fiscal quarters ended March 31, 2002 and 2001, is presented below. Three Months Six Months Ended March 31 Ended March 31 -------------------- -------------------- In thousands 2002 2001 2002 2001 ---- ---- ---- ---- Revenues $230,288 $336,731 $402,359 $605,881 Gross profit 59,828 52,505 95,057 110,908 Income before income taxes 37,438 32,365 58,160 59,991 Total assets 167,811 264,843 167,811 264,843 6. Derivatives and Hedging Activities We purchase natural gas for our regulated operations for resale under tariffs approved by the state commissions having jurisdiction over the service territory where the customer is located. We recover the cost of gas purchased for regulated operations through purchased gas adjustment mechanisms. We structure the pricing and performance of gas supply contracts to maximize flexibility and minimize cost and risk for the customer. Our risk management policies allow us to use financial instruments for trading purposes and to hedge risks, but not for speculative trading. These policies were developed by management. An energy risk management committee of multi-department representation monitors risks in accordance with these policies. We have purchased financial call options for natural gas for our Tennessee gas purchase portfolio for delivery in December 2002, January 2003 and February 2003. Previously purchased options were sold April 1, 2002, and proceeds were used to purchase options that are currently held. The cost of these options and all gas costs incurred are components of and are recovered under the guidelines of the Tennessee Incentive Plan. This plan establishes an incentive-sharing mechanism based on differences in the actual cost of gas purchased and benchmark rates. These differences, after applying a monthly 1% positive or negative deadband, together with income from marketing transportation and capacity in the secondary market and income (margin) from secondary market -11- sales of gas, are subject to an overall annual cap of $1,600,000 for shareholder gains or losses. The net gains or losses on gas procurement costs within the deadband (99%-101% of the benchmark) are not subject to sharing under the Incentive Plan. Any net gains or losses on gas procurement costs outside the deadband are combined with capacity management benefits and shared between customers and shareholders. This amount is subject to the overall annual cap and is placed in a regulatory asset to be surcharged or refunded to customers. During April 2002, we purchased financial call options for natural gas for our South Carolina gas purchase portfolio for delivery in June 2002 through October 2002. The costs of these options are a component of and are recovered under the guidelines of the South Carolina experimental hedging program approved by the Public Service Commission of South Carolina (PSCSC) on March 26, 2002. The primary benefit of this plan is to stabilize gas costs for South Carolina ratepayers. This plan operates off of pricing indices that are tied to future projected gas prices as traded on a national exchange and is limited to 60% of the annual normalized sales volumes. The hedging program uses a matrix of historic, inflation-adjusted gas prices over the past four years plus the current season with a heavier weighting on current data as the basis for determining the purchase of financial instruments. The supply cost portfolio will be diversified over a rolling 24 months with a short-term focus (1 to 12 months) and a long-term focus (13 to 24 months). Purchases will be executed within the parameters of the matrix as compared to daily NYMEX monthly prices. There is limited subjective discretion in making purchases with little or no risk of speculation in the market. The PSCSC, in its order approving the plan, stated that the actions we take in accordance with the plan will be deemed to be prudent. -12- Item 2. Management's Discussion and Analysis of Financial Condition and Results - -------------------------------------------------------------------------------- of Operations - ------------- Forward-Looking Statements - -------------------------- This document and other documents we file with the Securities and Exchange Commission (SEC) contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements orally to analysts, investors, the media and others. Our discussion contains forward-looking statements concerning, among others, plans, objectives, proposed capital expenditures and future events or performance. Our statements reflect our current expectations and involve a number of risks and uncertainties. Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements. Important factors that could cause actual results to differ include: o Regulatory issues, including those that affect allowed rates of return, rate structures and financings. In addition to the impact of our three state regulatory commissions, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated by the FERC and the NCUC, respectively. o Residential, commercial and industrial growth in our service territories. