-----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, Io9sWY7NVFdI1Czd+WlkBUpNYUPKD7kY9jSzO7zHv/soQf1fZMPBBchXGEuVM30G hH64o3Tu9bdrDLAo+jpbCw== 0000930661-99-002836.txt : 19991215 0000930661-99-002836.hdr.sgml : 19991215 ACCESSION NUMBER: 0000930661-99-002836 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991214 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ATMOS ENERGY CORP CENTRAL INDEX KEY: 0000731802 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 751743247 STATE OF INCORPORATION: TX FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-10042 FILM NUMBER: 99774410 BUSINESS ADDRESS: STREET 1: 1800 THREE LINCOLN CTR STREET 2: 5430 LBJ FREEWAY CITY: DALLAS STATE: TX ZIP: 75240 BUSINESS PHONE: 9729349227 MAIL ADDRESS: STREET 1: 1800 THREE LINCOLN CTR STREET 2: 5430 LBJ FREEWAY CITY: DALLAS STATE: TX ZIP: 75240 FORMER COMPANY: FORMER CONFORMED NAME: ENERGAS CO DATE OF NAME CHANGE: 19881024 10-K405 1 FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30, 1999 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 For the fiscal year ended September 30, 1999 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 1-10042 ATMOS ENERGY CORPORATION (Exact name of registrant as specified in its charter) TEXAS AND VIRGINIA 75-1743247 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas 75240 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code: (972) 934-9227 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered ------------------- ---------------------- Common stock, No Par Value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None 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 --- --- "continued" 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] The aggregate market value of the voting stock held by non-affiliates of the registrant was $660,086,573 as of November 24, 1999. On November 24, 1999 the registrant had 31,316,186 shares of common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Annual Report to Shareholders for the year ended September 30, 1999 are incorporated by reference into Parts I, II and IV of this report. Portions of the registrant's Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 9, 2000 are incorporated by reference into Part III of this report. ATMOS ENERGY CORPORATION ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 1999 TABLE OF CONTENTS Page no. Cautionary statement regarding forward-looking statements 5 PART I Item 1. Business 6 Acquisitions and Mergers 8 Operating Statistics 9 Utility Energy Services and Propane Data 14 Gas Sales 15 Gas Supply 16 Regulation and Rates 18 Competition 22 Employees 23 Item 2. Properties 23 Item 3. Legal Proceedings 24 Item 4. Submission of Matters to a Vote of Security Holders 24 Executive Officers of the Registrant 25 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 26 Item 6. Selected Financial Data 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 26 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 26 3 Page no. Item 8. Financial Statements and Supplementary Data 27 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 27 PART III Item 10. Directors and Executive Officers of the Registrant 28 Item 11. Executive Compensation 28 Item 12. Security Ownership of Certain Beneficial Owners and Management 28 Item 13. Certain Relationships and Related Transactions 28 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 29 4 Cautionary Statement under the Private Securities Litigation Reform Act of 1995 The matters discussed or incorporated by reference in this Annual Report on Form 10-K may contain "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this Report regarding the Company's financial position, business strategy and plans and objectives of management of the Company for future operations, are forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report or in any of the Company's other documents or oral presentations, the words "anticipate," "expect," "estimate," "plans," "believes," "objective," "forecast," "goal" or other similar words are intended to identify forward- looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to the Company's operations, markets, services, rates, recovery of costs, availability of gas supply, and other factors. These risks and uncertainties include, but are not limited to, national, regional, and local economic and competitive conditions, regulatory and business trends and decisions, technological developments, Year 2000 issues, inflation rates, weather conditions, and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will be realized or will approximate actual results. 5 PART I ITEM 1. BUSINESS Atmos Energy Corporation (the "Company") was organized under the laws of the State of Texas in 1983 as a subsidiary of Pioneer Corporation ("Pioneer") for the purposes of owning and operating Pioneer's natural gas distribution business in Texas. Immediately following the transfer of such business, which had been operated by Pioneer and its predecessors since 1906, Pioneer distributed the outstanding stock of the Company, then known as Energas Company, to Pioneer shareholders. In September 1988, the Company changed its name from Energas Company to Atmos Energy Corporation. As a result of its merger with United Cities Gas Company in July 1997, the Company became incorporated in the Commonwealth of Virginia as well as the State of Texas. The Company distributes and sells natural gas and propane to approximately 1,078,000 residential, commercial, industrial, agricultural, and other customers. The Company distributes and sells natural gas through approximately 1,038,000 meters in 802 cities, towns, and communities in service areas located in Texas, Louisiana, Kentucky, Colorado, Kansas, Illinois, Tennessee, Iowa, Virginia, Georgia, South Carolina and Missouri. The Company also transports gas for others through parts of its distribution system. It also distributes propane to approximately 40,000 customers in Kentucky, North Carolina, Virginia, and Tennessee. The Company's Texas distribution system is operated through its Energas Company division (the "Energas Division") and covers an area having a population of approximately 950,000 people. The economy of the area is based primarily on oil and gas production and agriculture. The principal cities served by the Energas Division include Amarillo, Lubbock, Midland, and Odessa. At September 30, 1999, the Company had approximately 316,000 regulated and non-regulated meters in service in Texas. The Company's Louisiana distribution system is operated through its Trans Louisiana Gas Company division (the "Trans La Division") and covers an area having a population of approximately 250,000 people. The economy of the area is based primarily on oil and gas production, agriculture, and food processing. The principal cities served by the Trans La Division are Lafayette, Pineville, and Natchitoches. At September 30, 1999, the Company had approximately 81,000 meters in service in Louisiana. The Company's Kentucky distribution system is operated through its Western Kentucky Gas Company division (the "Western Kentucky Division") and covers an area having a population of approximately 680,000 people. The economy of the area is based primarily on industry and agriculture. The principal cities served by the Western Kentucky Division include Bowling Green, Owensboro, and 6 Paducah. At September 30, 1999, the Company had approximately 180,000 meters in service in Kentucky. The Company's distribution systems in Colorado and parts of Kansas and Missouri are operated through its Greeley Gas Company division (the "Greeley Division") and covers an area having a combined population of approximately 530,000 people. The economies of the areas served are based on oil and gas production, agriculture and resort business. The principal cities and counties served by the Greeley Division include Greeley, Durango and Lamar, Colorado; Bonner Springs, Herington and Ulysses, Kansas; and Wyandotte and Johnson Counties in Kansas. At September 30, 1999 the Greeley Division had approximately 202,000 meters in service. The Company operates natural gas distribution systems in Georgia, Illinois, Iowa, South Carolina, Tennessee, Virginia and Missouri through its United Cities Gas Company division (the "United Cities Division") and covers an area having a combined population of approximately 6.4 million people. The economies of the areas served include customers engaged in the manufacture of asphalt, automobiles, auto parts, chemicals, electronics, food products, metals, textiles and wire, among others. The division also serves several colleges and a major army base. The principal cities served by the United Cities Division include Franklin and Murfreesboro, Tennessee; Hannibal, Missouri; and Gainesville and Columbus, Georgia. At September 30, 1999, the United Cities Division had approximately 259,000 meters in service. The Company also operates certain non-regulated businesses through various wholly-owned subsidiaries. One subsidiary, Atmos Storage, Inc. ("Storage"), provides natural gas storage services. It owns natural gas storage fields in Kentucky and Kansas to supplement natural gas used by customers in Kansas, Tennessee, and other states. Another subsidiary, Atmos Energy Marketing, LLC, owns a 45% interest in Woodward Marketing, LLC ("WMLLC"), a Delaware limited liability company that provides natural gas services. WMLLC provides gas marketing and energy management services to industrial customers, municipalities and local distribution companies, including the Trans La, Western Kentucky and United Cities Divisions. In addition, Atmos Energy Services, Inc. markets gas to industrial and irrigation customers primarily in West Texas through Enermart Energy Services Trust ("Enermart") and to industrial customers in Louisiana, and is developing plans for marketing various non-regulated services and products. United Cities Propane Gas, Inc. ("Propane") is engaged primarily in the retail distribution of propane ("LP") gas, and on a much smaller scale, the wholesale supply of LP gas. It exited 7 the direct merchandising and repair of propane gas appliances in 1999. Propane currently has operation and storage centers and storefront offices located in Tennessee, Kentucky, and North Carolina, with a total company storage capacity of approximately 2.5 million gallons. As of September 30, 1999, Propane served approximately 40,000 customers in the states listed above as well as Virginia. During the three-year period ended September 30, 1999, the propane operations added approximately 10,900 customers through acquisitions of six propane distribution companies and a propane transport company. Finally, Atmos Leasing Inc. and Atmos Energy Marketing, LLC, leases real estate and vehicles to the United Cities Division and leases appliances to residential customers. The natural gas distribution business is subject to a number of factors, many of which affect the Company from time to time. These include (i) the ongoing need to obtain adequate and timely rate relief from regulatory authorities to recover costs of service and earn a fair return on invested capital; (ii) inherent seasonality of the business; (iii) competition with alternate fuels; (iv) competition with other gas sources for industrial customers, including the ability of some customers to bypass the Company's facilities, which could result in loss of revenues and reduction in the Company's net income; and (v) possible volatility in the supply and price of natural gas and propane. The propane distribution business is also subject to seasonality and competition with alternate fuels and other suppliers. ACQUISITIONS AND MERGERS Since its organization in 1983, the Company has sought to expand its customer base and to diversify the weather patterns, local economic conditions, and regulatory environments to which its operations are subject. As part of this strategy, the Company acquired Trans Louisiana Gas Company, Inc. ("TLG") in January 1986, Western Kentucky Gas Utility Corporation ("WKG") in December 1987, Greeley Gas Company ("GGC") in December 1993, Oceana Heights Gas Company of Thibodaux, Louisiana in November 1995 and United Cities Gas Company ("UCGC") in July 1997. Subsequent to September 30, 1999, the Company entered into a definitive agreement with Southwestern Energy Company ("Southwestern") on October 15, 1999 to acquire the Missouri natural gas distribution assets of Associated Natural Gas, a division of Arkansas Western Gas, which is a wholly- owned subsidiary of Southwestern. Under the terms of the agreement, the Company will purchase the Missouri gas system for approximately $32.0 million in cash plus working capital adjustments. This transaction, which will add approximately 48,000 customers, is expected to be completed by mid-year 2000, subject to approvals by the Missouri Public Service Commission and the Federal Energy Regulatory Commission. 8 The Company continues to consider and pursue, where appropriate, additional acquisitions of natural gas distribution properties and other business opportunities. For further information regarding the UCGC merger, see Note 2 of notes to consolidated financial statements in the Company's Annual Report to Shareholders. OPERATING STATISTICS The table on the following page reflects the operating statistics of Atmos including the United Cities Division for fiscal 1999 and 1998 and the restated operating statistics for 1997, 1996 and 1995 on a pooled basis with UCGC. It is followed by two tables of utility sales and operating statistics by business unit for 1999 and 1998, respectively. Certain prior year amounts have been reclassified to conform with the current year presentation. 9 ATMOS ENERGY CORPORATION CONSOLIDATED OPERATING STATISTICS
Year ended September 30, ------------------------------------------------------------- 1999 1998 1997 1996 1995 ----------- ----------- ----------- ----------- --------- METERS IN SERVICE, end of year Residential 919,012 889,074 870,747 860,229 834,376 Commercial 98,268 94,302 92,703 91,960 90,093 Industrial 14,329 16,322 17,217 19,403 19,762 Public authority and other 6,386 4,834 4,781 4,716 4,982 ----------- ----------- ----------- ----------- --------- Total meters 1,037,995 1,004,532 985,448 976,308 949,213 Propane customers 39,539 37,400 29,097 26,108 23,359 ----------- ----------- ----------- ----------- --------- Total 1,077,534 1,041,932 1,014,545 1,002,416 972,572 =========== =========== =========== =========== ========= HEATING DEGREE DAYS (2) Actual (weighted average) 3,374 3,799 3,909 4,043 3,706 Percent of normal 85% 95% 98% 101% 93% SALES VOLUMES - MMcf (3) Residential 67,128 73,472 75,215 77,001 69,666 Commercial 31,457 36,083 37,382 38,247 34,921 Industrial(including agricultural) 35,741 44,881 46,416 57,863 57,290 Public authority and other 5,793 4,937 5,195 5,182 4,779 ----------- ----------- ----------- ----------- --------- Total sales volumes 140,119 159,373 164,208 178,293 166,656 Transportation volumes - MMcf (3) 55,468 56,224 48,800 44,146 47,647 ----------- ----------- ----------- ----------- --------- TOTAL THROUGHPUT - MMcf (3) 195,587 215,597 213,008 222,439 214,303 =========== =========== =========== =========== ========= PROPANE - Gallons (000's) 22,291 23,412 25,204 33,637 28,854 =========== =========== =========== =========== ========= OPERATING REVENUES (000's) Gas sales revenues Residential $ 349,691 $ 410,538 $ 452,864 $ 409,039 $ 337,768 Commercial 144,836 184,046 193,302 186,032 150,949 Industrial(including agricultural) 117,382 161,382 168,386 187,693 171,591 Public authority and other 22,330 20,504 23,898 21,738 18,185 ----------- ----------- ----------- ----------- --------- Total gas sales revenues 634,239 776,470 838,450 804,502 678,493 Transportation revenues 23,101 23,971 19,885 18,872 19,813 Other gas revenues 4,500 8,121 6,385 13,751 9,374 ----------- ----------- ----------- ----------- --------- Total gas revenues 661,840 808,562 864,720 837,125 707,680 Propane revenues 22,944 29,091 33,194 38,372 24,651 Other revenues 5,412 10,555 8,921 11,194 17,224 ----------- ----------- ----------- ----------- --------- Total operating revenues $ 690,196 $ 848,208 $ 906,835 $ 886,691 $ 749,555 =========== =========== =========== =========== ========= AVERAGE SALES PRICE/Mcf $4.53 $4.87 $5.11 $4.51 $4.07 AVERAGE COST OF GAS/Mcf SOLD 2.79 3.24 3.51 3.15 2.70 AVERAGE TRANSPORTATION REVENUES/Mcf .42 .43 .41 .43 .42
See footnotes on page 13. 10 UTILITY SALES AND STATISTICAL DATA BY BUSINESS UNIT - 1999 (1)
Year ended September 30, 1999 ------------------------------------------------------------------ Western United Total Energas Trans La Kentucky Greeley Cities Utility --------- --------- --------- --------- --------- ----------- METERS IN SERVICE, at end of year Residential 274,452 74,890 159,449 181,859 228,362 919,012 Commercial 26,300 5,567 18,371 17,736 30,294 98,268 Industrial (incl. agricultural) 13,014 128 238 339 610 14,329 Public authority and other 2,230 893 1,559 1,704 - 6,386 -------- ------- -------- -------- -------- ---------- Total 315,996 81,478 179,617 201,638 259,266 1,037,995 ======== ======= ======== ======== ======== ========== HEATING DEGREE DAYS(2) Actual 3,083 1,265 3,472 4,992 3,168 3,374 Normal 3,531 1,771 4,333 5,696 3,784 3,990 Percent of normal 87% 71% 80% 88% 84% 85% SALES VOLUMES-MMcf(3) Residential 20,871 3,111 11,822 16,748 14,576 67,128 Commercial 6,825 1,334 5,122 6,642 11,534 31,457 Industrial (incl. agricultural) 1,514 - 2,973 1,462 14,952 20,901 Public authority and other 2,234 769 1,371 1,419 - 5,793 -------- ------- -------- -------- -------- ---------- Total 31,444 5,214 21,288 26,271 41,062 125,279 TRANSPORTATION VOLUMES-MMcf(3) 4,637 696 25,814 10,021 14,300 55,468 -------- ------- -------- -------- -------- ---------- TOTAL THROUGHPUT-MMcf(3) 36,081 5,910 47,102 36,292 55,362 180,747 ======== ======= ======== ======== ======== ========== OTHER STATISTICS Operating revenues (000's) $123,656 $36,644 $100,165 $132,093 $224,755 $ 617,313 Miles of pipe 13,244 2,276 3,668 5,676 5,806 30,670 Employees(4) 372 128 258 286 427 1,471 Communities served 92 41 163 123 383 802
See footnotes on page 13. 11 UTILITY SALES AND STATISTICAL DATA BY BUSINESS UNIT - 1998 (1)
Year ended September 30, 1998 ------------------------------------------------------------------ Western United Total Energas Trans La Kentucky Greeley Cities Utility --------- --------- --------- --------- --------- ----------- METERS IN SERVICE, at end of year Residential 272,190 74,522 156,107 176,316 209,939 889,074 Commercial 25,982 5,526 18,000 19,367 25,427 94,302 Industrial (incl. agricultural) 14,753 123 442 409 595 16,322 Public authority and other 2,278 977 1,579 - - 4,834 -------- ------- -------- -------- -------- ---------- Total 315,203 81,148 176,128 196,092 235,961 1,004,532 ======== ======= ======== ======== ======== ========== HEATING DEGREE DAYS(2) Actual 3,669 1,725 3,771 5,322 3,544 3,799 Normal 3,531 1,771 4,333 5,696 3,784 3,989 Percent of normal 104% 97% 87% 93% 94% 95% SALES VOLUMES-MMcf(3) Residential 23,594 3,670 12,413 17,602 16,193 73,472 Commercial 7,754 1,433 5,530 9,321 12,045 36,083 Industrial (incl. agricultural) 2,076 - 3,415 1,783 14,982 22,256 Public authority and other 2,559 917 1,461 - - 4,937 -------- ------- -------- -------- -------- ---------- Total 35,983 6,020 22,819 28,706 43,220 136,748 TRANSPORTATION VOLUMES-MMcf(3) 5,526 949 25,813 10,244 13,692 56,224 -------- ------- -------- -------- -------- ---------- TOTAL THROUGHPUT-MMcf(3) 41,509 6,969 48,632 38,950 56,912 192,972 ======== ======= ======== ======== ======== ========== OTHER STATISTICS Operating revenues (000's) $156,170 $36,326 $123,588 $148,331 $274,030 $ 738,445 Miles of pipe 13,217 2,248 3,647 5,322 5,674 30,108 Employees(4) 401 134 267 193 621 1,616 Communities served 92 41 163 123 383 802
See footnotes on page 13. 12 Notes to preceding tables: - -------------------------- (1) These tables present data for Atmos' five utility business units. Their operations include the regulated local distribution companies located in their respective service areas. (2) A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The greater the number of heating degree days, the colder the climate. Heating degree days are used in the natural gas industry to measure the relative coldness of weather experienced and to compare relative temperatures between one geographic area and another. Normal degree days are based on 30-year average National Weather Service data for selected locations. (3) Volumes are reported as metered in million cubic feet ("MMcf"). (4) The number of employees excludes 427 and 391 Atmos shared services and customer support center employees and 164 and 186 non-utility employees in 1999 and 1998, respectively. 13 UTILITY, ENERGY SERVICES AND PROPANE DATA The following table summarizes certain information regarding the operation of the utility, energy services and propane segments of the Company for each of the three years as of and for the period ended September 30, 1999. Amounts for 1997 have been restated to reflect the pooling of interests with UCGC on July 31, 1997. Energy Utility Services Propane Total ---------- -------- -------- ---------- (In thousands) 1999 Operating revenues (1) $ 617,313 $49,939 $22,944 $ 690,196 Operating income (loss) 49,000 5,782 (543) 54,239 Net income (loss) 10,800 7,813 (869) 17,744 Identifiable assets (1) 1,125,691 71,115 33,731 1,230,537 1998 Operating revenues (1) $ 738,445 $80,672 $29,091 $ 848,208 Operating income 100,665 11,595 619 112,879 Net income (loss) 43,332 11,999 (66) 55,265 Identifiable assets (1) 1,052,225 52,616 36,549 1,141,390 1997 Operating revenues (1) $ 805,252 $68,389 $33,194 $ 906,835 Operating income 61,213 4,991 405 66,609 Net income (loss) 19,739 4,189 (90) 23,838 Identifiable assets (1) 1,002,690 62,511 23,110 1,088,311 (1) Net of intersegment eliminations The utility segment is comprised of the Company's five regulated utility divisions: Energas Division, Greeley Division, Trans La Division, United Cities Division and Western Kentucky Division. The energy services segment is currently composed of four parts. Atmos Storage Inc., owns underground storage fields in Kansas and Kentucky and provides storage services to the United Cities Division and Greeley Division and other non-regulated customers. Atmos Energy Services, Inc., markets gas to irrigation and industrial customers in West Texas through Enermart Energy Services Trust, and to industrial customers in Louisiana and is developing plans for marketing various non-regulated services and products. Atmos Energy Marketing, LLC, owns the Company's 45% investment in WMLLC, a gas marketing and energy management services business. Atmos Leasing, Inc., leases buildings and vehicles to the United Cities Division and gas appliances to residential customers. 