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our local markets and the United States. o Deregulation, unanticipated impacts of restructuring and increased competition in the energy industry. We face competition from electric companies and energy marketing and trading companies. As a result of continued deregulation, we expect this highly competitive environment to continue. o The potential loss of large-volume industrial customers to alternate fuels or to bypass or the shift by such customers to special competitive contracts at lower per-unit margins. o The ability to meet internal performance goals. Regulatory issues, customer growth, deregulation, economic and capital market conditions, the price and availability of natural gas and weather conditions can impact our performance goals. o The capital-intensive nature of our business, including development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. o Changes in the availability and price of natural gas. To meet customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system while also ensuring that our supply and capacity contracts will allow us to remain competitive. We have a diversified portfolio of local peaking facilities, transportation and storage contracts with interstate pipelines and supply contracts with major producers and marketers to satisfy the supply and delivery requirements of our customers. Because these producers and pipelines are subject to -13- risks associated with exploring, drilling, producing, gathering and transporting natural gas, their risks also increase our exposure to supply and price fluctuations. We engage in hedging activity in order to minimize price volatility for our customers. o Changes in weather conditions. Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild or severe weather, either during the winter period or the summer period, can have a significant impact on the demand for and the price of natural gas. o Changes in environmental requirements and cost of compliance. o Earnings of our equity investments. We have investments in unregulated retail energy marketing services, interstate liquefied natural gas (LNG) operations, intrastate pipeline operations and propane. These companies have risks that are inherent to their industries and, as an equity investor, we assume such risks. All of these factors are difficult to predict and many are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. When used in our documents or oral presentations, the words "anticipate," "believe," "intend," "plan," "estimate," "expect," "objective," "projection," "budget," "forecast," "goal" or similar words or future or conditional verbs such as "will," "would," "should," "could" or "may" are intended to identify forward-looking statements. Factors relating to regulation and management are also described or incorporated in our Annual Report on Form 10-K, as well as information included in, or incorporated by reference from, future filings with the SEC. Some of the factors that may cause actual results to differ have been described above. Others may be described elsewhere in this report. There also may be other factors besides those described or incorporated in this report or in the Form 10-K that could cause actual conditions, events or results to differ from those in the forward-looking statements. Forward-looking statements reflect our current expectations only as of the date they are made. We assume no duty to update these statements should expectations change or actual results differ from current expectations. Financial Condition and Liquidity - --------------------------------- We finance current cash requirements primarily from operating cash flows and short-term borrowings. Outstanding short-term borrowings under our bank lines of credit totaling $150 million ranged from zero to $30 million during the three months ended April 30, 2002, with an average interest rate of 2.22%, and from zero to $57 million during the six months ended April 30, 2002, with an average interest rate of 3.47%. Our operations are weather sensitive. Warmer weather can lead to lower margins from fewer volumes of natural gas being sold or transported. Colder weather that increases the volumes of natural gas sold to weather-sensitive customers can result in the inability of some of our customers to pay their bills. Either warm or cold weather that is outside the normal range of temperatures can lead to less operating cash flow, thereby -14- increasing short-term borrowings to meet current cash requirements. The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas that are charged by suppliers and to increased gas supplies required to meet our customers' needs during cold weather. Short-term debt increases when wholesale prices for natural gas increase because we must pay suppliers for the gas before we can recover our costs from customers through their monthly bills. In addition to short-term borrowings, we sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing. Our dividend reinvestment and stock purchase plan is also a source of capital. The