14 The propane segment includes United Cities Propane Gas, Inc., which is primarily engaged in the retail and wholesale distribution of propane gas in Tennessee, Kentucky, North Carolina and Virginia. GAS SALES The Company's natural gas distribution business is seasonal and highly dependent on weather conditions in the Company's service areas. Gas sales to residential and commercial customers are greater during the winter months than during the remainder of the year. The volumes of such sales during the winter months will vary with the temperatures during such months. The seasonal nature of the Company's sales to residential and commercial customers is offset partially by the Company's sales in the spring and summer months to its agricultural customers in Texas, Colorado and Kansas who utilize natural gas to operate irrigation equipment. The Company also has weather normalization adjustments in its rate jurisdictions in Tennessee and Georgia, which serve approximately 186,000 customers. The Company believes that it has lessened its sensitivity to weather risk by diversifying its operations into geographic areas having different weather patterns. In addition to weather, the Company's revenues are affected by the cost of natural gas and economic conditions in the areas that the Company serves. Higher gas costs, which the Company is generally able to pass through to its customers under purchased gas adjustment clauses, may cause customers to conserve, or, in the case of industrial customers, to use alternative energy sources. In recent years, natural gas market conditions have changed. Natural gas prices to distributors have become more volatile and the number of competing marketers of natural gas has increased. The Company's gas marketing subsidiaries purchase gas to address requirements for large volume customers in certain highly competitive markets. In certain instances, customers purchase gas directly from others instead of from the Company and the Company transports such gas through its distribution systems to the customers' facilities for a fee. Although transportation of customer-owned gas reduces the Company's operating revenues and corresponding purchased gas cost, the transportation revenues received by the Company generally offset the loss to gross profit. The Company's distribution systems have experienced aggregate peak day deliveries of approximately 1.5 billion cubic feet ("Bcf") per day. The Company has the ability to curtail deliveries to certain customers under the terms of interruptible contracts and applicable state statutes or regulations which enables it to maintain its deliveries to high priority customers. The Company has not imposed curtailment in its Energas Division since the Company began independent operations in 1983 or in its Trans La 15 Division since the Company acquired TLG in 1986. The Western Kentucky Division curtailed deliveries to certain interruptible customers during exceptionally cold periods in December 1989, January 1994 and during the winter of 1996. Neither the Greeley Division nor its predecessor, GGC, have curtailed deliveries to its sales customers since prior to 1980. The United Cities Division curtails interruptible service customers from time to time each year in accordance with the interruptible contracts and tariffs. GAS SUPPLY The Company receives gas deliveries through some 28 pipeline transportation companies, both interstate and intrastate, to satisfy its firm sales market requirements. The transportation agreements are firm and many of them have pipeline no-notice storage service which provide for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term available to maintain the Company's Right of First Refusal which provides the right to roll over the term and yet reduce the risk of stranded demand costs in the event of unbundling its services. The Western Kentucky Division's gas supply is delivered by the following pipelines: Williams Pipeline-Texas Gas, Tennessee Gas, Trunkline, Midwestern Pipeline and ANR, except that a small percentage of the requirements are being purchased directly from intrastate producers that are connected directly to its distribution system. During 1998, WKG sought and was granted approval by the Kentucky Public Service Commission for a Performance-based Rate ("PBR") program. This three-year supply and asset management program commenced in July 1998. The United Cities Division is served by 13 interstate pipelines. The majority of the volumes are transported through East Tennessee Pipeline, Southern Natural Gas and Williams Pipeline-Central. Colorado Interstate Gas Company, Williams Pipeline-Central, Public Service Company of Colorado, and Northwest Pipeline are the principal transporters of the Greeley Division's requirements. Additionally, the Greeley Division purchased substantial volumes from producers that are connected directly to its distribution system. The Energas Division receives sales and transportation service from various KN pipeline affiliates. Also, the Energas Division purchases a significant portion of its supply from Pioneer Natural Resources (formerly Mesa) which is connected directly to the Company's Amarillo, Texas distribution system. 16 Louisiana Intrastate Gas Company ("LIG"), Acadian Pipeline, Koch Gateway and Williams Pipeline-Texas Gas pipelines deliver most of the Trans La Division's requirements. The Company also owns and operates numerous natural gas storage facilities in Kentucky and Kansas which are used to help meet customer requirements during peak demand periods and to reduce the need to contract for additional pipeline capacity to meet such peak demand periods. Additionally, the Company operates various propane plants and a liquified natural gas ("LNG") plant for peak shaving purposes. The Company also contracts for storage service in underground storage facilities of many of the interstate pipelines serving it. See "Item 2. Properties" below for further information regarding the peak shaving facilities. The United Cities and Western Kentucky Gas Divisions normally injects gas into pipeline storage systems and company owned storage facilities during the summer months and withdraws it in the winter months. At the present time, the underground storage facilities of Storage have a maximum daily output capability of approximately 15,000 thousand cubic feet ("Mcf"). The United Cities Division has the ability to serve approximately 60% of its peak day load through the use of company owned storage facilities, storage contracts with its suppliers and peaking facilities throughout the system. This ability provides the operational flexibility and security of supply required to meet the needs of the highly weather sensitive residential and commercial markets. During 1999, the Company purchased its gas supply from various producers and marketers. The suppliers were selected through a bidding process (except for local production purchases) by sending out a Request for Proposal ("RFP") to suppliers that have demonstrated that they can provide reliable service. These suppliers were selected based on their ability to deliver gas supply to our designated firm pipeline receipt points and the best cost. Major suppliers during 1999 were Reliant Energy, Sonat Marketing, KN Marketing, Pioneer Natural, CIG the Merchant, WMLLC, Oneok Gas Marketing, Barrett Resources, Anadarko and Tenaska Marketing. 17 REGULATION AND RATES Regulation - ---------- Energas Division In the Energas Division, the governing body of each municipality served by the Company has original jurisdiction over all utility rates, operations, and services within its city limits except with respect to sales of natural gas for vehicle fuel and agricultural use. The Company operates pursuant to non- exclusive franchises granted by the municipalities it serves, which franchises are subject to renewal from time to time. The franchises granted to the Company permit it to conduct natural gas distribution within the municipalities' incorporated limits. The Railroad Commission of Texas has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality. In Texas, rates for large industrial customers are routinely set by contract negotiation between the Company and its customers pursuant to statutory standards and are filed with and subject to the governmental authority of the municipalities or the Railroad Commission, depending on whether the customer is located inside or outside the limits of a municipality. Historically, the Company's rates for large industrial customers have been accepted as filed. Agricultural sales in Texas are not regulated, except that prices for agricultural sales cannot exceed the prices the Company charges the majority of its commercial or other similar large-volume users in Texas. Trans La Division The Trans La Division is regulated by the Louisiana Public Service Commission, which regulates utility services, rates, and other matters. In most of the parishes and incorporated areas in which the Company operates in Louisiana, it does so pursuant to a non-exclusive franchise granted by the governing authority of each parish or incorporated area. The franchise gives the Company the general privilege to operate its gas distribution business in, as well as the right to install its distribution lines along the roadways of, the parish or the incorporated area. Direct sales of natural gas to industrial customers in Louisiana who utilize the gas for fuel or in manufacturing processes and sales of natural gas for vehicle fuel are exempt from regulation. Western Kentucky Division The Western Kentucky Division is regulated by the Kentucky Public Service Commission, which regulates utility services, rates, issuance of securities, and other matters. The Company operates in the various incorporated cities served by it in Kentucky pursuant to non-exclusive franchises granted by such cities. The franchises 18 grant to the Company the right to operate its gas distribution business in the city and to install its distribution lines and related equipment in and along the city's public rights-of-way. Sales of natural gas for use as vehicle fuel in Kentucky are not subject to regulation. Greeley Division The Greeley Division is regulated by the Colorado Public Utilities Commission, the Kansas Corporation Commission, and the Missouri Public Service Commission with respect to accounting, rates and charges, operating matters, and the issuance of securities. The Company operates in the various incorporated cities served by it in the states of Colorado, Kansas and Missouri under terms of non-exclusive franchises granted by the various cities. The franchises grant to the Company, among other things, the right to install and operate its gas distribution system within the city limits. Most of the Greeley Division's wholesale gas suppliers are regulated by various federal and state commissions. United Cities Division In each state in which the United Cities Division operates, its rates, services and operations as a natural gas distribution company is subject to general regulation by the state public service commission. In addition, the issuance of securities by the Company is subject to approval by the state commissions, except in South Carolina and Iowa. Missouri only regulates the issuance of secured debt. The United Cities Division operates in each community, where necessary, under a franchise granted by the municipality for a fixed term of years. To date, it has been able to renew franchises and expects to continue to do so in the future. The Company is also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of its gas distribution facilities. The Company's distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time the Company receives inquiries regarding various environmental matters. The Company believes that its properties and operations substantially comply with and are operated in substantial conformity with applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which, if adversely determined, would have a material adverse effect on the Company. 19 Rates - ----- Approximately 89% of the Company's revenues in fiscal 1999 were derived from sales at rates set by or subject to approval by local or state authorities. The method of determining regulated rates varies among the twelve states in which the Company has utility operations. As a general rule, the regulatory authority reviews the Company's rate request and establishes a rate structure intended to generate revenue sufficient to cover the Company's costs of doing business and provide a reasonable return on invested capital. Substantially all of the sales rates charged by the Company to its customers fluctuate with the cost of gas purchased by the Company. Rates established by regulatory authorities are adjusted for increases and decreases in the Company's purchased gas cost through automatic purchased gas adjustment mechanisms. Therefore, while the Company's operating revenues may fluctuate, gross profit (which is defined as operating revenues less purchased gas cost) is generally not eroded or enhanced because of gas cost increases or decreases. The Georgia Public Service Commission and Tennessee Regulatory Authority have approved Weather Normalization Adjustments ("WNA") that allow the United Cities Division to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. The net effect of the WNAs was an increase (decrease) in revenues of $4,394,000, $682,000 and $2,643,000 in 1999, 1998 and 1997, respectively. 20 The following table sets forth the major rate requests made by the Company or other parties during the most recent five years and the action taken on such requests: Effective Amount Amount Jurisdiction Date Requested Received ------------ -------- --------- -------- (In thousands) Texas West Texas System 11/18/94 $ 2,581 $ 1,702 (a) 11/01/96 7,676 5,800 (a) Pending 8,827 Pending (g) Amarillo System Pending 4,354 Pending (g) Louisiana 11/01/99 (b) - (b) Kentucky 11/01/95 7,665 2,300 (c) 03/01/96 1,000 (c) Pending 14,127 Pending (h) Colorado 05/01/94 4,527 3,246 01/21/98 - (1,600) (e) Kansas 09/01/95 4,230 2,700 (d) Missouri 10/14/95 1,100 903 South Carolina 02/07/95 341 253 Tennessee 11/15/95 3,951 2,227 Iowa 05/17/96 750 410 Georgia 12/02/96 5,003 3,160 Illinois 07/09/97 1,234 428 Virginia 09/29/95 810 103 10/01/98 - (248) (f) (a) These increases include $200,000 and $500,000 applicable to areas outside the city limits which became effective in January 1995 and April 1997, respectively. (b) The Louisiana Public Service Commission approved a Rate Stabilization Clause ("RSC") for three years with an allowed return on common equity between 10.5% and 11.5%. This decision increased the service charge amounts from about 20% to about 70% of actual costs, and increased the monthly customer charges from $6 to $9, both effective November 1, 1999. (c) The Kentucky rate order provided an increase of $2,300,000, lowered depreciation rates effective November 1, 1995 and 21 provided an additional $1,000,000 beginning March 1, 1996. The order also included a provision for a pilot demand side management program which could cost up to $450,000 annually. (d) This increase applied to the Kansas area previously served by the United Cities Division and transferred to the Greeley Division in 1999. (e) Rate reduction as a result of settlement in a case initiated by the Colorado Consumer Counsel. (f) Rate reduction as a result of a settlement with the Virginia State Corporation Commission staff regarding investigation of earnings. (g) The Energas Division applied for rate increases in August 1999. The proposed rates have been suspended until December 8, 1999. (h) The Western Kentucky Gas Division applied for an increase in May 1999. A hearing is scheduled for December 14, 1999. COMPETITION The Company is not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within its service areas. However, the Company does compete with other natural gas suppliers and suppliers of alternate fuels for sales to industrial and agricultural customers. The Company competes in all aspects of its business with alternative energy sources, including, in particular, electricity. Competition for the residential and commercial customers is increasing. Promotional incentives, improved equipment efficiencies, and promotional rates all contribute to the acceptability of electric equipment. In the United Cities Division, #2 and #6 fuel oil are the primary competition for industrial customers. In addition, certain customers, primarily industrial, may have the ability to by-pass the Company's distribution system by connecting directly with a pipeline. Beginning in 1985, changes in the federal regulatory environment through Federal Energy Regulatory Commission ("FERC") orders and conditions related to markets and gas supply in the United States have brought increased competition into the natural gas industry. In 1993, FERC Order 636 was implemented by the interstate pipelines that serve the United Cities and Western Kentucky Divisions, but FERC policies have not had a direct impact upon the Company's Energas, Greeley and Trans La Divisions which are primarily supplied by intrastate pipelines. However, competition for large volume customers in the United Cities and Western Kentucky Divisions and other service areas has increased as a result of FERC Order 636. The Company has sought regulatory approvals for competitive pricing on a case by case basis. 22 The United Cities Division has received approval from all the regulatory authorities in the states in which it operates, except Iowa, to place into effect a negotiated tariff rate which allows the United Cities Division to maintain industrial loads at lower margin rates. Iowa has rules which allow for flexible rates, which are competitive with the price of alternative fuels. In addition, certain industrial customers have changed from firm to interruptible rate schedules in order to obtain natural gas at a lower cost. Additionally, the United Cities Division has received approval from all state regulatory authorities to provide transportation service of customer-owned gas. United Cities Propane Gas, Inc. is in competition with other suppliers of propane, natural gas and electricity with respect to price and service. The wholesale cost of propane is subject to fluctuations primarily based on demand, availability of supply and product transportation costs. Through its 45% interest in WMLLC, Atmos Energy Marketing, LLC competes with other natural gas brokers in obtaining natural gas supplies for customers. Atmos Leasing, Inc. also competes with other companies in the leasing of real estate, vehicles, and appliances. Atmos Storage, Inc. charges rates to the United Cities Division that are subject to review by the various commissions in the states within which the storage service is provided. Therefore, Storage's rates must be competitive with other storage facilities. Storage also stores natural gas for WMLLC. As a result, Storage is in competition with other companies that store natural gas as to rates charged and deliverability of natural gas. Agreements between Storage and the United Cities Division give the United Cities Division first priority to any storage services. EMPLOYEES At September 30, 1999, the Company employed 2,062 persons. See "Utility Sales and Statistical Data by Business Unit - 1999" for the number of employees by business unit. As discussed in Note 2 of notes to consolidated financial statements in the Company's Annual Report to Shareholders, the Company underwent downsizing and restructuring in 1997 and 1998 in connection with the integration of UCGC and the reorganization of the Company's other divisions. ITEM 2. PROPERTIES The Company owns an aggregate of 30,670 miles of underground distribution and transmission mains throughout its gas distribution systems. These mains are located on easements or right-of-ways granted to the Company, which generally provide for perpetual use. The Company maintains its mains through a program of continuous 23 inspection and repair and believes that its system of mains is in good condition. The Company also owns and operates nine propane peak shaving plants with a total capacity of approximately 1,050,000 gallons that can produce an equivalent of 19,459 Mcf daily and an LNG storage facility with a capacity of 500,000 Mcf which can inject a daily volume of 30,000 Mcf in the system, as well as underground storage fields which are used to supplement the supply of natural gas in periods of peak demand. It has seven underground gas storage facilities in Kentucky and four in Kansas that have a total storage capacity of approximately 21.1 Bcf. However, approximately 10.0 Bcf of gas in the storage facilities must be retained as cushion gas to maintain reservoir pressure. The maximum daily delivery capability of the storage facilities is approximately 154 MMcf. Substantially all of the Company's properties in its Greeley Division and United Cities Division with net values of approximately $173.7 million and $293.0 million, respectively, are subject to liens under First Mortgage Bonds assumed by the Company in its mergers with GGC and UCGC. At September 30, 1999, the liens secured $17.0 million of outstanding 9.4% Series J First Mortgage Bonds due May 1, 2021, and $102.2 million of outstanding Series N, P, Q, R, T, U and V First Mortgage Bonds due at various dates from 2000 through 2022. The Company's administrative offices are consolidated in Dallas, Texas under one lease. The Company also maintains field offices throughout its distribution system, the majority of which are located in leased premises. Net property, plant and equipment at September 30, 1999 included approximately $918.2 million for utility, $23.8 million for energy services, and $23.8 million for propane. The Company holds franchises granted by the incorporated cities and towns that it serves. At September 30, 1999, the Company held 408 such franchises having terms generally ranging from five to 25 years. The Company believes that each of its franchises will be renewed. ITEM 3. LEGAL PROCEEDINGS Incorporated by reference from the 1999 Annual Report to Shareholders, Note 6 of notes to consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of fiscal 1999. 24 EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth certain information as of September 30, 1999, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer during the past five years. Years of Name Age Service Office Currently Held - ---------------------------------------------------------------------------- Robert W. Best 52 2 Chairman, President and Chief Executive Officer Larry J. Dagley 51 2 Executive Vice President and Chief Financial Officer J. Charles Goodman 38 15 Executive Vice President, Utility Operations Wynn D. McGregor 46 11 Vice President, Human Resources Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997. He previously served as Senior Vice President- Regulated Businesses of Consolidated Natural Gas Company (1996 - March 1997) and was responsible for its transmission and distribution companies. Prior to that, he served as Senior Vice President of Transco Energy Company and President of Transcontinental Gas Pipe Line Corporation (1992-1995); and President of Texas Gas Transmission Corporation (1985 - 1995). Larry J. Dagley was named Executive Vice President and Chief Financial Officer effective May 1, 1997. From August 1995 to May 1997, he served as Senior Vice President and Chief Financial Officer of Pacific Enterprises, a Los Angeles, California based utility holding company whose principal subsidiary was Southern California Gas Co., the nation's largest gas distribution utility. From 1985 until joining Pacific Enterprises, he served as Senior Vice President and Controller (1985-1993) and Senior Vice President and Chief Financial Officer (1993-1995) of Transco Energy Company, a Houston, Texas based natural gas pipeline company. Prior to joining Transco, Mr. Dagley was an audit partner with Arthur Andersen & Co., where he supervised audits and financial consulting engagements in the energy industry. J. Charles Goodman was named Executive Vice President, Operations in April 1995. He previously served as President of the Company's Trans La Gas Division from February 1993 until April 1995 and as Chief Engineer of the Company from February 1989 until February 1993. Wynn D. McGregor was named Vice President, Human Resources in January 1994. He previously served the Company as Director of Human Resources from February 1991 to December 1993 and as Manager, Compensation and Employment from December 1987 to January 1991. 25 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information required by this item is set forth under the caption "Market Price of Common Stock and Related Matters" in the Financial Review section of Atmos' 1999 Annual Report to Shareholders filed as Exhibit 13 to this Annual Report on Form 10-K. Such information is incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA The information required by this item is set forth under the caption "Selected Financial Data" in the Financial Review section of Atmos' 1999 Annual Report to Shareholders filed as Exhibit 13 to this Annual Report on Form 10-K. Such information is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this item is set forth under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Financial Review section of Atmos' 1999 Annual Report to Shareholders filed as Exhibit 13 to this Annual Report on Form 10-K. Such information is incorporated herein by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The risk inherent in the Company's market risk sensitive instruments is the potential loss arising from adverse changes in natural gas commodity prices and interest rates as discussed below. The sensitivity analysis does not, however, consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions the Company may take to mitigate its exposure to such changes. Actual results may differ. Gas Prices The Company purchases natural gas for its regulated and non-regulated natural gas operations. Substantially all of the gas purchased for regulated operations is recovered through purchased gas adjustment mechanisms. The Company's market risk in gas prices is related to gas purchases in the open market at spot prices for sale to non-regulated energy services customers at fixed prices. As a result, the Company's earnings could be 26 affected by changes in the price and availability of such gas. As market conditions dictate, the Company from time to time will lock-in future gas prices, using various hedging techniques including swap agreements with suppliers. The Company does not use such financial instruments for trading purposes and is not a party to any leveraged derivatives. Market risk is estimated as a hypothetical 10% increase in the portion of the Company's gas cost related to fixed-price non-regulated sales. Based on projected fiscal 2000 non-regulated gas sales at fixed prices, such an increase would result in an increase to cost of gas of approximately $2.8 million in fiscal 2000, before considering the effect of swap agreements outstanding as of September 30, 1999. As of September 30, 1999, the Company had entered into swap agreements to lock in gas costs for all outstanding fixed-price sales agreements. The Company plans to mitigate the risk of increased gas purchase costs for fixed-price customers by entering into swap agreements to lock in purchased gas cost for estimated sales volumes in fiscal 2000. Interest Rates The Company's earnings are affected by changes in short-term interest rates as a result of its issuance of short-term commercial paper. If market interest rates for commercial paper average 2% more in fiscal 2000 than they did during fiscal 1999, the Company's interest expense, would increase by approximately $2.0 million. Market risk for fixed-rate long-term obligations is estimated as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates and amounts to approximately $31.6 million based on discounted cash flow analyses. As of September 30, 1999, the Company was not engaged in other activities which would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates, foreign currency exchange rates, or market commodity prices. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The response to this Item is submitted as a separate section of this Annual Report on Form 10-K on page 33. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 27 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding directors and compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2000. Information regarding executive officers is included in Part I of this Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2000. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2000. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2000. 28 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1. and 2. Financial statements and financial statement schedules. The response to this portion of Item 14 is submitted as a separate section of this Annual Report on Form 10-K on page 33. 3. Exhibits The exhibits listed in the accompanying Exhibits Index are filed as part of this Annual Report on Form 10-K. The exhibits numbered 10.21(a) through 10.32 are management contracts or compensatory plans or arrangements. (b) Reports on Form 8-K (1) The Company did not file a Form 8-K Current Report in the quarter ended September 30, 1999. 29 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. ATMOS ENERGY CORPORATION (Registrant) By /s/ LARRY J. DAGLEY ------------------------ Larry J. Dagley Executive Vice President and Chief Financial Officer Date: December 14, 1999 30 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Robert W. Best and Larry J. Dagley, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. 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 and on the date indicated: /s/ ROBERT W. BEST Chairman, President December 14, 1999 - ------------------------- and Chief Executive Robert W. Best Officer /s/ LARRY J. DAGLEY Executive Vice December 14, 1999 - ------------------------- President and Chief Larry J. Dagley Financial Officer /s/ TOM S. HAWKINS, JR. Vice President, December 14, 1999 - ------------------------- Planning and Budgeting Tom S. Hawkins, Jr. and Interim Controller (Principal Accounting Officer) 31 /s/ TRAVIS W. BAIN, II Director December 14, 1999 - ------------------------- Travis W. Bain, II /s/ DAN BUSBEE Director December 14, 1999 - ------------------------- Dan Busbee /s/ RICHARD W. CARDIN Director December 14, 1999 - ------------------------- Richard W. Cardin /s/ THOMAS J. GARLAND Director December 14, 1999 - ------------------------- Thomas J. Garland /s/ GENE C. KOONCE Director December 14, 1999 - ------------------------- Gene C. Koonce /s/ VINCENT J. LEWIS Director December 14, 1999 - ------------------------- Vincent J. Lewis /s/ THOMAS C. MEREDITH Director December 14, 1999 - ------------------------- Thomas C. Meredith /s/ PHILLIP E. NICHOL Director December 14, 1999 - ------------------------- Phillip E. Nichol /s/ CARL S. QUINN Director December 14, 1999 - ------------------------- Carl S. Quinn /s/ CHARLES K. VAUGHAN Director December 14, 1999 - ------------------------- Charles K. Vaughan /s/ RICHARD WARE II Director December 14, 1999 - ------------------------- Richard Ware II 32 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES (Item 8, 14(a) 1 and 2) Form 10-K Page no. --------- Financial statements and supplementary data: Consolidated balance sheets at September 30, 1999 and 1998 (Contained in Exhibit 13) Consolidated statements of income for the years ended September 30, 1999, 1998 and 1997 (Contained in Exhibit 13) Consolidated statements of shareholders' equity for the years ended September 30, 1999, 1998 and 1997 (Contained in Exhibit 13) Consolidated statements of cash flows for the years ended September 30, 1999, 1998 and 1997 (Contained in Exhibit 13) Notes to consolidated financial statements (Contained in Exhibit 13) Supplementary Quarterly Financial Data (unaudited) (Contained in Exhibit 13) Independent auditors' report (Contained in Exhibit 13) Financial statement schedule for the years ended September 30, 1999, 1998 and 1997: II. Valuation and Qualifying Accounts 34 All other financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and accompanying notes thereto. The financial statements and the independent auditors' report of Ernst & Young LLP listed in the above index, which are included in the Financial Review section of the Annual Report to Shareholders of Atmos Energy Corporation for the year ended September 30, 1999, are incorporated herein by reference. 33 Atmos Energy Corporation Schedule II Valuation and Qualifying Accounts Three Years Ended September 30, 1999 (In thousands)
Additions Balance at ---------------------- Balance beginning Charged to Charged to at end of costs & other of period expenses accounts Deductions period ---------- ---------------------- ----------- ------- 1999 - ---- Allowance for doubtful accounts $1,969 $8,899 - $1,637 (1) $9,231 1998 - ---- Allowance for doubtful accounts $2,188 $2,140 - $2,359 (1) $1,969 1997 - ---- Allowance for doubtful accounts $2,462 $2,003 - $2,277 (1) $2,188
(1) Uncollectible accounts written off 34 EXHIBITS INDEX Item 14. (a) (3)
Page Number or Exhibit Incorporation by Number Description Reference to ------- ------------------------------- --------------------- Plan of Reorganization ---------------------- 2.1 Agreement and Plan of Reorganization dated July 19, Exhibit 2.1 to Registration 1996, by and between the Registrant and United Statement on Form S-4 filed Cities Gas Company October 4, 1996 (File No. 333-13429) 2.2 Amendment No. 1 to Agreement and Plan of Exhibit 2.1(a) to Registration Reorganization dated October 3, 1996 Statement on Form S-4 filed October 4, 1996 (File No. 333-13429) Articles of Incorporation and Bylaws ------------------------------------ 3.1(a) Restated Articles of Incorporation of the Company, Exhibit 3.1 of Form 10-K for as Amended (as of July 31, 1997) fiscal year ended September 30, 1997 (File No. 1-10042) 3.1(b) Articles of Amendment to the Restated Articles of Exhibit 3a of Form 10-Q for Incorporation of Atmos Energy Corporation as quarter ended March 31, 1999 (File Amended (Texas) No. 1-10042) 3.1(c) Articles of Amendment to the Restated Articles of Exhibit 3b of Form 10-Q for Incorporation of Atmos Energy Corporation as quarter ended March 31, 1999 (File Amended (Virginia) No. 1-10042) 3.2 Bylaws of the Company (Amended and Restated as of Exhibit 3.2 of Form 10-K for November 12, 1997) fiscal year ended September 30, 1997 (File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to - --------- ------------------------------ ------------------------ Instruments Defining Rights of Security Holders ----------------------------------------------- 4.1 Specimen Common Stock Certificate (Atmos Energy Exhibit (4)(b) of Form 10-K for Corporation) fiscal year ended September 30, 1988 (File No. 1-10042) 4.2 Rights Agreement, dated as of November 12, 1997, Exhibit 4.1 of Form 8-K dated between the Company and BankBoston, N.A. November 12, 1997 (File no. 1-10042) 4.3 First Amendment to Rights Agreement dated as of Exhibit 2 of Form 8-A, Amendment August 11, 1999, between the Company and No. 1, dated August 12, 1999 (File BankBoston, N.A., as Rights Agent No. 1-10042) 9 Not Applicable Material Contracts ------------------ 10.1(a) Note Purchase Agreement, dated as of December 21, Exhibit 10(c) of Form 8-K filed 1987, by and between the Company and John Hancock January 7, 1988 (File No. 0-11249) Mutual Life Insurance Company Note Purchase Agreement, dated as of December 21, 1987, by and between the Company and John Hancock Charitable Trust I (Agreement is identical to Hancock Agreement listed above except as to the parties thereto.)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------------ ---------------------- Note Purchase Agreement dated as of December 21, 1987, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement (Agreement is identical to Hancock Agreement listed above except as to the parties thereto.) 10.1(b) Amendment to Note Purchase Agreement, dated Exhibit (10)(b)(ii) of Form 10-K October 11, 1989, by and between the Company for fiscal year ended September and John Hancock Mutual Life Insurance Company 30, 1989 revising Note Purchase Agreement dated December (File No. 1-10042) 21, 1987 Amendment to Note Purchase Agreement, dated October 11, 1989, by and between the Company and John Hancock Charitable Trust I revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment listed above except as to the parties thereto.)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------- ---------------------- Amendment to Note Purchase Agreement, dated October 11, 1989, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987 (Amendment is identical to Hancock amendment listed above except as to the parties thereto.) 10.1(c) Amendment to Note Purchase Agreement, dated Exhibit 10(b)(iii) of Form 10-K November 12, 1991, by and between the Company for fiscal year ended September and John Hancock Mutual Life Insurance Company 30, 1991 (File No. 1-10042) revising Note Purchase Agreement dated December 21, 1987 Amendment to Note Purchase Agreement, dated November 12, 1991, by and between the Company and John Hancock Charitable Trust I revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment listed above except as to the parties thereto.)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------- ---------------------- Amendment to Note Purchase Agreement, dated November 12, 1991, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment above except as to the parties thereto.) 10.1(d) Amendment to Note Purchase Agreement, dated Exhibit 4.3(d) to Registration December 22, 1993, by and between the Company Statement on Form S-3 filed April and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated December 21, 1987 Amendment to Note Purchase Agreement, dated December 22, 1993, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1982, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987 (Amendment is identical to Hancock amendment listed above except as to the parties thereto and the amounts thereof)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------------ ---------------------- 10.1(e) Amendment to Note Purchase Agreement, dated Exhibit 4.3(e) to Registration December 20, 1994, by and between the Company Statement on Form S-3 filed April and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated December 21, 1987 Amendment to Note Purchase Agreement, dated December 20, 1994, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987 (Amendment is identical to Hancock amendment listed above) 10.1(f) Amendment to Note Purchase Agreement, dated Exhibit 4.3(f) to Registration July 29, 1997, by and between the Company and Statement on Form S-3 filed April John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated December 21, 1987
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Page Number or Exhibit Incorporation by Number Reference to -------- ------------------------------------------------ ---------------------- Amendment to Note Purchase Agreement, dated July 29,1997, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987 (Amendment is identical to Hancock amendment listed above except as to the parties thereto and the amounts thereof) 10.2(a) Note Purchase Agreement, dated as of October Exhibit 10(c) of Form 10-K for 11, 1989, by and between the Company and John fiscal year ended September 30, Hancock Mutual Life Insurance Company 1989 (File No. 1-10042) 10.2(b) Amendment to Note Purchase Agreement, dated as Exhibit 10(c)(ii) of Form 10-K for of November 12, 1991, by and between the fiscal year ended September 30, Company and John Hancock Mutual Life Insurance 1991 (File No. 1-10042) Company revising Note Purchase Agreement dated October 11, 1989 10.2(c) Amendment to Note Purchase Agreement, dated Exhibit 4.4(c) to Registration December 22, 1993, by and between the Company Statement on Form S-3 filed April and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated October 11, 1989
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ---------------------------------------------- ---------------------- 10.2(d) Amendment to Note Purchase Agreement, dated Exhibit 4.4(d) to Registration December 20,1994, by and between the Company Statement on Form S-3 filed April and John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated October 11, 1989 10.2(e) Amendment to Note Purchase Agreement, dated Exhibit 4.4(e) to Registration July 29, 1997, by and between the Company and Statement on Form S-3 filed April John Hancock Mutual Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated October 11, 1989 10.3(a) Note Purchase Agreement, dated as of August 29, Exhibit 10(f)(i) of Form 10-K for 1991, by and between the Company and The fiscal year ended September 30, Variable Annuity Life Insurance Company 1991 (File No. 1-10042) 10.3(b) Amendment to Note Purchase Agreement, dated Exhibit 10(f)(ii) of Form 10-K for November 26, 1991, by and between the Company fiscal year ended September 30, and The Variable Annuity Life Insurance Company 1991 (File No. 1-10042) revising Note Purchase Agreement dated August 29, 1991 10.3(c) Amendment to Note Purchase Agreement, dated Exhibit 4.5(c) to Registration December 22, 1993, by and between the Company Statement on Form S-3 filed April and The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated August 29, 1991
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------- ---------------------- 10.3(d) Amendment to Note Purchase Agreement, dated Exhibit 4.5(d) to Registration July 29, 1997, by and between the Company and Statement on Form S-3 filed April The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated August 29, 1991 10.4(a) Note Purchase Agreement, dated as of August 31, Exhibit (10)(f) of Form 10-K for 1992, by and between the Company and The fiscal year ended September 30, Variable Annuity Life Insurance Company 1992 (File No. 1-10042) 10.4(b) Amendment to Note Purchase Agreement, dated Exhibit 4.6(b) to Registration December 22, 1993, by and between the Company Statement on Form S-3 filed April and The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated August 31, 1992 10.4(c) Amendment to Note Purchase Agreement, dated Exhibit 4.6(c) to Registration July 29, 1997, by and between the Company and Statement on Form S-3 filed April The Variable Annuity Life Insurance Company 20, 1998 (File No. 333-50477) revising Note Purchase Agreement dated August 31, 1992 10.5(a) Note Purchase Agreement, dated November 14, Exhibit 10.1 of Form 10-Q for 1994, by and among the Company and New York quarter ended December 31, 1994 Life Insurance Company, New York Life Insurance (File No. 1-10042) and Annuity Corporation, The Variable Annuity Life Insurance Company, American General Life Insurance Company, and Merit Life Insurance Company
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------ ---------------------- 10.5(b) Amendment to Note Purchase Agreement, dated Exhibit 4.7(b) to Registration July 29, 1997 by and among the Company and New Statement on Form S-3 filed April York Life Insurance Company, New York Life 20, 1998 (File No. 333-50477) Insurance and Annuity Corporation, The Variable Annuity Life Insurance Company, American General Life Insurance Company and Merit Life Insurance Company revising Note Purchase Agreement dated November 14, 1994 10.6(a) Indenture of Mortgage, dated as of July 15, Exhibit to Registration Statement 1959, from United Cities Gas Company to First of United Cities Gas Company on Trust of Illinois, National Association, and Form S-3 (File No. 33-56983) M.J. Kruger, as Trustees, as amended and supplemented through December 1, 1992 (the Indenture of Mortgage through the 20th Supplemental Indenture) 10.6(b) Twenty-First Supplemental Indenture dated as of Exhibit 10.7(a) of Form 10-K for February 5, 1997 by and among United Cities Gas fiscal year ended September 30, Company and Bank of America Illinois and First 1997 (File No. 1-10042) Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959
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Page Number or Exhibit Incorporation by Number Description Reference to -------- --------------------------------------------- ---------------------- 10.6(c) Twenty-Second Supplemental Indenture dated as Exhibit 10.7(b) of Form 10-K for of July 29, 1997 by and among the Company and fiscal year ended September 30, First Trust National Association and Russell C. 1997 (File No. 1-10042) Bergman supplementing Indenture of Mortgage dated as of July 15, 1959 10.7(a) Form of Indenture between United Cities Gas Exhibit to Registration Statement Company and First Trust of Illinois, National of United Cities Gas Company on Association, as Trustee dated as of November Form S-3 (File No. 33-56983) 15, 1995 10.7(b) First Supplemental Indenture between the Exhibit 10.8(a) of Form 10-K for Company and First Trust of Illinois, National fiscal year ended September 30, Association, as Trustee dated as of July 29, 1997 (File No. 1-10042) 1997 10.8(a) Seventh Supplemental Indenture, dated as of Exhibit 10.1 of Form 10-Q for October 1, 1983 between Greeley Gas Company quarter ended June 30, 1994 (File ("Greeley Division") and the Central Bank of No. 1-10042) Denver, N.A. ("Central Bank") 10.8(b) Ninth Supplemental Indenture, dated as of April Exhibit 10.2 of Form 10-Q for 1, 1991, between the Greeley Division and quarter ended June 30, 1994 (File Central Bank No. 1-10042) 10.8(c) Bond Purchase Agreement, dated as of April 1, Exhibit 10.3 of Form 10-Q for 1991, between the Greeley Division and Central quarter ended June 30, 1994 (File Bank No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------ ---------------------- 10.8(d) Tenth Supplemental Indenture, dated as of Exhibit 10.4 of Form 10-Q for December 1, 1993, between the Company and quarter ended June 30, 1994 (File Colorado National Bank, formerly Central Bank No. 1-10042) 10.9(a) Purchase Agreement for 6-3/4% Debentures due Exhibit 99.1 of Form 8-K dated 2028 by and among Merrill Lynch Co., July 22, 1998 (File No. 1-10042) NationsBanc Montgomery Securities LLC, Edward D. Jones & Co., L.P. and Atmos Energy Corporation dated July 22, 1998 10.9(b) Form of Indenture between Atmos Energy Exhibit 4.1 to Registration Corporation and U.S. Bank Trust National Statement on Form S-3 filed April Association, Trustee 20, 1998 (File No. 333-50477) Gas Supply Contracts -------------------- 10.10(a) Firm Gas Transportation Agreement No. 123535 dated November 1, 1998 between Greeley Gas and Public Service Company of Colorado 10.10(b) Transportation Storage Service Agreement No. Exhibit 10.6(b) of Form 10-K for TA-0544 between Greeley Gas and Williams fiscal year ended September 30, Natural Gas Company dated October 1, 1993 1994 (File No. 1-10042) 10.10(c) Firm Transportation Service Agreement No. Exhibit 10.10(d) of Form 10-K for 33180A, Rate Schedule TF-1, between Greeley Gas fiscal year ended September 30, Company and Colorado Interstate Gas Company, 1998 (File No. 1-10042) dated July 1, 1998.