natural gas business is seasonal in nature resulting primarily in fluctuations in balances in accounts receivable from customers, inventories of stored natural gas and accounts payable to suppliers in addition to short-term borrowings discussed above. From April 1 to October 31, we build up natural gas inventories by injecting gas into storage for sale in the colder months. Inventory of stored gas decreased and accounts payable and accounts receivable increased from October 31, 2001, to April 30, 2002, due to this seasonality and the demand for gas during the winter season. Most of our annual earnings are realized in the winter period, which is the first five months of our fiscal year. We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements funded through sources noted above. The capital expansion program supports our approximately 4% current annual growth in customer base. Utility construction expenditures for the three months ended April 30, 2002, were $21.5 million, compared with $15.3 million for the same period in 2001. Utility construction expenditures for the six months ended April 30, 2002, were $39.7 million, compared with $44 million for the same period in 2001. Utility construction expenditures for the twelve months ended April 30, 2002, were $85.9 million, compared with $109.8 million for the same period in 2001. Our expected future contractual obligations at April 30, 2002, are as follows: In millions Payments Due by Period ---------------------------------------------------- Less than 1-3 4-5 After Contractual Obligations Total 1 Year Years Years 5 Years - ----------------------- ----- ------ ----- ----- ------- Long-term debt $511 $ 2 $ 49 $ 35 $425 Pipeline and storage 938 95 256 141 446 capacity and gas supply* *100% recoverable due to rate mechanism. At April 30, 2002, our capitalization consisted of 45% in long-term debt and 55% in common equity. Critical Accounting Policies and Estimates - ------------------------------------------ We have prepared our consolidated financial statements in conformity with accounting principles -15- generally accepted in the United States of America. The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods reported. Actual results may change significantly from the use of our current estimates. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, management evaluates estimates and assumptions. As a result of this evaluation and any new circumstances, adjustments are made in subsequent periods to reflect more current information if management determines that modifications in assumptions and estimates are required. We believe the following critical accounting policies affect the more significant judgments and estimates used in the preparation of our consolidated financial statements. For a complete discussion of significant accounting policies, refer to Note 1 in Item 8 of our 2001 Form 10-K. Regulation. We are subject to regulation by certain state and federal authorities. We have accounting policies that conform to Statement of Financial Accounting Standards No. 71, "Accounting for the Effect of Certain Types of Regulation" and are in accordance with accounting requirements and ratemaking practices prescribed by the regulatory authorities. The application of these accounting policies allows us to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the income statement by an unregulated company. These deferred regulatory assets and liabilities are then flowed through the income statement in the period in which the same amounts are reflected in rates. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to these portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Allowance for Uncollectible Accounts. We evaluate the collectibility of our trade accounts receivable based on our recent past loss history and an overall assessment of past due trade accounts receivable amounts outstanding. Employee Benefits. We have a defined-benefit pension plan for the benefit of substantially all full-time regular employees. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to the plan. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by us, within certain guidelines. In addition, our actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense recorded in future periods. -16- Self Insurance. We are self-insured for certain losses related to general liability, group medical benefits and workers' compensation. We maintain stop loss coverage with third party insurers to limit our total exposure. Our liabilities represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are not discounted and are established based upon analysis of historical data and actuarial estimates. The liabilities are reviewed by management and third party actuaries at least annually to ensure that they are appropriate. While we believe these estimates are reasonable based on the information currently available, if actual trends, including the severity or frequency of claims or fluctuations in premiums, differ from our estimates, our financial results could be impacted. Results of Operations - --------------------- We will discuss the results of operations for the three months, six months and twelve months ended April 30, 2002, compared with similar periods in 2001. Margin Margin (operating revenues less cost of gas) for the three months ended April 30, 2002, decreased $1.1 million compared with the same period in 2001 primarily due to 1.2 million fewer dekatherms consumed by higher-margin residential and commercial customers even though delivered volumes of natural gas, which we refer to as system throughput, increased 1.6 million dekatherms from the same period in 2001. Margin for the current three-month period reflects revenues from customers of $7.4 million from the weather normalization adjustment (WNA) due to weather that was 7% warmer than normal. The WNA is designed to offset the impact of unusually cold or warm weather on customer billings and operating margin. The same period in 2001 reflected increased margin of $5.9 million from the WNA due to weather that was 5% warmer than normal. Margin for the six months ended April 30, 2002, decreased $6.5 million compared with the same period in 2001 primarily due to a decrease in system throughput of 10.1 million dekatherms as fewer volumes were consumed by higher-margin residential and commercial customers. Margin for the current six-month period reflects WNA revenues of $19.8 million, compared with WNA refunds of $8.5 million for the same period in 2001. Margin for the twelve months ended April 30, 2002, decreased $2.8 million compared with the same period in 2001 primarily due to a decrease in system throughput of 16.4 million dekatherms as fewer volumes were consumed by all customer classes due to weather that was 18% warmer. Margin for the current twelve-month period reflects WNA revenues of $19.8 million, compared with WNA refunds of $8.5 million for the same period in 2001. Under gas cost recovery mechanisms, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net amounts of any over- or under- -17- recoveries of gas costs are added to or deducted from cost of gas and included in refunds due customers in the consolidated financial statements. In North Carolina and South Carolina, recovery of gas costs is subject to annual gas cost recovery proceedings to determine the prudency of our gas purchases. We have been found prudent in all such past proceedings; however, there can be no guarantee that we will be found prudent in future proceedings. Operations and Maintenance Expenses Operations and maintenance expenses for the three months ended April 30, 2002, decreased $311,000 compared with the same period in 2001, less than 1%, primarily for the reasons listed below. o Decrease in transportation clearing expenses due to lower fuel costs and depreciation on vehicles. o Decrease in outside labor as outsourced positions were replaced by employees. These decreases were partially offset by an increase in payroll due to the shift from outsourced positions and an increase in rents and leases. Operations and maintenance expenses for the six months ended April 30, 2002, decreased $1.2 million compared with the same period in 2001, less than 2%, primarily for the reasons listed below. o Decrease in outside labor as outsourced positions were replaced by employees. o Decrease in the provision for uncollectibles. These decreases were partially offset by an increase in payroll due to the shift from outsourced positions. Operations and maintenance expenses for the twelve months ended April 30, 2002, increased $619,000 compared with the same period in 2001, less than 1%, primarily for the reasons listed below. o Increase in the provision for uncollectibles. o Increase in risk insurance due primarily to general liability coverage and workers' compensation. o Increase in advertising expenses. These increases were partially offset by the following decreases. o Decrease in outside labor as outsourced positions were replaced by employees. o Decrease in employee benefits due primarily to a decrease in pension expense as administrative fees are now paid from benefit plan assets rather than by the sponsor and a decrease in the cost of postretirement healthcare and life insurance benefits. -18- Depreciation Depreciation expense for the three months, six months and twelve months ended April 30, 2002, increased over similar prior periods due to the growth of plant in service. General Taxes General taxes for the three months ended April 30, 2002, increased $1.6 million compared with the same period in 2001 primarily due to an increase in property taxes. General taxes for the six months and twelve months ended April 30, 2002, increased $1.2 million and $5.2 million, respectively, compared with the same periods in 2001 primarily due to increases in property taxes, franchise taxes and use taxes. Other Income Income from equity investee earnings for the three months ended April 30, 2002, increased $3.7 million compared with the same period in 2001 primarily due to an increase in earnings from unregulated retail energy marketing services. Income from equity investee