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------------- ---------------------- 10.10(d) Firm Transportation Service Agreement No. 33181A, Rate Schedule TF-1, between Colorado Interstate Gas Company and Greeley Gas Company dated July 1, 1998 10.10(e) No-Notice Storage and Transportation Delivery Exhibit 10.10(e) of Form 10-K for Service Agreement No. 31028A, Rate Schedule fiscal year ended September 30, NNT-1, between Colorado Interstate Gas Company 1998 (File No. 1-10042) and Greeley Gas Company dated October 1, 1996 10.11 Amarillo Supply Agreement dated January 2, 1993 Exhibit 10.7(a) of Form 10-K for between Energas and Pioneer Natural Resources, fiscal year ended September 30, USA, Inc. (formerly Mesa Operating Company) 1994 (File No. 1-10042) 10.12(a) Agreement for Firm Intrastate Transportation of Exhibit 10.1 of Form 10-Q for Natural Gas in the State of Louisiana between quarter ended March 31, 1998 Trans La and Louisiana Intrastate Gas Company (File No. 1-10042) L.L.C. (LIG) dated December 22, 1997 and effective July 1, 1997 10.12(b) Agreement for Firm 311(a)(2) Transportation of Exhibit 10.2 of Form 10-Q for Natural Gas in the State of Louisiana between quarter ended March 31, 1998 Trans La and Louisiana Intrastate Gas Company (File No. 1-10042) L.L.C. (LIG) dated December 22, 1997 and effective July 1, 1997 10.13(a) Gas Transportation Agreement between Texas Gas Exhibit 10.3 of Form 10-Q for and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993 (Contract no. T3355, zone 3) (File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to --------- ---------------------------------------------- ------------------------- 10.13(b) Gas Transportation Agreement between Texas Gas Exhibit 10.4 of Form 10-Q for and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993 (Contract no. T3819, zone 4) (File No. 1-10042) 10.13(c) Gas Transportation Agreement between Texas Gas Exhibit 10.5 of Form 10-Q for and Western Kentucky Gas dated November 1, 1993 quarter ended December 31, 1993 (Contract no. N0210, zone 2, Contract no. (File No. 1-10042) N0340, zone 3, Contract no. N0435, zone 4) 10.14(a) Gas Transportation Agreement, Contract No. Exhibit 10.17(a) of Form 10-K for 2550, dated September 1, 1993, between fiscal year ended September 30, Tennessee Gas Pipeline Company, a division of 1993 (File No. 1-10042) Tenneco, Inc. ("Tennessee Gas"), and Western Kentucky, Campbellsville Service Area 10.14(b) Gas Transportation Agreement, Contract No. Exhibit 10.17(b) of Form 10-K for 2546, dated September 1, 1993, between fiscal year ended September 30, Tennessee Gas and Western Kentucky, Danville 1993 (File No. 1-10042) Service Area 10.14(c) Gas Transportation Agreement, Contract No. Exhibit 10.17(c) of Form 10-K for 2385, dated September 1, 1993, between fiscal year ended September 30, Tennessee Gas and Western Kentucky, Greensburg 1993 (File No. 1-10042) et al Service Area 10.14(d) Gas Transportation Agreement, Contract No. Exhibit 10.17(d) of Form 10-K for 2551, dated September 1, 1993, between fiscal year ended September 30, Tennessee Gas and Western Kentucky, Harrodsburg 1993 (File No. 1-10042) Service Area
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------------- ---------------------- 10.14(e) Gas Transportation Agreement, Contract No. Exhibit 10.17(e) of Form 10-K for 2548, dated September 1, 1993, between fiscal year ended September 30, Tennessee Gas and Western Kentucky, Lebanon 1993 (File No. 1-10042) Service Area 10.15 Gas Service Agreement (Service for Firm Exhibit 10.5 of Form 10-Q for Transportation) between Energas and Westar quarter ended December 31, 1996 Transmission Company dated January 1, 1996 (File No. 1-10042) 10.16 Gas Service Agreement (Service for Firm Exhibit 10.7 of Form 10-Q for Transportation) between Westar Transmission quarter ended December 31, 1996 Company and EnerMart dated January 1, 1996 (File No. 1-10042) (Irrigation) 10.17 Gas Service Agreement (Service for Firm Exhibit 10.8 of Form 10-Q for Transportation) between KN Westex and Enermart quarter ended December 31, 1996 Trust dated January 1, 1996 (File No. 1-10042) 10.18 Gas Sales Agreement (Irrigation) between KN Exhibit 10.11 of Form 10-Q for Marketing and EnerMart Trust dated March 1, 1996 quarter ended December 31, 1996 (File No. 1-10042) 10.19 Gas Sales Agreement (Swing) between Energas and Exhibit 10.13 of Form 10-Q for KN Marketing, dated January 1, 1996 quarter ended December 31, 1996 (File No. 1-10042) 10.20(a) Operating Agreement between Energas and Westar Exhibit 10.15 of Form 10-Q for Transmission Company, effective December 1, 1996 quarter ended December 31, 1996(File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------------- ---------------------- 10.20(b) Gas Transportation Agreement Service Package Exhibit 10.4 of Form 10-Q for No. 4272 between United Cities Gas Company and quarter ended March 31, 1998(File East Tennessee Natural Gas Company dated No. 1-10042) November 1, 1993 10.20(c) Gas Transportation Agreement Service Package Exhibit 10.5 of Form 10-Q for No. 4219 between United Cities Gas Company and quarter ended March 31, 1998(File Tennessee Gas Pipeline Company dated November No. 1-10042) 1, 1993 10.20(d) Transportation-Storage Contract No. TA-0614 Exhibit 10.6 of Form 10-Q for (Request 0180) between United Cities Gas quarter ended March 31, 1998(File Company and Williams Natural Gas Company dated No. 1-10042) October 1, 1993 10.20(e) Transportation-Storage Contract No. TA-0611 Exhibit 10.7 of Form 10-Q for (Request 0002) between United Cities Gas quarter ended March 31, 1998(File Company and Williams Natural Gas Company dated No. 1-10042) October 1, 1993 10.20(f) Service Agreement No. 867760 Under Rate Exhibit 10.8 of Form 10-Q for Schedule FT between United Cities Gas Company quarter ended March 31, 1998(File and Southern Natural Gas Company dated November No. 1-10042) 1, 1993 10.20(g) Service Agreement No. 867761 Under Rate Exhibit 10.9 of Form 10-Q for Schedule FT-NN between United Cities Gas quarter ended March 31, 1998(File Company and Southern Natural Gas Company dated No. 1-10042) November 1, 1993
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Page Number or Exhibit Incorporation by Number Description Reference to -------- --------------------------------------------- ---------------------- Executive Compensation Plans and Arrangements --------------------------------------------- 10.21(a) *Severance Agreement dated April 1, 1995 Exhibit 10.3 of Form 10-Q for between the Company and J. Charles Goodman quarter ended June 30, 1995 (File No. 1-10042) 10.21(b) *Form of Atmos Energy Corporation Change in Exhibit 10.21(b) of Form 10-K for Control Severance Agreement--Tier I fiscal year ended September 30, 1998 (File No. 1-10042) 10.21(c) *Form of Atmos Energy Corporation Change in Exhibit 10.21(c) of Form 10-K for Control Severance Agreement--Tier II fiscal year ended September 30, 1998 (File No. 1-10042) 10.22(a) *Atmos Energy Corporation Mini-Med Plan, as Exhibit 10.22 of Form 10-K for restated effective July 1, 1996 fiscal year ended September 30, 1996 (File No. 1-10042) 10.22(b) *Amendment No. One to the Atmos Energy Exhibit 10.22(b) of Form 10-K for Corporation Mini-Med Plan fiscal year ended September 30, 1998 (File No. 1-10042) 10.23 *Long Term Stock Plan for the United Cities Gas Exhibit 99.1 of Form S-8 filed Company Division July 29, 1997 (File No. 333-32343) 10.24(a) *Atmos Energy Corporation Retirement Plan for Exhibit 10(y) of Form 10-K for Outside Directors fiscal year ended September 30, 1992 (File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- -------------------------------------------- ------------------------ 10.24(b) *Amendment No. 1 to the Atmos Energy Exhibit 10.2 of Form 10-Q for Corporation Retirement Plan for Outside quarter ended December 31, 1996 Directors (File No. 1-10042) 10.25(a) *Description of Financial and Estate Planning Exhibit 10.25(b) of Form 10-K for Program fiscal year ended September 30, 1997 (File No. 1-10042) 10.25(b) *Description of Sporting Events Program Exhibit 10.26(c) of Form 10-K for fiscal year ended September 30, 1993 (File No. 1-10042) 10.26(a) *Atmos Energy Corporation Supplemental Exhibit 10.26 of Form 10-K for Executive Benefits Plan, Amended and Restated fiscal year ended September 30, in its Entirety August 12, 1998 1998 (File No. 1-10042) 10.26(b) *Atmos Energy Corporation Performance-Based Exhibit 10.32 of Form 10-K for Supplemental Executive Benefits Plan, Effective fiscal year ended September 30, Date August 12, 1998 1998 (File No. 1-10042) 10.27 *Atmos Energy Corporation Restricted Stock Exhibit 10.27 of Form 10-K for Grant Plan (Amended and Restated as of November fiscal year ended Septmeber 30, 12, 1997) 1997 (File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------------- ---------------------- 10.28 *Atmos Energy Corporation Outside Directors Exhibit 10.28 of Form 10-K fiscal Stock-for-Fee Plan (Amended and Restated as of year ended September 30, 1997 November 12, 1997) (File No. 1-10042) 10.29 *Atmos Energy Corporation Executive Exhibit 10.33 of Form 10-K for Nonqualified Deferred Compensation Plan fiscal year ended September 30, 1998 (File No. 1-10042) 10.30(a) *Consulting Agreement between the Company and Exhibit 10.2 of Form 10-Q for Charles K. Vaughan, effective October 1, 1994 quarter ended June 30, 1997 (File No. 1-10042) 10.30(b) *Amendment No.1 to Consulting Agreement between Exhibit 10.3 of Form 10-Q for the Company and Charles K. Vaughan, dated May quarter ended June 30, 1997 (File 14, 1997 No. 1-10042) 10.30(c) *Amendment No. 2 to Consulting Agreement Exhibit 10.30(c) of Form 10-K for between the Company and Charles K. Vaughan, fiscal year ended September 30, dated August 12, 1998 1998 (File No. 1-10042) 10.30(d) *Amendment No. 3 to Consulting Agreement between the Company and Charles K. Vaughan, dated November 10, 1999 10.31(a) *Atmos Energy Corporation Executive Retiree Exhibit 10.31 of Form 10-K for Life Plan fiscal year ended September 30, 1997 (File No. 1-10042)
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Page Number or Exhibit Incorporation by Number Description Reference to -------- --------------------------------------------- ---------------------- 10.31(b) *Amendment No. 1 to The Atmos Energy Exhibit 10.31(a) of Form 10-K for Corporation Executive Retiree Life Plan fiscal year ended September 30, 1997 (File No. 1-10042) 10.32 *Atmos Energy Corporation Equity Incentive and Exhibit 99.1 of Form S-8 filed Deferred Compensation Plan for Non-Employee March 1, 1999 (File No. 333-73145) Directors 11 Not applicable 12 Not applicable 13 Financial Review section of the Company's 1999 Annual Report to Shareholders (with exception of the information incorporated by reference included in Part I and Part II hereof, the 1999 Annual Report to Shareholders is not deemed filed or part of this Form 10-K) 16 Not applicable 18 Not applicable Other Exhibits, as indicated ---------------------------- 21 Subsidiaries of the registrant 22 Not applicable 23 Consent of independent auditor, Ernst & Young LLP
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Page Number or Exhibit Incorporation by Number Description Reference to -------- ----------------------------------------------- ---------------------- 24 Power of Attorney Signature page of Form 10-K for fiscal year ended September 30, 1999 27 Financial Data Schedule for Atmos for year ended September 30, 1999
-------------------------- * This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement." 55 EX-10.10(A) 2 FIRM GAS TRANSPORTATION AGREEMENT NO. 123535 EXHIBIT 10.10(a) FIRM GAS TRANSPORTATION SERVICE AGREEMENT Contract No. 123535 THIS SERVICE AGREEMENT (Agreement), made and entered into as of this 1st day of November, 1998, by and between Public Service Company of Colorado (Company), a Colorado corporation, having a mailing address of P.O. Box 840, Denver, Colorado, 80202, and Greeley Gas Company, a Division of Atmos Energy Corporation (Shipper), a Texas corporation, having a mailing address of 700 Three Lincoln Centre, 5430 LBJ Freeway, P.O. Box 650205, Dallas, Texas 75265- 0205. Company and Shipper are collectively referred to as the "Parties." THE PARTIES REPRESENT: Shipper has by separate agreement acquired supplies of natural gas, hereinafter referred to as "Shipper's Gas;" Shipper has made the necessary arrangements and/or has entered into separate agreements to cause Shipper's Gas to be delivered to Company's Receipt Point(s) as specified in Exhibit(s) "A-1" through "C-2;" Shipper has requested and Company agrees to receive and transport Shipper's Gas from the Receipt Point(s) to the Delivery Point(s), as specified in Exhibit(s) "A-1" through "C-2," on a firm capacity basis and, if applicable, to sell gas to Shipper on a firm supply reservation basis; and Shipper assumes responsibility for the installation and maintenance costs for a communication line necessary for electronic metering for the facility(s) specified in Exhibit(s) "A-1," "B-1" and "C-1." THEREFORE, THE PARTIES AGREE AS FOLLOWS: 1. Shipper acknowledges and agrees that gas transportation service provided hereunder is subject to the terms and conditions of Company's applicable gas transportation tariff as on file and in effect from time to time with the Public Utilities Commission of the State of Colorado (Commission) and such terms and conditions are incorporated herein as part of this Agreement. 2. Rates and Payment: Transportation service, Firm Capacity service and Firm Supply Reservation service provided by - 1 - Company under this Service Agreement shall be paid for by Shipper at the charges under the standard rate set forth in Company's gas transportation tariff unless otherwise specified in Exhibit(s) "A-1" through "C-2." Applicable facility charges shall be paid at the rate set forth in Company's Gas Transportation Tariff unless otherwise specified in Exhibit(s) "A-1" through "C-2." 3. Back-up Supply Sales Service: In the event that adequate supplies of Shipper's gas are not available for receipt by Company, Company shall sell to Shipper sufficient quantity(s) of natural gas as necessary to meet Shipper's backup natural gas supply needs, up to the Total Peak Day Quantity for the Firm Supply Reservation Service (if any) as specified in Exhibit(s) "A-1" through "C- 2," but in no event greater at any Delivery Point than the Firm Capacity Peak Day Quantity at such Delivery Point as specified in Exhibit(s) "A-1" through "C- 2," except as provided for in paragraph 10 hereof. To the extent that the Shipper does not purchase Firm Supply Reservation Service or exceeds the Firm Capacity Peak Day Quantity at any Delivery Point, Company will provide Back-up Supply Sales Service on an interruptible basis, as available. All natural gas sold by Company to Shipper shall be at the Back-up Supply Sales Charge specified in Company's gas transportation tariff. 4. Quality: Gas delivered by the Shipper or for the Shipper's account at the Receipt Point(s) as specified in Exhibit(s) "A-1" through "C-2" shall conform to the specifications for gas as specified in Exhibit "D" and Exhibit "E." 5. Term - Effective Date: This Agreement shall be effective November 1, 1998, and shall continue in full force and effect through April 30, 2003 for all Delivery Points identified in Exhibit "A-1 and A-2", and April 30, 1999 for all Delivery Points identified in Exhibits "B-1", "B-2", "C-1" and "C-2" under this Agreement, and from year to year thereafter until terminated by either party effective upon such Service Termination Date(s) or May 1 of any succeeding year upon thirty (30) days prior written notice. 6. Notices: Except as otherwise provided, any notice or information that either party may desire to give to the other regarding this agreement shall be in writing to the following address, or to such other address as either of the parties shall designate in writing. COMPANY: SHIPPER: Payments Only: Invoices only Public Service Greeley Gas Company, a Division of Company of Colorado - 2 - P.O. Box 17230 Atmos Energy Corporation Denver, Colorado 80217-0230 Attn: Gas Supply Dept (303) 623-1234 P.O. Box 650205 Fax: (303) 294-2136 Dallas, Texas 75265-0205 Phone : (972) 855-3756 Fax: (972) 855-3773 All Others Public Service Greeley Gas Company, a Division of Company of Colorado Seventeenth Street Plaza Atmos Energy Corporation 1225 17th Street, Suite 1100 Attn: Gas Supply Dept Denver, Colorado 80202-5533 P.O. Box 650205 Dallas, Texas 75265-0205 Attn: Unit Manager, Phone: (972) 855-3758 Gas Transportation Phone: (303) 294-8318 Fax: (972) 855-3773 Fax: (303) 294-2757 Routine communications, including monthly statements and payments, shall be considered as duly delivered or furnished three (3) days after being mailed or when transmitted electronically. 7. Assignment - Consent: This Service Agreement shall not be assigned by either party hereto without the prior written consent of the other party. Consent for assignment of this Service Agreement shall not be unreasonably withheld by or from either party. 8. Cancellation of Prior Agreement: This Service Agreement supersedes, cancels and terminates, as of the date of this Service Agreement, the following agreements and any amendments thereto: Gas Transportation Service Agreement, dated 11/1/95 (Document No. 123535), between Greeley Gas Company, a division of Atmos Energy Company and Public Service Company of Colorado 9. Cancellation of this Service Agreement: (a) Shipper may cancel this Service Agreement upon thirty (30) days' written notice. If Receiving Party(s) then chooses to return to full firm natural gas service from Company, Company will, at Receiving Party's request, subject to availability of sufficient volumes of firm natural gas from Company's suppliers, reinstate Receiving Party with full firm service under the appropriate tariffs as they may be filed with the Commission. Shipper shall be responsible for costs, if any, which may be incurred by Company due to such termination. - 3 - (b) In the event Shipper no longer desires Firm Transportation Service and Receiving Party(s) obtains interruptible sales or interruptible transportation service or converts to an alternate fuel prior to the end of the Contract Period or any subsequent Contract Period, Shipper may terminate this Agreement by paying Company a termination charge. The termination charge shall equal the Firm Capacity Charge and the Firm Supply Reservation Charge, if applicable, multiplied by the Receiving Party(s)' Peak Day Quantity(s), as described on Exhibit(s) "A-1" through "C-2," multiplied by the number of months remaining in the Contract Period. The parties agree that Shipper shall owe no termination charge in the event the Agreement is terminated in accordance with paragraph 5 above. (c) Either party shall have the further right to terminate this Agreement if the other party, within ten days following receipt of written notification of a claim of a material breach hereunder, fails to remedy such material breach and to indemnify such party for the consequences thereof. Such termination shall become effective on the eleventh day following such notification or, if the notification provides for a different termination date which is later than the ten-day notification period, on the date specified in such notification. For purposes of this paragraph, "material breach" shall include, but not be limited to, a continuing or repeated failure to perform a basic obligation under this Agreement and shall not include periodic or isolated failures to perform or other liquidated claims which can be resolved pursuant to monetary or volume adjustments. 10. Delivery Point Peak Day Quantity: (a) The Delivery Points reflected in the attached Exhibits "A-1" through "C-2" are interconnections between Company's pipeline system and Shipper's downstream natural gas facilities and the parties recognize the mutual operational benefits of providing for flexibility in coordinating gas flows at each of these Delivery Points. The Peak Day Quantities identified in the attached Exhibits "A-1" through "C-2" represent Shipper's current and best information of Delivery Point peaking volumes. Shipper and Company agree that the parties will reevaluate these volumes on a periodic basis, but at least once annually, to determine if and at what level any adjustments to the individual Delivery Point Peak Day Quantities are needed. (b) On a monthly basis, Company will review the actual deliveries made to these points and, provided the total volumes delivered do not exceed the total contracted-for volume applicable to the corresponding Exhibit area, Company will authorize any volume exceeding the Delivery Point Peak Day Quantity as authorized overrun gas. Should delivered volumes at any Delivery Point consistently exceed the Peak Day Quantity for - 4 - that point, Shipper will request and Company will accept, subject to available capacity, an increase in the contracted-for Peak Day Quantity at the specified Delivery Point. In increasing the contracted volume at a Receipt Point, Shipper may shift volumes from other points within the same Exhibit area if volumes at such other points do not exceed maximum Peak Day Quantities in which case Shipper may request an increase in the overall Contract Maximum Peak Day quantity, as necessary. (c) If, pursuant to any applicable state law or administrative action, order, or regulation Shipper restructures its gas utility services to provide unbundled gas sales and transportation services to some or all of its customers, and such restructuring results in Shipper holding Peak Day Quantities under this Agreement in excess of that required to provide service to the markets served by Shipper using the gas transportation service provided under this Agreement subsequent to such restructuring ("Excess Capacity"), Shipper shall have the right to reduce the Peak Day Quantities hereunder by the quantity of such Excess Capacity to the extent Shipper is unable, through the use of its best efforts, to assign any of such Excess Capacity to third parties or to acquire the necessary regulatory approvals to permit Shipper to recover the costs of such Excess Capacity through its service rates or charges. Any such reduction to the Peak Day Quantities hereunder shall become effective upon the implementation date of Shipper's restructuring of services. If Shipper elects to exercise its right to reduce Peak Day Quantities hereunder pursuant to this subsection, Shipper shall provide Company at least ninety (90) days prior written notice of such election. 11. Maximum Capacity by Exhibit: Administrative circumstances require the separation of electronically metered and non-electronically metered volumes into two separate Exhibits covering the same regional area, as reflected in the attached Exhibit "A-1" Electronically Metered Front Range and Exhibit "A-2" Non- Electronically Metered Front Range, Exhibit "B-1" Electronically Metered Southern and Exhibit "B-2" Non-Electronically Metered Southern, and Exhibit "C- 1" Electronically Metered Western and Exhibit "C-2" Non-Electronically Metered Western. This Agreement is intended to make available firm transportation service up to the maximum contracted volume by Exhibit area, i.e., the Front Range Area (Exhibits "A-1" and "A-2"), the Southern Area (Exhibit "B-1" and "B- 2"), and the Western Area (Exhibits"C-1" and "C-2"). Therefore, in instances where the total delivered volumes under any Electronically Metered or Non- Electronically Metered Exhibit exceed the Maximum Daily Contract quantity for that Exhibit, the parties agree that transportation will be authorized provided available capacity - 5 - exists on the corresponding Electronically Metered or Non-Electronically Metered Exhibit area. 12. For all Delivery Points listed on Exhibits "A-2," "B-2" and "C-2," Shipper will nominate transportation volumes based on a percentage volume provided by Company, therefore, the balancing provisions of Company's Tariff as they would apply to this Agreement are waived. 13. Exhibit(s) and Addendums: All exhibits attached hereto are incorporated into the terms of this Agreement. 14. This Agreement shall be governed by and construed in accordance with the laws of the State of Colorado. IN WITNESS WHEREOF, the parties have executed this Firm Gas Transportation Service Agreement as of the day and year first above written. COMPANY: SHIPPER: PUBLIC SERVICE COMPANY GREELEY GAS COMPANY, A DIVISION OF COLORADO OF ATMOS ENERGY CORPORATION By: By: ------------------------ ------------------------ Title: Title: ------------------------ ------------------------ Taxpayer I.D. No. 84-0296600 Taxpayer I.D. No. - 6 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN GREELEY GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) - -------------------------------------------------------------------------------- Receipt Point Peak Day Quantity Utilization Curve Dth/Day - -------------------------------------------------------------------------------- Chalk Bluffs 39,868 General - -------------------------------------------------------------------------------- CIG Ft. Lupton 797 General - -------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - --------------------------------------------------------------------------------------------------------------------------- Ault #1 & #2 306412692 800 1st meter $185 see below 11/1/98 08/26/90 11/1/98 4/30/2003 - --------------------------------------------------------------------------------------------------------------------------- Eaton #1 & #2 206412763 500 addt'l $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - --------------------------------------------------------------------------------------------------------------------------- Kersey Group 706412713 1,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - --------------------------------------------------------------------------------------------------------------------------- Lasalle 406412719 900 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - --------------------------------------------------------------------------------------------------------------------------- Lucerne #1 606412723 200 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - ---------------------------------------------------------------------------------------------------------------------------
- 7 - - --------------------------------------------------------------------------------------------------------------------------- Monfort Meas 706412727 500 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 Statn. meter - --------------------------------------------------------------------------------------------------------------------------- North Greeley 106412730 14,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - --------------------------------------------------------------------------------------------------------------------------- Platteville 906412745 1000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - --------------------------------------------------------------------------------------------------------------------------- South Greeley 106412754 2,000 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - ---------------------------------------------------------------------------------------------------------------------------
- 8 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE (cont'd.) 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S) continued
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - --------------------------------------------------------------------------------------------------------------------------- West Greeley 606412761 18,715 addt'l. $125 see below 11/1/98 08/26/90 11/1/98 4/30/2003 meter - -------------------------------------------------------------------------------------------------------------------------- CIG/PSCo n/a 8,000 n/a n/a see below 11/1/98 06/01/98 11/1/98 5/31/2003 inter- connects - --------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 39,615Dth 3. FIRM SUPPLY RESERVATION SERVICE Front Range Effective Date Termination Date Peak Day Quantity Of Service Of Service Dth/Day - --------------------------------------------------------------------- 3,005 6/1/98 4/30/2003 - --------------------------------------------------------------------- Total Firm Supply Reservation Quantity available for delivery to all of Shipper's Delivery Points as may be nominated from time to time under contract numbers 123535 and 177473: 3,005 Dth Rates for Firm Transportation Service: Unless otherwise specified as provided below, the Transportation Commodity Charge for services hereunder for all quantities nominated by Shipper and delivered by Company to the Delivery Points identified above shall be $.05/Dth inclusive of any Demand Side Management Charges and General Rate Schedule Adjustments, plus additional surcharges for reimbursement of applicable taxes, franchise fees and Fuel Reimbursement. The parties further agree that the percentage for Fuel Reimbursement to be retained by Company for deliveries made to Front - 9 - Range Delivery Points from PSCo to Shipper under the above referenced agreements shall be 2%, with 0% fuel deductions for deliveries made by PSCo to CIG Delivery Points. The Transportation Commodity Charge provided above shall continue in effect from November 1, 1998 through April 30, 2003, or in the case of the CIG Delivery Points, May 31, 2003, unless a revised - 10 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-1" ELECTRONICALLY METERED FRONT RANGE (cont'd.) discounted or minimum Transportation Commodity Charge applicable to service hereunder is ordered by the Commission or the Commission issues an order in a rate proceeding which specifically disallows the Company's proposed recovery in its jurisdictional rates of the revenue requirement attributable to the difference between the Transportation Commodity Charge provided above and the applicable Maximum Transportation Commodity Charge set forth in Company's tariff, either through a discount adjustment on transportation throughput or other method of rate recovery. If a revised discounted or minimum Transportation Commodity Charge applicable to service hereunder is ordered by the Commission or the Commission issues an order in a rate proceeding disallowing the Company's proposed recovery of the revenue requirement attributable to the discount provided hereunder, the parties shall have 30 days after the date of such to attempt to adjust other components of such total charge so that there will be no increase in such total charge paid by Shipper hereunder. If the parties are unable to make any adjustment within the then existing Commission orders and there is an increase in such total charge paid by Shipper, Shipper shall pay the increased rate required by the Commission but shall have the right to terminate this Agreement at any time and, notwithstanding anything contained herein to the contrary, without any termination or other charge, thereafter upon 30 days prior written notice to Company. Upon the expiration of the term of the discounted Transportation Commodity Charge, as specified herein, the Transportation Commodity Charge shall automatically revert to the full Standard Rate as applicable under Company's then-effective Gas Transportation Tariff, as approved and on file with the Commission. A minimum of ninety days prior to April 30, 2003, Shipper may request a price redetermination for the discounted rate provided above. The parties shall endeavor to reach a mutually agreeable rate prior to May 1, 2003 to be effective prospectively thereafter. If no such redetermined rate can be agreed upon, either party may terminate this Agreement effective May 1, 2003, or any subsequent annual term thereafter. - 11 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN GREELEY GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) - ------------------------------------------------------------------------------- Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ------------------------------------------------------------------------------- Chalk Bluffs 4,370 General - ------------------------------------------------------------------------------- CIG Ft Lupton 87 General - ------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - -------------------------------------------------------------------------------------------------------------------------- Corsey Group 906412694 20 1st meter $185 same as 11/1/98 08/26/90 11/1/98 9/30/2003 Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- East 606412695 50 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 Keenesburg meter Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- Gilcrest 506412766 425 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- Hill-N-Park 206412697 360 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - --------------------------------------------------------------------------------------------------------------------------
- 12 - - -------------------------------------------------------------------------------------------------------------------------- Hudson 406412700 375 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- Keenesburg 306412710 340 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- Nunn 206412739 175 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - --------------------------------------------------------------------------------------------------------------------------
- 13 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE (cont'd.) 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - -------------------------------------------------------------------------------------------------------------------------- Pierce 606412742 400 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------- Roggen 706412751 70 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - ------------------------------------------------------------------------------------------------------------------------- South Gate 106412768 50 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 Trailer meter Exh. A-1 - ------------------------------------------------------------------------------------------------------------------------- South Roggen 106412773 15 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - ------------------------------------------------------------------------------------------------------------------------- West Hudson 306412705 300 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 meter Exh. A-1 - ------------------------------------------------------------------------------------------------------------------------- West 506412771 35 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 LaSalle meter Exh. A-1 Group - ------------------------------------------------------------------------------------------------------------------------- Prospect 306412748 55 addt'l. $125 same as 11/1/98 08/26/90 11/1/98 9/30/2003 Valley meter Exh. A-1 - ------------------------------------------------------------------------------------------------------------------------- Misc. Farm 1,700 same as 11/1/98 08/26/90 11/1/98 9/30/2003 Taps Exh. A-1 - -------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 4,370 Dth Rates for Firm Transportation Service: - 14 - Unless otherwise specified as provided below, the Transportation Commodity Charge for services hereunder for all quantities nominated by Shipper and delivered by Company to the Delivery Points identified above shall be $.05/Dth inclusive of any Demand Side Management Charges and General Rate Schedule Adjustments, plus additional surcharges for reimbursement of applicable taxes, franchise fees and Fuel Reimbursement. The parties further agree that the percentage for Fuel Reimbursement to be retained by Company for deliveries made to Front Range Delivery Points under the above referenced agreements shall be 2%. - 15 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE (cont'd.) The Transportation Commodity Charge provided above shall continue in effect from November 1, 1998 through April 30, 2003, unless a revised discounted or minimum Transportation Commodity Charge applicable to service hereunder is ordered by the Commission or the Commission issues an order in a rate proceeding which specifically disallows the Company's proposed recovery in its jurisdictional rates of the revenue requirement attributable to the difference between the Transportation Commodity Charge provided above and the applicable Maximum Transportation Commodity Charge set forth in Company's tariff, either through a discount adjustment on transportation throughput or other method of rate recovery. If a revised discounted or minimum Transportation Commodity Charge applicable to service hereunder is ordered by the Commission or the Commission issues an order in a rate proceeding disallowing the Company's proposed recovery of the revenue requirement attributable to the discount provided hereunder, the parties shall have 30 days after the date of such to attempt to adjust other components of such total charge so that there will be no increase in such total charge paid by Shipper hereunder. If the parties are unable to make any adjustment within the then existing Commission orders and there is an increase in such total charge paid by Shipper, Shipper shall pay the increased rate required by the Commission but shall have the right to terminate this Agreement at any time and, notwithstanding anything contained herein to the contrary, without any termination or other charge, thereafter upon 30 days prior written notice to Company. Upon the expiration of the term of the discounted Transportation Commodity Charge, as specified herein, the Transportation Commodity Charge shall automatically revert to the full Standard Rate as applicable under Company's then-effective Gas Transportation Tariff, as approved and on file with the Commission. A minimum of ninety days prior to April 30, 2003, Shipper may request a price redetermination for the discounted rate provided above. The parties shall endeavor to reach a mutually agreeable rate prior to May 1, 2003 to be effective prospectively thereafter. If no such redetermined rate can be agreed upon, either party may terminate this Agreement effective May 1, 2003, or any subsequent annual term thereafter. - 16 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "B-1" ELECTRONICALLY METERED SOUTHERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN GREELEY GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) - -------------------------------------------------------------------------------- Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - -------------------------------------------------------------------------------- Outlet of Tiffany Compressor 6,500 Stabilized Station - -------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - -------------------------------------------------------------------------------------------------------------------------- Crested 406412639 700 addt'l $125 TF 1yr. 11/28/90 11/1/98 4/30/99 Butte Town meter Border Station - -------------------------------------------------------------------------------------------------------------------------- East 306412687 2,500 addt'l $125 TF 1yr. 05/06/87 11/1/98 4/30/99 Gunnison meter Town Border Station - -------------------------------------------------------------------------------------------------------------------------- Salida Town 206412701 2,600 addt'l $125 TF 1yr. 05/06/87 11/1/98 4/30/99 Border meter Station - ------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 5,800 Dth - 17 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "B-2" NON-ELECTRONICALLY METERED SOUTHERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN GREELEY GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) - -------------------------------------------------------------------------------- Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - -------------------------------------------------------------------------------- Outlet of Tiffany Compressor 1,115 Stabilized Station - -------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - --------------------------------------------------------------------------------------------------------------------------- Poncha 706412690 100 addt'l. $125 TF 1yr. 11/28/90 11/1/98 4/30/99 Springs meter - --------------------------------------------------------------------------------------------------------------------------- Chalk Creek 206412678 85 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99 meter - --------------------------------------------------------------------------------------------------------------------------- Tomichi 106412706 40 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99 Village meter - --------------------------------------------------------------------------------------------------------------------------- West 906412707 375 addt'l. $125 TF 1yr. 05/06/87 11/1/98 4/30/99 Gunnison meter Town Border - ---------------------------------------------------------------------------------------------------------------------------
- 18 - - --------------------------------------------------------------------------------------------------------------------------- Misc. Farm 800 TF 1yr. 05/06/87 11/1/98 4/30/99 Taps - ---------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 1,400 Dth - 19 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "C-1" ELECTRONICALLY METERED WESTERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN GREELEY GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) - ------------------------------------------------------------------------------- Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ------------------------------------------------------------------------------- KNGWRD 680 General - ------------------------------------------------------------------------------- MOFRRO 575 General - ------------------------------------------------------------------------------- LONGCA 266 General - ------------------------------------------------------------------------------- NF1GCA 1,770 General - ------------------------------------------------------------------------------- NF1GHC 3,540 General - ------------------------------------------------------------------------------- NF2GCA 3,540 General - ------------------------------------------------------------------------------- ROSGCA 89 General - ------------------------------------------------------------------------------- TERGCA 22 General - ------------------------------------------------------------------------------- TWIGCA 66 General - ------------------------------------------------------------------------------- CIG Ft Lupton General - ------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - --------------------------------------------------------------------------------------------------------------------------- Craig 206412744 4,648 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99 meter - --------------------------------------------------------------------------------------------------------------------------- Meeker 706413010 1,000 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99 meter - ---------------------------------------------------------------------------------------------------------------------------