earnings for the six months and twelve months ended April 30, 2002, decreased $2.1 million and $5 million, respectively, compared with the same periods in 2001 primarily due to decreases in earnings from unregulated retail energy marketing services and from propane, both of which were impacted by warmer weather. Other income for the twelve months ended April 30, 2002, decreased $2.6 million compared with the same period in 2001. The previous twelve-month period includes a gain from the contribution of substantially all of our propane assets in exchange for an interest in Heritage Propane Partners in August 2000, partially offset by losses from the propane operations prior to the contribution. Utility Interest Charges Utility interest charges for the three months ended April 30, 2002, increased $262,000 compared with the same period in 2001 primarily due to an increase in interest on long-term debt from higher amounts of debt outstanding and a decrease in the portion of the allowance for funds used during construction (AFUDC) attributable to borrowed funds. Utility interest charges for the six months and twelve months ended April 30, 2002, increased $740,000 and $585,000, respectively, compared with the same periods in 2001 primarily for the reasons listed below. o Increase in interest on long-term debt from higher amounts of debt outstanding. o Increase in interest on refunds due customers from larger balances outstanding. o Decrease in the portion of AFUDC attributable to borrowed funds. -19- Decreases in interest on short-term debt due to lower balances outstanding at lower rates partially offset these increases for the three, six and twelve months ended April 30, 2002. -20- Item 3. Quantitative and Qualitative Disclosures about Market Risk - ------------------------------------------------------------------- All financial instruments discussed below are held for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Exposure to interest rate changes relates to both short- and long-term debt. Exposure to gas cost variations relates to the supply of and demand for natural gas. Interest Rate Risk - ------------------ We have short-term borrowing arrangements to provide working capital and general corporate funds. The level of borrowings under such arrangements varies from period to period, depending upon many factors including our investments in capital projects. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels. At April 30, 2002, we had no short-term debt outstanding. The weighted average interest rates on short-term debt for the three months and six months ended April 30, 2002, were 2.22% and 3.47%, respectively. We primarily borrow highly liquid debt instruments of a short-term nature. The carrying amount of such debt approximates fair value. The table below provides information at April 30, 2002, about our long-term debt that is sensitive to changes in interest rates. Expected Maturity Date ---------------------- Fair Value There- at April 30, 2002 2003 2004 2005 2006 after Total 2002 ---- ---- ---- ---- ---- ----- ----- ------------ Fixed Rate Long-Term Debt (in millions) $2 $47 $2 -- $35 $425 $511 $544 Average Interest Rate 10.06% 6.39% 10.06% -- 9.44% 7.55% 7.60% Credit Rating - ------------- Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider various factors. The more significant quantitative factors include, among other things: o Ratio of total debt to total capitalization, including balance sheet leverage. o Ratio of net cash flows to capital expenditures. o Funds from operations interest coverage. o Ratio of funds from operations to average total debt. o Pre-tax interest coverage. -21- Qualitative factors include, among other things, stability of regulation in each jurisdiction of our operations, risks and controls inherent with the distribution of natural gas, predictability of cash flows, business strategy and management, industry position and contingencies. At April 30, 2002, our long-term debt consisting of medium-term notes and senior notes were rated A2 by Moody's and A by Standard and Poor's. Commodity Price Risk - -------------------- In the normal course of business, we utilize contracts of various duration for the forward sales and purchases of natural gas. We manage our gas supply costs through a portfolio of short- and long-term procurement contracts with several suppliers. Due to cost-based rate regulation in our utility operations, we have limited exposure to changes in commodity prices as substantially all changes in purchased gas costs are passed on to customers under gas cost recovery mechanisms. Additional information concerning market risk is set forth in "Financial Condition and Liquidity" in Item 2 of this report on page 14. -22- PART II. OTHER INFORMATION Item 5. Other Information - -------------------------- Regulatory Proceedings - ---------------------- On March 28, 2002, we filed an application with the North Carolina Utilities Commission (NCUC) requesting rates and charges to increase annual revenues by $28.2 million, an increase of 6.8%. In addition, we