- 20 - - ------------------------------------------------------------------------------------------------------------------------- Hayden TBS 506412747 2,600 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99 meter - -------------------------------------------------------------------------------------------------------------------------- Mt. Werner 506412752 2,600 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99 #1 meter - -------------------------------------------------------------------------------------------------------------------------- Steamboat 306412772 1,215 addt'l $125 TF 1yr. 10/20/86 11/1/98 4/30/99 TBS meter - --------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 10,163 Dth - 21 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "C-2" NON-ELECTRONICALLY METERED WESTERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND GREELEY GAS COMPANY, A DIVISION OF PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S) Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - -------------------------------------------------------------------------------- KNGWRD 88 General - -------------------------------------------------------------------------------- MOFRRO 75 General - -------------------------------------------------------------------------------- LONGCA 34 General - -------------------------------------------------------------------------------- NF1GCA 230 General - -------------------------------------------------------------------------------- NF1GHC 460 General - -------------------------------------------------------------------------------- NF2GCA 460 General - -------------------------------------------------------------------------------- ROSGCA 11 General - -------------------------------------------------------------------------------- TERGCA 3 General - -------------------------------------------------------------------------------- TWIGCA 9 General - -------------------------------------------------------------------------------- CIG Ft Lupton General - -------------------------------------------------------------------------------- 2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Service Transport- Effective Capacity and Specific ation Date Of Date Termination Delivery Peak Day Facility Facility Commodity Term of First of of Service Point(s) Load Point Quantity Charge Charge Charge Rate Delivery Service Date (Dth) - --------------------------------------------------------------------------------------------------------------------------- Thompson 406412762 45 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99 Hill meter - --------------------------------------------------------------------------------------------------------------------------- Milner 106412749 65 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99 Town Brder meter - --------------------------------------------------------------------------------------------------------------------------
- 22 - - --------------------------------------------------------------------------------------------------------------------------- Steamboat 206412758 200 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99 II West meter - --------------------------------------------------------------------------------------------------------------------------- Brooklyn 606412737 627 addt'l. $125 TF 1yr. 10/20/86 11/1/98 4/30/99 Group meter - --------------------------------------------------------------------------------------------------------------------------- Misc. Farm 1,233 TF 1yr. 10/20/86 11/1/98 4/30/99 Taps - ---------------------------------------------------------------------------------------------------------------------------
Total Firm Capacity Reservation Peak Day Quantity: 2,170 Dth - 23 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "D" GAS UTILIZATION CURVES Stabilized Utilization Curve [Public Service Company of Colorado Stabilized Utilization Curve Graph appears here] The Utilization Curve is a general representation of the natural gas quality which is acceptable from a utilization standpoint. However, the gas composition must be known in order to determine if a supply is acceptable and can be interchanged with supplies in a pipeline system. PSCo reserves the right in all instances to evaluate gas composition to determine system compatibility and to refuse any gas which is unacceptable from a utilization basis. - 24 - Contract No.: 123535 Effective Date Of Agreement: 11/01/98 Effective Date of Exhibit: 11/01/98 EXHIBIT "E" GAS UTILIZATION CURVES General Utilization Curve [Public Service Company of Colorado Stabilized Utilization Curve Graph appears here] The Utilization Curve is a general representation of the natural gas quality which is acceptable from a utilization standpoint. However, the gas composition must be known in order to determine if a supply is acceptable and can be interchanged with supplies in a pipeline system. PSCo reserves the right in all instances to evaluate gas composition to determine system compatibility and to refuse any gas which is unacceptable from a utilization basis. - 25 - EX-10.10(D) 3 FIRM TRANSPORTATION SERVICE AGREEMENT NO. 33181A Exhibit 10.10(d) Firm Transportation Service Agreement Contract No. 33181000A Rate Schedule TF-1 between Colorado Interstate Gas Company and Greeley Gas Company, a division of Atmos Energy Corporation Dated: July 1, 1998 Page 2 FIRM TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-1 The Parties identified below, in consideration of their mutual promises, agree as follows: 1. Transporter: Colorado Interstate Gas Company 2. Shipper: Greeley Gas Company, a division of Atmos Energy Corporation 3. Applicable Tariff: Transporter's FERC Gas Tariff, First Revised Volume No. 1, as the same may be amended or superseded from time to time ("the Tariff"). 4. Changes in Rates and Terms: Transporter shall have the right to propose to the FERC changes in its rates and terms of service, and this Agreement shall be deemed to include any changes which are made effective pursuant to FERC Order or regulation or provisions of law, without prejudice to Shipper's right to protest the same. 5. Transportation Service: Transportation Service at and between Primary Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm basis. Receipt and Delivery of quantities at Secondary Point(s) of Receipt and/or Secondary Point(s) of Delivery shall be in accordance with the Tariff. 6. Points of Receipt and Delivery: Shipper agrees to Tender gas for Transportation Service, and Transporter agrees to accept Receipt Quantities at the Primary Point(s) of Receipt identified in Exhibit "A." Transporter agrees to provide Transportation Service and Deliver gas to Shipper (or for Shipper's account) at the Primary Point(s) of Delivery identified in Exhibit "A." 7. Rates and Surcharges: As set forth in Exhibit "B." 8. Negotiated Rate Agreement: N/A 9. Maximum Delivery Quantity ("MDQ"): November through March - 0 Dth per Day April, May, September, October - 1,836 Dth per Day June through August - 3,979 Dth per Day 10. Term of Agreement: Beginning: July 1, 1998 Extending through: September 30, 2000 11. Notices, Statements, and Bills: To Shipper: Invoices for Transportation: Page 3 Greeley Gas Company, a division of Atmos Energy Corporation P.O. Box 650205 Dallas, Texas 75265-0205 Attention: Gas Supply Department All Notices: Greeley Gas Company, a division of Atmos Energy Corporation P.O. Box 650205 Dallas, Texas 75265-0205 Attention: John Hack To Transporter: See Payments, Notices, Nominations, and Points of Contact sheets in the Tariff. 12. Supersedes and cancels prior Agreement: When this Agreement becomes effective, it shall supersede and cancel the following agreement between the Parties: The Firm Transportation Service Agreement between Transporter and Shipper dated October 1, 1997, referred to as Transporter's Agreement No. 33181000. 13. Adjustment to Rate Schedule TF-1 and/or General Terms and Conditions: N/A 14. Incorporation by Reference: This Agreement in all respects shall be subject to the provisions of Rate Schedule TF-1 and to the applicable provisions of the General Terms and Conditions of the Tariff as filed with, and made effective by, the FERC as same may change from time to time (and as they may be amended pursuant to Section 13 of the Agreement). IN WITNESS WHEREOF, the parties hereto have executed this Agreement. Transporter: Shipper: Colorado Interstate Gas Company Greeley Gas Company, a division of Atmos Energy Corporation By By ------------------------- ------------------------- Thomas L. Price Vice President ---------------------------- (Print or type name) ---------------------------- (Print or type title) Page 4 EXHIBIT "A" Firm Transportation Service Agreement between Colorado Interstate Gas Company and Greeley Gas Company, a division of Atmos Energy Corporation Dated: July 1, 1998 1. Shipper's Maximum Delivery Quantity ("MDQ") for the following months shall be as follows: November - March 0 Dth per Day April, May, September, October 1,836 Dth per Day June - August 3,979 Dth per Day
Primary Point(s) of Receipt Quantity (Dth per Day) (Note 2) -------- --------- Primary Point(s) of Receipt April, Maximum of Receipt November May, June Receipt (Note 1) through September through Pressure March October August p.s.i.g. - ------------------------- -------- --------- ------- -------- Central System Lakin Master Meter 0 1,037 2,228 220 ------ ------- ------- Southern System Big Canyon 0 224 491 955(4) Mocane 0 575 1,260 65 ------ ------- ------- Total Southern System 0 799 1,751 ------ ------- ------- TOTAL 0 1,836 3,979 ------ ------- -------
Page 5
Primary Point(s) of Delivery Quantity (Dth per Day) (Note 3) -------- ---------- April, Maximum November May, June Delivery Primary Point(s) of Delivery through September, through Pressure (Note 1) March October August p.s.i.g. - ------------------------- -------- ---------- ------- ---------- Canon City Group (Note 5) Canon City 0 1,269 2,750 (Note 6) Colorado State Penitentiary 0 89 194 100 Engineering Station 476+78 0 1 3 Line Pressure Florence City Gate 0 297 643 60 Fremont County Industrial Park 0 3 6 Line Pressure Penrose City Gate 0 40 88 60 Penrose PBS-2 0 39 84 Line Pressure Portland City Gate 0 10 23 100 Pritchett City Gate 0 10 23 150 ------ ------- ----- Total Canon City Group 0 1,758 3,814 ------ ------- ----- Total Capacity Release 0 1,445 3,130 ------ ------- ----- Eads Group Brandon Station 8 18 350 Eads City Gate 0 62 135 60 Highline Taps: Neoplan (Bent County) 0 1 2 Line Pressure Penrose South (Fremont County) 0 3 7 Line Pressure L.J. Stafford (Baca County) 0 1 3 Line Pressure ------ ------- ----- Total Eads Group 0 76 167 ------ ------- ----- McClave Delivery 0 105 227 500 ------ ------- ----- Springfield 0 210 455 Line Pressure ------ ------- ----- TOTAL 0 1,836 3,979 ------ ------- ----- Storage Injection 0 799 1,100 N/A
Page 6 NOTES: (1) Information regarding Point(s) of Receipt and Point(s) of Delivery, including legal descriptions, measuring parties, and interconnecting parties, shall be posted on Transporter's electronic bulletin board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. (2) Each Point of Receipt Quantity may be increased by an amount equal to Transporter's Fuel Reimbursement percentage. Shipper shall be responsible for providing such Fuel Reimbursement at each Point of Receipt on a pro rata basis based on the quantities received on any Day at a Point of Receipt divided by the total quantity Delivered at all Point(s) of Delivery under this Transportation Service Agreement. (3) The sum of the Delivery Quantities at Point(s) of Delivery shall be equal to or less than Shipper's MDQ. (4) Minimum pressure Shipper will deliver gas to Transporter is 350 p.s.i.g. (5) For Capacity Release purposes, the aggregate of the Canon City Group Point of Delivery Quantities is as designated (e.g., 1,445 Dth per Day April, May, September, October). To the extent that Shipper is not utilizing a portion of its remaining Point of Delivery Quantities at non-Canon City Group Points of Delivery, Shipper may nominate up to the Canon City Group total (e.g., 1,758 Dth per Day April, May, September, October), provided that volumes Tendered by Shipper under this Agreement do not exceed the monthly MDQ (e.g., 1,836 Dth per Day April, May, September, October) unless an Authorized Overrun has been granted to Shipper by Transporter. (6) Line pressure but not less than 100 p.s.i.g. Page 7 EXHIBIT "B" Firm Transportation Service Agreement between Colorado Interstate Gas Company and Greeley Gas Company, a division of Atmos Energy Corporation Dated: July 1, 1998
Primary Primary R1 Point(s) Points of Reservation Commodity Term of Fuel of Receipt Delivery Rate Rate Rate Reimbursement Surcharges - ---------- ----------- ----------- --------- ------- ------------- ---------- As listed As listed on $1.46 (Notes 1 Through (Note 2) (Note 3) on Exhibit on Exhibit and 4) 9/30/00 "A" "A" Secondary Point(s) Primary R1 of Point(s) of Reservation Commodity Term of Fuel Receipt Delivery Rate Rate Rate Reimbursement Surcharges - ---------- ----------- ----------- --------- ------- ------------- ---------- All As listed on $1.46 (Notes 1 Through (Note 2) (Note 3) Exhibit "A" and 4) 9/30/00 Secondary Secondary R1 Point(s) Point(s) of Reservation Commodity Term Fuel of Receipt Delivery Rate Rate of Rate Reimbursement Surcharges - ---------- ----------- ----------- --------- ------- ------------- ---------- All All (Note 1) (Note 1) Through (Note 2) (Note 3) 9/30/00
Page 8 EXHIBIT "B" NOTES: (1) Unless otherwise agreed by the Parties in writing, the rates for service hereunder shall be Transporter's maximum rates for service under Rate Schedule TF-1 or other superseding Rate Schedules, as such rates may be changed from time to time. (2) Fuel Reimbursement shall be as stated on Transporter's Schedule of Surcharges and Fees in the Tariff, as they may be changed from time to time, unless otherwise agreed between the Parties. (3) Surcharges, If Applicable: All applicable surcharges, unless otherwise specified, shall be the maximum surcharge rate as stated in the Schedule of Surcharges and Fees in The Tariff, as such surcharges may be changed from time to time. GQC: The Gas Quality Control Surcharge shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in The Tariff. GRI: The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms and Conditions as set forth in The Tariff. HFS: The Hourly Flexibility Surcharge shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in The Tariff. Order No. 636 Transition Cost Mechanism: Surcharge(s) shall be assessed pursuant to Article 21 of the General Terms and Conditions as set forth in The Tariff. ACA: The ACA Surcharge shall be assessed pursuant to Article 19 of the General Terms and Conditions as set forth in The Tariff. (4) The Authorized Overrun Rate charged by Transporter shall be determined pursuant to the Stipulation and Agreement in Docket No. RP96-190, when applicable, while such Settlement is in effect. EX-10.30(D) 4 AMDMT NO. 3 TO CHARLES K. VAUGHAN CONSULTING AGRMT Exhibit 10.30(d) AMENDMENT NO. 3 TO CONSULTING AGREEMENT THIS AMENDMENT NO. 3 TO CONSULTING AGREEMENT (the "Amendment") is made and entered into this 10th day of November, 1999, by and between ATMOS ENERGY CORPORATION, a Texas and Virginia corporation (the "Company"), and CHARLES K. VAUGHAN ("Consultant"). WHEREAS, the Company and Consultant entered into that certain Consulting Agreement dated October 1, 1994, as amended by Amendment No. 1 to Consulting Agreement dated May 14, 1997 and Amendment No. 2 to Consulting Agreement dated August 12, 1998 (the "Agreement"); and WHEREAS, the Company and Consultant desire to amend the Agreement as set forth below and to extend the term thereof for an additional one-year period; NOW THEREFORE, for and in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows: 1. Paragraph 5 of the Agreement shall be deleted and replaced in its entirety by the following: 5.1. Change in Control. Upon a "Change in Control" of the Company, all sums payable to Consultant over the course of the term of this Agreement shall instead be paid by Company to Consultant within ten days of a "Change in Control". A "Change in Control" of the Company shall be deemed to have occurred if: (a) Any "Person" (as defined in Section 5.2(a) below), other than (1) the Company or any of its subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding securities pursuant to an offering of such securities, or (4) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company, is or becomes the "beneficial owner" (as defined in Section 5.2(b) below), directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such person any securities acquired directly from the Company or its Affiliates) representing 33 1/3% or more of the combined voting power of the Company's then outstanding securities, or 33 1/3% or more of the then outstanding common stock of the Company, excluding any Person who becomes such a beneficial owner in connection with a transaction described in subparagraph (c)(1) below. (b) During any period of two consecutive years (the "Period"), individuals who at the beginning of the Period constitute the Board of Directors of the Company and any "new director" (as defined in Section 5.2(c) below) cease for any reason to constitute a majority of the Board of Directors. (c) There is consummated a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any other corporation, except if: (1) the merger or consolidation would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation; or (2) the merger or consolidation is effected to implement a recapitalization of the Company (or similar transaction) in which no Person is or becomes the beneficial owner, directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business) representing 60% or more of the combined voting power of the Company's then outstanding securities; (d) The shareholders of the Company approve a plan of complete liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company of all or substantially all the Company's assets, other than a sale or disposition by the Company of all or substantially all of the Company's assets to an entity, at least 60% of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale. 5.2. Definitions. For purposes of Section 5.1 above, (a) "Person" shall have the meaning given in Section 3(a)(9) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") as modified and used in Sections 13(d) and 14(d) of the Exchange Act. (b) "Beneficial owner" shall have the meaning provided in Rule 13d-3 under the Exchange Act. (c) "New director" shall mean an individual whose election by the Company's Board of Directors or nomination for election by the Company's shareholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of the Period or whose election or nomination for election was previously so approved or recommended. However, "new director" shall not include a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation relating to the election of directors of the Company. (d) "Affiliate" shall have the meaning set forth in Rule 12b-2 promulgated under Section 12 of the Exchange Act. 2. Extension of Term. In accordance with Subparagraph 4(a) of the Agreement, the Company and the Consultant hereby agree to extend the term of the Agreement for an additional one- year period commencing on October 1, 2000 and ending September 30, 2001. The Consultant's annual compensation during such year shall be $130,000 to be paid in equal semi-annual installments on October 1, 2000 and April 1, 2001. 3. No Other Amendment. Except as expressly amended hereby, all of the other terms, provisions, and conditions of the Agreement are hereby ratified and confirmed and shall remain unchanged and in full force and effect. To the extent any terms or provisions of this Amendment conflict with those of the Agreement, the terms and provisions of the Agreement shall control. This Amendment shall be deemed a part of, and is hereby incorporated into the Agreement. The Agreement and any and all other documents heretofore, now, or hereafter executed and delivered pursuant to the terms of the Agreement are hereby amended so that any reference to the Agreement shall mean a reference to the Agreement as amended hereby. 4. Governing Law. This Amendment shall be governed by, and construed in accordance with, the laws of the State of Texas. 5. Counterparts. This Amendment may be executed in counterparts, each of which will be an original, but all of which together will constitute one and the same agreement. IN WITNESS WHEREOF, the parties hereto have executed this Amendment effective as of the date and year first above written. COMPANY ATMOS ENERGY CORPORATION By: /s/ ROBERT W. BEST --------------------------------- Robert W. Best Chairman, President and Chief Executive Officer CONSULTANT /s/ CHARLES K. VAUGHAN ------------------------------------- CHARLES K. VAUGHAN EX-13 5 FINANCIAL REVIEW SECTION - 1999 ANNUAL REPORT EXHIBIT 13 ---------- ATMOS ENERGY CORPORATION 1999 ANNUAL REPORT FINANCIAL REVIEW Page no. Selected financial data 2 Market price of common stock and related matters 3 Management's discussion and analysis of financial condition and results of operations 4 Management's responsibility for financial statements 33 Report of independent auditors 34 Consolidated balance sheets 35 Consolidated statements of income 37 Consolidated statements of shareholders' equity 38 Consolidated statements of cash flows 40 Notes to consolidated financial statements 42 1 SELECTED FINANCIAL DATA The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein. Year ended September 30, -------------------------------------------------------- 1999 1998 1997 1996 1995 ========== ========== ========== ========== ======== (In thousands, except per share data) Operating revenues $ 690,196 $ 848,208 $ 906,835 $ 886,691 $749,555 ========== ========== ========== ========== ======== Net income $ 17,744 $ 55,265 $ 23,838 $ 41,151 $ 28,808 ========== ========== ========== ========== ======== Diluted net income per share $ .58 $ 1.84 $ .81 $ 1.42 $ 1.06 ========== ========== ========== ========== ======== Cash dividends per share $ 1.10 $ 1.06 $ 1.01 $ .98 $ .96 ========== ========== ========== ========== ======== Total assets at end of year $1,230,537 $1,141,390 $1,088,311 $1,010,610 $900,948 ========== ========== ========== ========== ======== Long-term debt at end of year $ 377,483 $ 398,548 $ 302,981 $ 276,162 $294,463 ========== ========== ========== ========== ======== 2 MARKET PRICE OF COMMON STOCK AND RELATED MATTERS The Company's stock trades on the New York Stock Exchange under the trading symbol "ATO". The high and low sale prices and dividends paid per share of the Company's common stock for fiscal 1999 and 1998 are listed below. The high and low prices listed are the actual closing NYSE quotes for Atmos shares. Fiscal year 1999 --------------------------------------- Dividends High Low paid Quarter ended: --------- --------- --------- December 31 $32 1/4 $28 3/8 $.275 March 31 32 11/16 23 1/16 .275 June 30 26 5/16 24 .275 September 30 26 3/8 23 7/8 .275 ----- $1.10 ===== Fiscal year 1998 --------------------------------------- Dividends High Low paid Quarter ended: --------- --------- --------- December 31 $30 7/16 $24 5/8 $.265 March 31 30 5/16 26 5/16 .265 June 30 31 1/16 28 13/16 .265 September 30 30 7/8 25 3/4 .265 ----- $1.06 ===== See Note 4 of notes to consolidated financial statements for restriction on payment of dividends. The number of record holders of the Company's common stock on September 30, 1999 was 35,179. 3 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction This section provides management's discussion of Atmos Energy Corporation's (the "Company" or "Atmos") financial condition, cash flows and results of operations with specific information on liquidity, capital resources and results of operations. It includes management's interpretation of such financial results, the factors affecting these results, the major factors expected to affect future operating results, and future investment and financing plans. This discussion should be read in conjunction with the Company's consolidated financial statements and notes thereto. Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995 The matters discussed or incorporated by reference in this Annual Report may contain "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the notes to consolidated financial statements, regarding the Company's financial position, business strategy and plans and objectives of management of the Company for future operations, are forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report or in any of the Company's other documents or oral presentations, the words "anticipate," "expect," "estimate," "plans," "believes," "objective," "forecast," "goal" or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to the Company's operations, markets, services, rates, recovery of costs, availability of gas supply, and other factors. These risks and uncertainties include, but are not limited to, national, regional and local economic and competitive conditions, regulatory and business trends and decisions, technological developments, Year 2000 issues, inflation rates, weather conditions, and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. 4 Accordingly, while the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will be realized or will approximate actual results. Year 2000 Readiness The Year 2000 issues arose because many computer systems and software applications, as well as embedded computer chips in plant and equipment currently in use, were constructed using an abbreviated date field that eliminates the first two digits of the year. On January 1, 2000, these systems, applications and embedded computer chips may incorrectly recognize the date as January 1, 1900. Accordingly, many computer systems and software applications, as well as embedded chips, may incorrectly process financial and operating information or fail to process such information completely. The Company has been aware of these issues and has continued to address their potential effects on its computer systems, software applications and plant and equipment. State of readiness. In October 1996, the Company established its Year 2000 Project Team with the mission of ensuring that all critical systems, facilities and processes are identified, analyzed for Year 2000 readiness, corrected if necessary, and tested if changes are necessary. The Year 2000 Project Team is headed by an officer of the Company and consists of representatives from all business units and shared services units of the Company. The Company has a Year 2000 strategy in place and has continued to implement its Year 2000 plan to manage and minimize risks associated with the Year 2000 issues. The Company also received comprehensive assessments in April and July 1999, updating an earlier assessment completed in June 1998, by an independent consulting firm, which specializes in such matters, of the risks posed for the Company and its business units by the Year 2000 issues, including assessments of the risks in each area of the Company involving the use of computer technology and assessments of the business and legal risks created for the Company by the Year 2000 issues. Such assessments also addressed the risks associated with the Company's embedded technologies such as micro-controllers or microchips embedded in non-information technology-related equipment. With respect to information technology ("IT") systems, the Company has conducted an inventory and review of its application software on all platforms including the mainframe, H-P Unix, local area network and personal computers and has remediated 5 Year 2000 issues relating to such operating environments. Concerning non-IT systems, including embedded technology, the Company has conducted an inventory and review of all of its telecommunications, security access and building control systems, forms, reports and other business processes and activities as well as the equipment and facilities utilized in the Company's gas distribution and storage systems and has remediated all Year 2000 issues identified. The Company's Year 2000 plan includes specific timetables for the following categories of tasks for each of its shared services units and business units with respect to both IT systems and embedded technology as follows: - Identification of Year 2000 issues--completed; - Prioritization of Year 2000 issues--completed; - Estimation of total Year 2000-related costs--completed; - Implementation of Year 2000 solutions--completed; - Testing of Year 2000 solutions--completed; - Certification of Year 2000 readiness by third party vendors and suppliers-- completed; - Monitoring of all systems for changes in current systems that would require changes in Year 2000 plan--completed; - Development of Year 2000 contingency plans--completed; - Final Year 2000 tests--began October 1, 1999, and ongoing, including the Clean Management Program. The Company has also conducted an inventory and review of mission critical computer systems provided by outside vendors and has contacted all major vendors to coordinate their Year 2000 readiness schedules with those of the Company. The Company has required vendors who provide mission critical goods or services to submit to the Company their readiness plans and to certify readiness in order to continue to do business with the Company. As discussed above, the Company has also tested vendor products that provide mission critical goods or services to ensure their Year 2000 readiness. In addition, the Company has identified its key suppliers, including gas suppliers and gas pipelines, and has communicated with them, including conducting on-site visits, for the purpose of evaluating the status of their solutions to their respective Year 2000 issues. Costs to Address Year 2000 issues. As of September 30, 1999, the Company had incurred a total of over $900,000 in direct fees and expenses in connection with its Year 2000 efforts. The Company expects to spend approximately $1.0 million in direct fees and expenses on its Year 2000 efforts by December 31, 1999. In addition, as part of its normal systems 6 upgrade in the ordinary course of business, the Company has replaced its customer information system, accounting and financial reporting system, and human resources system. Although these systems are Year 2000 ready, the replacement of these systems was not accelerated to 1999 solely in an attempt to address Year 2000 issues. Risks of Year 2000 issues and contingency plans. As required by the United States Securities and Exchange Commission ("SEC"), the Company has identified what it believes are its "most reasonably likely worst case Year 2000 scenarios." These scenarios are (i) the temporary interference with the Company's ability to receive gas from upstream suppliers and deliver gas to customers; (ii) the temporary interference with the Company's ability to communicate with customers regarding any problems with service they may encounter; and (iii) the temporary inability to send invoices to and receive payments from customers. The "most reasonably likely worst case scenario" associated with the Year 2000 issues would be the Company's temporary inability to continue to transport and distribute gas to its customers without interruption. In the event the Company and/or its suppliers and vendors were unable to remediate critical Year 2000 issues prior to January 1, 2000, the ability of the Company to deliver gas to its customers without interruption could be impacted. In order to address this scenario, the Company has developed contingency plans to continue to deliver gas primarily through manual intervention and other procedures should it become necessary to do so. Such procedures include back-up power supply for its critical distribution and storage operations, manual operation of the Company's gas distribution and storage systems, and, if necessary, curtailment of supply. The Company's storage capacity would be used to supplement system supply in the event its suppliers or gas pipelines are unable to make deliveries. With respect to communications with customers, which is heavily reliant on services provided by third parties, the Company has evaluated Year 2000 readiness by such third parties and has continued to refine its contingency plans to address any worst case scenarios. Concerning the billing and payment systems, as previously discussed, the Company has replaced its customer information system, accounting and financial reporting system, and human resources system with systems that are Year 2000 ready, which should substantially diminish the risk of Year 2000 issues. Nevertheless, the Company has developed contingency plans and has continued to refine such plans in case the billing and payment systems prove not to be Year 2000 ready. 7 Despite the Company's efforts, there can be no assurance that all material risks associated with Year 2000 issues relating to systems and embedded technology within its control will have been adequately identified and corrected before the end of 1999. However, as the result of its Year 2000 plan and the replacement of the customer information system, accounting and financial reporting system, and human resources system in 1999, the Company does not believe that in the aggregate, Year 2000 issues with respect to both its own IT and non-IT systems will be material to its business, operations or financial condition. On the other hand, while the Company has researched the Year 2000 readiness of its suppliers and vendors, the Company can make no representations regarding the Year 2000 readiness status of systems or parties outside its control, and cannot assess the effect on it of any non-readiness by such systems or parties. Ratemaking procedures The Company's five utility divisions are regulated by various state or local public utility authorities. The method of determining regulated rates varies among the 12 states in which the Company has utility operations. It is the responsibility of the regulators to determine that utilities under their jurisdiction operate in the best interests of customers while providing the utilities the opportunity to earn a reasonable return on investment. In a general rate case, the applicable regulatory authority, which is typically the state public utility commission, establishes a base margin, which is the amount of revenue authorized to be collected from customers to recover authorized operating expense (other than the cost of gas), depreciation, interest, taxes and return on rate base. The Company's utility divisions perform annual deficiency studies for each rate jurisdiction to determine when to file rate cases, which are typically filed every two to five years. Substantially all of the sales rates charged by the Company to its customers fluctuate with the cost of gas purchased by the Company. Rates established by regulatory authorities are adjusted for increases and decreases in the Company's purchased gas cost through automatic purchased gas adjustment mechanisms. Therefore, while the Company's operating revenues may fluctuate, gross profit (which is defined as operating revenues less purchased gas cost) is generally not eroded or enhanced because of gas cost increases or decreases. 8 The overall reduction in net revenue from 1998 to 1999, other than the reduction resulting from the effects of warmer than normal weather, confirms the need for revised rates in certain jurisdictions. This is generally the result of depreciation, operating expenses and interest expense associated with assets placed in service but for which new rates have not been placed in effect to allow the Company to recover the costs associated with those assets and to provide a reasonable return on the investments made. In the regulatory environment, assets have to be placed in service and historical test periods established before rate cases can be filed. Once filed, regulatory bodies can suspend implementation of the new rates while studying the cases. All the while, as was the case for Atmos in 1999, the Company suffers the negative financial effects of having placed assets in service without the benefit of rate relief. In that regard, the Company engaged in three rate proceedings in 1999: a rate investigation in Trans Louisiana Gas Company ("Trans La Division") before the Louisiana Public Service Commission ("Louisiana Commission"); a rate case before the Kentucky Public Service Commission ("Kentucky Commission") in Western Kentucky Gas Company ("Western Kentucky Division"); and, two rate cases before the cities in Energas Company ("Energas Division"). In August 1998, the Trans La Division filed with the Louisiana Commission requesting a commodity performance mechanism and a rate freeze and the Louisiana Commission responded by ordering a rate investigation. During the rate proceeding, the Trans La Division sought to: - Preserve revenues; - Maintain competitive rates and create a use-based billing method for the cost of service; and - Restructure rates to be revenue neutral and reduce weather sensitivity. In October 1999, a settlement was reached and the Louisiana Commission issued an order, effective November 1, 1999, addressing each of these issues as described in Note 3 of notes to the accompanying consolidated financial statements. In May 1999, the Western Kentucky Division requested an increase in revenues of approximately $14.1 million from the Kentucky Public Service Commission. In this case the Western Kentucky Division sought: - To support the Company's business plans with regulatory strategy; 9 - To apply marketing principles to develop rate proposals maximizing customer satisfaction and profitability; - To eliminate revenue deficiency resulting from investments since the last rate case; - To use Year 2000 projected costs to design future rates; - To set rates to recover cost of each service; and - To consistently earn authorized returns via long-term price stability proposals, such as weather normalization adjustment and industrial rate proposals designed to protect industrial margin losses resulting from potential bypass. The hearing is scheduled to begin in December 1999, and the final order is required by statute by April 24, 2000. In August 1999, the Energas Division filed rate cases with the cities served by its West Texas System and the City of Amarillo. The Company is seeking to: - Eliminate revenue deficiency resulting from investments since the last rate case; - Develop funding mechanisms for projects which maintain safety and reliability of the system; - Differentiate customer rates and classes by true cost of service; - Earn authorized return on equity in all Energas rate divisions; - Eliminate or reduce the number of future rate filings; - Prepare Energas for unbundling; - Design rates that provide stable income regardless of weather; and - Implement depreciation rates that reflect the actual retirements and replacements. The City of Amarillo is required by statute to reach a decision on the case by the end of December 1999. The West Texas Cities must reach a decision by the end of January 2000. If a settlement is not reached in either case at the cities' level, the case will be appealed to the Railroad Commission of Texas. The Company's rate activity for the last three fiscal years can be summarized as follows: no rate changes in 1999, rate reductions of $1.8 million in 1998, and rate increases of $9.4 million in 1997. For further information regarding rate activity, see Note 3, "Rates," in notes to consolidated financial statements. 10 Weather and seasonality The Company's natural gas and propane distribution businesses and irrigation sales business are seasonal and dependent upon weather conditions in the Company's service areas. Natural gas sales to residential, commercial, and public authority customers and propane sales are affected by winter heating season requirements. Sales to industrial customers are much less weather sensitive. Sales to agricultural customers, who typically use natural gas to power irrigation pumps during the period from March through September, are affected by rainfall amounts. These factors generally result in higher operating revenues and net income during the period from October through March of each year and lower operating revenues, and either net losses or lower net income during the period from April through September of each year. The effect of significantly warmer than normal winter weather in 1999 on the Company's consolidated volumes delivered is illustrated by the following degree day information. Year ended September 30, ------------------------- 1999 1998 1997 ----- ----- ----- Sales volumes - Bcf 140.1 159.4 164.2 Transportation volumes - Bcf 55.5 56.2 48.8 ----- ----- ----- Total 195.6 215.6 213.0 ===== ===== ===== Degree days: Actual 3,374 3,799 3,909 % of normal 85% 95% 98% The effects of weather that is above or below normal are offset in the Tennessee and Georgia jurisdictions served by the United Cities Gas Company ("United Cities Division") through Weather Normalization Adjustments ("WNA"). The Georgia Public Service Commission and the Tennessee Regulatory Authority have approved WNAs. The WNA, effective October through May each year in Georgia, and November through April each year in Tennessee, allow the United Cities Division to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. The net effect of the WNA was an increase in revenues of $4.4 million, $.7 million and $2.6 million in 1999, 1998 and 1997, respectively. Approximately 186,000 or 18% of the Company's meters in service are located in Georgia and Tennessee. 11 The Company recognizes the benefits of mitigating the effects of weather where possible. In that regard, the Company is currently seeking a WNA in its rate case in Kentucky and is seeking to increase its customer charge in Texas to help offset some of the negative effects of weather. However, the Company cannot predict whether it will receive the WNA in Kentucky or the increased customer charges in Texas, or how much benefit might be achieved. For further information regarding the impact of weather and seasonality on operating results, see Note 17, "Selected Quarterly Financial Data (unaudited)" in notes to consolidated financial statements herein. CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of Cash Flows") Fiscal 1999, like fiscal 1998, was a year in which total cash outflows exceeded total cash inflows. This was generally the result of the combination of lower than normal cash flows from operating activities as a result of warmer than normal weather, higher than normal capital expenditures and mandatory long- term debt retirement. This cash shortfall was financed with short-term debt and sales of common stock through the Company's Employee Stock Ownership Plan ("ESOP") and its Direct Stock Purchase Plan ("DSPP"). Cash flows from operating activities Cash flows from operating activities as reported in the consolidated statement of cash flows totaled $84.7 million for 1999 compared with $91.7 million for 1998 and $68.7 million for 1997. The decrease in net cash provided by operating activities from 1998 to 1999 was the result of lower net income in 1999 primarily due to lower sales volumes because of 11% warmer winter weather, more rainfall in its agricultural service area and increased operating expenses. The increase in net cash provided by operating activities from 1997 to 1998 was the result of including a full 12 months of activity for the United Cities Division in the 1998 statement of cash flows for the combined companies. Using 1997 beginning balances for United Cities Gas Company ("UCGC") as of December 31, 1996 resulted in large swings in certain seasonal asset and liability accounts like accounts receivable and accounts payable. The changes in deferred charges and other assets and other current liabilities in 1997 and 1998 were related to merger and integration costs accrued and the related regulatory assets recorded in the fourth quarter of 1997. The $35.7 million increase in accounts receivable in 1999 was due to a change in over/under recovered 12 gas costs from a credit(over-recovered) balance of $16.2 million at September 30, 1998 to a debit(under-recovered) balance of $7.6 at September 30, 1999, and a temporary suspension in service cutoffs and normal efforts to collect past due receivables in connection with the Company's conversion to the new customer information and billing system. The over-recovered balance from 1998 was returned to customers through reductions in their 1999 bills. The $12.0 million increase in deferred charges and other assets net of non-cash amounts in 1999 was primarily due to increased pension assets. The $19.4 million increase in accounts payable in 1999 was primarily due to increased gas costs payable. The $11.9 million decrease in taxes payable in 1999 resulted from approximately 70% lower income tax expense due to lower pretax income. See "Consolidated Statements of Cash Flows" for other changes in assets and liabilities. Cash flows from investing activities A substantial portion of the Company's cash resources is used to fund its ongoing construction program in order to provide natural gas services to a growing customer base. Net cash used in investing activities totaled $109.6 million in 1999 compared with $118.8 million in 1998 and $121.1 million in 1997. In 1998, the Company received $16.0 million from the sale of office buildings and an airplane. Capital expenditures in fiscal 1999 amounted to $110.4 million, compared with $135.0 million in 1998 and $122.3 million in 1997. Currently budgeted capital expenditures for fiscal 2000 total approximately $75 million and include funds for additional mains, services, meters, and equipment. Completion of technology infrastructure and business process changes, implementation of Oracle enterprise resource planning system, and Year 2000 readiness in 1999 allowed the Company to significantly reduce its planned capital expenditures for fiscal 2000. Capital expenditures for fiscal 2000 are planned to be financed from internally generated funds and financing activities, as discussed below. The excess of cash outflows over inflows has resulted in an increase in debt as a percentage of total capitalization, including short-term debt, except for the portion related to current storage gas, as shown in the table below. 