are requesting changes to cost allocations and rate design and changes in tariffs and service regulations. We expect any allowed rate increase to be effective November 1, 2002. A hearing has been set to begin on August 27. We are unable to determine the outcome of this proceeding at this time. As previously reported, the NCUC, on February 26, 2002, issued an order in a generic proceeding that hedging of gas costs is permissible. The NCUC concluded that prudently incurred costs in connection with hedging should be treated as gas costs and would be subject to the annual gas cost prudency review based on the information available at the time of the hedge, not at the time of the prudency review. Each local distribution company may develop its own plan. On April 10, we requested the NCUC to reconsider its decision to make costs incurred in connection with hedging subject to an after-the-fact review for prudence. We also filed an experimental natural gas hedging program for reconsideration and pre-approval. The proposed program defines in advance the parameters for executing hedging transactions and provides that costs incurred under the plan will be deemed to be prudently incurred gas costs. A hearing has been scheduled for June 19 to consider approval of the hedging program as filed. We are unable to determine the outcome of this proceeding at this time. As previously reported, we filed a petition with the Public Service Commission of South Carolina (PSCSC) requesting permission to engage in certain gas cost hedging activities for the purpose of cost stabilization. We requested advance prudency determination and full recovery under gas cost recovery mechanisms for all costs to be incurred in connection with the implementation and administration of the hedging program. On March 26, 2002, the PSCSC issued an order approving this experimental hedging program, including the advance prudency determination. On May 3, 2002, we filed an application with the PSCSC requesting an annual increase in rates of $15.3 million in revenues, an increase of 10.5%. In addition, we are requesting approval of new depreciation rates, changes in cost allocations and rate design and changes in tariffs and service regulations. This is the first general rate filing in South Carolina in seven years. Hearings have been set for September 4 and 5. We are unable to determine the outcome of this proceeding at this time. Asset Purchase - -------------- On May 15, 2002, we announced an agreement to purchase the natural gas distribution assets of North Carolina Gas Service (NCGS), a division of NUI Utilities, Inc., for approximately $26 million in cash. NCGS serves approximately 14,000 customers in Rockingham and Stokes Counties, North Carolina. Completion of the acquisition is contingent upon approval from several regulatory bodies, including -23- the NCUC. We filed for approval of the NCGS asset acquisition with the NCUC on May 31, 2002. We anticipate the approvals and closing of the purchase before the end of the calendar year. Item 6. Exhibits and Reports on Form 8-K - ----------------------------------------- (a) Exhibits - 12 Computation of Ratio of Earnings to Fixed Charges. (b) Reports on Form 8-K - None. -24- SIGNATURES Pursuant to the requirements 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. Piedmont Natural Gas Company, Inc. ---------------------------------- (Registrant) Date June 12, 2002 /s/ David J. Dzuricky --------------- --------------------------------------- David J. Dzuricky Senior Vice President and Chief Financial Officer (Principal Financial Officer) Date June 12, 2002 /s/ Barry L. Guy --------------- --------------------------------------- Barry L. Guy Vice President and Controller (Principal Accounting Officer) -25- EX-12 3 g76784exv12.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12 PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES Computation of Ratio of Earnings to Fixed Charges For Fiscal Years Ended October 31, 1997 through 2001 and Twelve Months Ended April 30, 2002 (in thousands except ratio amounts) -----------------------------------
April 30, 2002 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- ---- Earnings: Pre-tax income from continuing operations $ 81,595 $ 90,683 $ 99,199 $103,077 $100,938 $ 86,484 Distributed income of equity investees 9,576 9,885 4,255 -- -- 9,252 Fixed charges 45,225 47,793 44,368 37,978 38,415 39,263 -------- -------- -------- -------- -------- -------- Total Adjusted Earnings $136,396 $148,361 $147,822 $141,055 $139,353 $134,999 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest $ 43,487 $ 45,286 $ 42,010 $ 35,911 $ 36,453 $ 36,949 Amortization of debt expense 355 420 465 323 304 346 One-third of rental expense 1,383 2,087 1,893 1,744 1,658 1,968 -------- -------- -------- -------- -------- -------- Total Fixed Charges $ 45,225 $ 47,793 $ 44,368 $ 37,978 $ 38,415 $ 39,263 ======== ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges 3.02 3.10 3.33 3.71 3.63 3.44 ==== ==== ==== ==== ==== ====
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