13 September 30, ------------------------------------------ 1999 1998 ---------------- ----------------- (In thousands) Working capital Short-term debt(1) $ 44,653 $ 48,909 ======== ======== Short-term debt $123,651 13.8% $ 17,491 2.1% Long-term debt 395,331 44.1% 456,331 54.0% Shareholders' equity 377,663 42.1% 371,158 43.9% -------- ----- -------- ----- Total capitalization $896,645 100.0% $844,980 100.0% ======== ===== ======== ===== (1)Includes short-term borrowings associated with working gas inventories. The debt as a percentage of total capitalization was 57.9% and 56.1% at September 30, 1999 and 1998, respectively. The Company's longer term plans are to decrease the debt to capitalization ratio to nearer its target range of 50- 52% through cash flow generated from operations, continued issuance of new common stock under its DSPP and ESOP, and reduction of capital expenditures to the range of $75.0 million to $80.0 million from the range of $110.4 million to $135.0 million in 1999 and 1998. Cash flows from financing activities Net cash provided by financing activities totaled $28.7 million for 1999 compared with $25.9 million for 1998 and $47.3 million for 1997. Financing activities during these periods included issuance of common stock, dividend payments, short-term borrowings from banks under the Company's credit lines, and issuance and repayment of long-term debt. Cash dividends paid. The Company paid $33.9 million in cash dividends during 1999 compared with $31.8 million in 1998 and $26.4 million in 1997 (excluding dividends of $3.4 million paid by UCGC in the quarter ended December 31, 1996). Atmos raised the dividend rate a total of $.04 per share for both 1998 and 1999. Short-term financing activities. At September 30, 1999, the Company had committed lines of credit for $250.0 million and $12.0 million to provide for short-term cash requirements. These credit facilities are negotiated at least annually. At 14 September 30, 1999, the Company also had uncommitted short-term credit lines of $74.0 million, of which $70.4 million was unused. In October 1998, the Company began a commercial paper program under which it is authorized to issue up to $250.0 million. The commercial paper program is supported by a $250.0 million committed line of credit. At September 30, 1999, the Company had $152.7 million of commercial paper outstanding. During 1999, short-term debt increased $101.9 million due largely to lower net income and cash requirements of $61.0 million for repayments of long-term debt and capital expenditures of $110.4 million. Short-term debt decreased $100.9 million in 1998, due to the application of a portion of the $150.0 million proceeds from the issuance of 6.75% debentures. Short-term debt increased $38.8 million during 1997. Long-term financing activities. No long-term debt was issued in fiscal 1999. In July 1998, the Company issued $150.0 million of 30-year 6.75% debentures. The debentures are rated A3 by Moody's and A- by Standard & Poor's. Long-term debt payments totaled $61.0 million, $16.3 million, and $14.7 million for the years ended September 30, 1999, 1998 and 1997, respectively. The amount for 1997 excludes repayments of $1.4 million by UCGC in the quarter ended December 31, 1996. Payments of long-term debt in 1999, 1998 and 1997 consisted of annual installments under the various loan documents. The loan agreements pursuant to which the Company's Senior Notes and First Mortgage Bonds have been issued contain covenants by the Company with respect to the maintenance of certain debt-to-equity ratios and cash flows, and restrictions on the payment of dividends. See Note 4 of the accompanying notes to consolidated financial statements for more information on these covenants. See Note 6 "Contingencies" for information regarding guarantees of certain accounts payable and short-term borrowings of Woodward Marketing, LLC ("WMLLC"). Issuance of common stock. The Company issued a total of 849,481, 755,882 and 400,578 shares of common stock in 1999, 1998 and 1997, respectively, under its various plans. See the Consolidated Statements of Shareholders' Equity and Note 7 of the accompanying notes to consolidated financial statements for the number of shares previously issued and available for future issuance under each of the Company's plans. 15 Future capital requirements The Company believes that internally generated funds, its credit facilities, commercial paper program and access to the public debt and equity capital markets will provide necessary working capital and liquidity for capital expenditures and other cash needs for fiscal 2000. The Company has access to $262.0 million under its committed lines of credit and $74.0 million under its uncommitted lines. A committed line of credit of $250.0 million is used to support the Company's $250.0 million commercial paper program. In early fiscal 2000, the Company plans to seek regulatory approvals and register a shelf offering with the SEC for the issuance from time to time of up to $500 million in debt and equity securities for general corporate purposes. Pro forma statement of cash flows for 1997 Because of the pooling of interests of Atmos, which has a September 30 fiscal year-end, with UCGC, which had a December 31 year-end, the activities of UCGC for the quarter ended December 31, 1996 were included in the restated 1996 consolidated statement of cash flows instead of the 1997 consolidated statement of cash flows. As a result, amounts in the 1997 consolidated statement of cash flows as reported are different than they would have been, had they included a full 12 month's activity for UCGC. The following amounts summarize the pro forma condensed consolidated statement of cash flows of Atmos and UCGC for the full 12 months ended September 30, 1997. (In thousands) Net cash provided by operating activities $ 60,278 Net cash used in investing activities (131,286) Net cash provided by financing activities 68,267 --------- Decrease in cash (2,741) Cash at beginning of year 8,757 --------- Cash at end of year $ 6,016 ========= 16 RESULTS OF OPERATIONS - CONSOLIDATED Year ended September 30, 1999 compared with year ended September 30, 1998 To assist in management's discussion of results of operations, the following table presents the effects of certain special items and weather on reported consolidated net income. Earnings per share amounts presented in this discussion are on a diluted basis. Year ended September 30, ------------------------------------------------- 1999 1998 1997 ---------------- -------------- -------------- Per Per Per Amount Share Amount Share Amount Share ------- ----- ------- ----- ------- ----- (In thousands, except per share data) Net income as reported $17,744 $ .58 $55,265 $1.84 $23,838 $ .81 Special items: Management reorganization - - - - 2,800 .10 Reserve for integration costs - - - - 12,630 .43 Sale of assets - - (2,244) (.07) - - Litigation settlement 2,070 .07 - - - - ------- ---- ------- ----- ------- ----- Normalized net income except for effects of weather 19,814 .65 53,021 1.77 39,268 1.34 Effects of weather 28,224 .91 3,485 .11 3,571 .12 ------- ----- ------- ----- ------- ----- Normalized net income $48,038 $1.56 $56,506 $1.88 $42,839 $1.46 ======= ===== ======= ===== ======= ===== Net income as reported The Company reported net income of $17.7 million, or $.58 per diluted share, on operating revenues of $690.2 million for the fiscal year ended September 30, 1999. Net income for 1998 was $55.3 million, or $1.84 per diluted share, on operating revenues of $848.2 million, which included one-time gains totaling $2.2 million or $.07 per diluted share, from the sales of real estate and equipment owned by the United Cities Division. Results for the year were negatively impacted by the warmest winter on record for Atmos. Across the Atmos system, weather was more than 15 percent warmer than normal and more 17 than 11 percent warmer than last year. Rainfall in West Texas exceeded average rainfall levels for the region by more than 32% during the 1999 irrigation season, resulting in a 43% decrease in irrigation sales over last year. In addition, increased depreciation and interest expense related to assets placed in service in advance of recognition in rates adversely affected financial results. Earnings were also reduced by a charge in the second quarter of $.07 per share for settlement of litigation in Louisiana. Net income for 1999 was also negatively impacted by operating and maintenance expenses that were higher than last year as a result of the first full year of operation of the Company's customer support center in Amarillo; process improvement initiatives related to the new customer information and billing system and the accounting and human resource systems placed in service during the year; and Year 2000 readiness initiatives. Operation expenses also included increased reserves of $5.0 million for the possible write-off of accounts receivable resulting from a temporary suspension in service cutoffs and normal efforts to collect past due receivables in connection with the Company's conversion to the new customer information and billing system. In addition to lower gross profit resulting from adverse weather conditions, gross profit for the year was reduced $4.3 million by reserves established for deferred gas costs that are not expected to be recoverable. Finally, 1999 results were positively impacted by a change in accounting principle adopted by WMLLC, a gas marketing and services company in which Atmos owns a 45% interest. WMLLC adopted Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" ("EITF 98-10"), the effect of which added $2.4 million to other income. For fiscal year 1998, the Company reported net income of $55.3 million, or $1.84 per diluted share, on operating revenues of $848.2 million. The 1998 net income included one-time gains totaling $2.2 million or $.07 per diluted share, from the sales of real estate and equipment. Although revenues for 1998 were lower as a result of winter weather that was 5% warmer than normal, as well as warmer than 1997, earnings improved due to gains on asset sales, lower operation and maintenance expenses and increased irrigation sales. Operation and maintenance expenses were lower for 1998 due to a company-wide restructuring of the organization and Atmos' integration of the United Cities Division. Sales of gas in West Texas to farmers for fueling irrigation pumps increased due to hot and dry summer weather in 18 1998. Irrigation volumes increased 34% in 1998 compared with 1997. For fiscal year 1997, the Company reported net income of $23.8 million, or $.81 per share, on operating revenues of $906.8 million. The 1997 net income included the effects of special after-tax charges related to management reorganization ($2.8 million or $.10 per share) and reserves related to the UCGC merger and integration ($12.6 million or $.43 per share). Excluding the effect of these charges, the Company's net income would have been $39.3 million or $1.34 per share in 1997, compared with $41.2 million, or $1.42 per share for 1996. The 1997 results include UCGC, which merged with Atmos effective July 31, 1997. Special items The Company became successor in interest in connection with a lawsuit filed against a gas company it acquired in Louisiana in 1995. In 1999 the Company settled the lawsuit for $3.25 million or $2.07 million after-tax. In 1998, the Company sold UCGC's former headquarters office building in Brentwood, Tennessee; two office buildings and a piece of land in Franklin, Tennessee that UCGC had held for investment; and an airplane. The Company realized a pre-tax gain on the sale of assets totaling $3.3 million or $2.2 million after-tax. In 1997 the Company completed a management reorganization and recorded a charge of $4.4 million ($2.8 million after-tax) in related costs. In connection with the UCGC merger and integration in 1997, the Company recorded approximately $17.0 million of transaction costs and $42.8 million for separation and other costs. The Company believes a significant amount of these costs will be recovered through rates and future operating efficiencies of the combined operations. Therefore, the Company recorded these costs as regulatory assets and established a reserve of $20.3 million ($12.6 million after-tax), to account for costs that may not be recovered. For further information regarding the merger, see Note 2 of notes to consolidated financial statements. 19 Consolidated Other Income, Interest Charges and Income Taxes Other income Equity in earnings of unconsolidated investment amounted to $7.2 million, $3.9 million and $3.3 million for 1999, 1998 and 1997, respectively. The increase for 1999 was primarily attributable to a change in accounting principle adopted by WMLLC. WMLLC adopted EITF 98-10, the effect of which added $2.4 million to equity in earnings of unconsolidated investment. Interest income was $.8 million, $1.5 million and $2.2 million for 1999, 1998 and 1997, respectively. The decreases in 1998 and 1999 were due to maintaining lower overnight cash balances for short-term investing. Other, net was $2.2 million, $4.3 million and $(.3) million for 1999, 1998 and 1997, respectively. The increase from 1997 to 1998 was primarily due to the $3.3 million gain from sale of certain assets obtained in the merger with UCGC. The $2.2 million in 1999 was primarily due to income from performance-based rates ("PBR") which were implemented in Kentucky in 1998. Interest charges Interest charges totaled $37.1 million, $35.6 million and $33.6 million in 1999, 1998 and 1997, respectively. The increases for 1998 and 1999, were related to increases in total debt outstanding for funding the infrastructure, technology, process changes and customer support investments made in 1997, 1998 and 1999. Income taxes The provision for income taxes was $9.6 million, $31.8 million and $14.3 million for 1999, 1998 and 1997, respectively. Changes in income taxes are primarily related to changes in pre-tax income. For further information regarding income taxes, see Note 5 of notes to consolidated financial statements. Net income by segment The Company has three business segments: utility operations, propane operations and energy services, which includes the Company's 45% interest in WMLLC. The following table sets forth the net income (loss) of each of these segments for 1999, 1998 and 1997. 20 Year ended September 30, -------------------------------- 1999 1998 1997 -------- -------- -------- (In thousands) Utility $10,800 $43,332 $19,739 Propane (869) (66) (90) Energy Services 7,813 11,999 4,189 ------- ------- ------- Reported net income $17,744 $55,265 $23,838 ======= ======= ======= For additional financial information regarding the Company's segments, see Note 12 of notes to consolidated financial statements and the following discussion of the "Results of Operations" for each segment. 21 RESULTS OF OPERATIONS - UTILITY Key financial and operating data for the Company's utility operations are highlighted in the following table. Year ended September 30, --------------------------------- 1999 1998 1997 ---------- ---------- -------- Financial (Dollars in thousands, - --------- except per Mcf data) Operating revenues $ 621,211 $ 739,930 $807,428 Purchased gas cost 343,338 438,920 505,716 ---------- ---------- -------- Gross profit 277,873 301,010 301,712 Operating expenses 225,623 200,345 240,499 Litigation settlement 3,250 - - ---------- ---------- -------- Operating income 49,000 100,665 61,213 Other income 2,763 843 1,242 Interest charges 35,799 33,181 30,882 Income taxes 5,164 24,995 11,834 ---------- ---------- -------- Net income $ 10,800 $ 43,332 $ 19,739 ========== ========== ======== Operating - --------- Sales volumes (MMcf): Residential 67,128 73,472 75,215 Commercial 31,457 36,083 37,382 Public authority and other 5,793 4,937 5,195 Industrial 20,901 22,256 27,545 ---------- ---------- -------- Total 125,279 136,748 145,337 Transportation (MMcf) 55,468 56,224 48,800 ---------- ---------- -------- Total volumes (MMcf) 180,747 192,972 194,137 ========== ========== ======== Meters in service, end of year 1,037,995 1,004,532 985,448 Average gas sales price/Mcf $ 4.71 $ 5.17 $ 5.36 Average cost of gas/Mcf $ 2.74 $ 3.21 $ 3.48 Average margin per Mcf sold $ 1.97 $ 1.96 $ 1.88 Average transportation revenue/Mcf $ .42 $ .43 $ .41 22 Year ended September 30, 1999 compared with year ended September 30, 1998 Operating revenues decreased approximately 16% to $621.2 million in 1999 from $739.9 million in 1998 due to a decrease of 8% in sales volumes and a decrease of 9% in the average sales price per thousand cubic feet ("Mcf") of gas sold. The decrease in sales price reflects a decrease in the commodity cost of gas, which is passed through to end users, and rate decreases implemented in 1998. Sales to weather sensitive residential, commercial and public authority customers decreased approximately 10.1 billion cubic feet ("Bcf") in 1999 while sales and transportation volumes delivered to industrial and agricultural customers decreased approximately 2.1 Bcf. Total sales and transportation volumes delivered decreased 6% to 180.7 Bcf in 1999, as compared with 193.0 Bcf in 1998. The volume decrease was primarily due to lower demand as a result of weather that was 11% warmer in 1999 than in 1998. Gross profit decreased by approximately 8% to $277.9 million in 1999 from $301.0 million in 1998. Factors contributing to the lower gross profit were a decrease in sales volumes of 11.5 Bcf or 8% due to the effect of 11% warmer weather than in 1998, rate decreases totaling approximately $1.8 million implemented in fiscal 1998 in Colorado and Virginia and a reserve of $4.3 million established for deferred gas costs that are not expected to be recoverable. Operating expenses increased $25.3 million or 13% to $225.6 million in 1999. The increase in operating expenses was due to the first full year of operation of the Company's Customer Support Center in Amarillo; process improvement initiatives related to the new customer information and billing system and the accounting and human resource systems placed in service during the year; and Year 2000 readiness initiatives. Operation expenses also included increased reserves of $5.0 million for the possible write-off of accounts receivable resulting from a temporary suspension in service cutoffs and normal efforts to collect past due receivables in connection with the Company's conversion to the new customer information and billing system. Year ended September 30, 1998 compared with year ended September 30, 1997 Utility operating revenues decreased approximately 8% to $739.9 million in 1998 from $807.4 million for 1997 due to a decrease of 6% in sales volumes and a decrease of 4% in the average sales price per Mcf. The decrease in sales volumes resulted from weather that was 3% warmer than 1997 and 5% warmer 23 than 30-year normals. Sales volumes and revenues were also reduced by certain industrial customers switching from sales service to transportation service. Gross profit was not significantly changed at $301.0 million for 1998 as compared with $301.7 million for 1997. The switching from sales to transportation service did not significantly affect gross profit for 1998. Operating expenses decreased $40.2 million for 1998 as compared with 1997 primarily due to a $20.3 million reserve for integration included in 1997, a $4.4 million charge for a management reorganization in 1997, and a significant reduction in 1998 operating expenses due to the company-wide restructuring of the organization and the integration of the United Cities Division. Interest charges increased 7% to $33.2 million primarily due to an increased level of debt and slightly higher average short-term rates in 1998 as compared with 1997. 24 RESULTS OF OPERATIONS - PROPANE Key financial and operating data for the propane operations are presented in the following table. Year ended September 30, --------------------------- 1999 1998 1997 ------- ------- ------ Financial (Dollars in thousands, - --------- except per gallon data) Operating revenues $22,944 $29,091 $33,194 Purchased gas cost 11,155 17,709 21,193 ------- ------- ------- Gross profit 11,789 11,382 12,001 Operating expenses 12,332 10,763 11,596 ------- ------- ------- Operating income(loss) (543) 619 405 Other income 482 174 159 Interest charges 1,231 897 744 Income tax benefit (423) (38) (90) ------- ------- ------- Net income (loss) $ (869) $ (66) $ (90) ======= ======= ======= Operating - --------- Propane heating degree days: Actual 3,440 3,799 3,847 % of normal 85% 94% 96% Sales volumes (000 gallons): Retail 19,700 17,229 17,145 Wholesale 2,591 6,183 8,059 ------- ------- ------- Total 22,291 23,412 25,204 ======= ======= ======= Average selling price/gallon $.88 $.88 $.90 Average cost/gallon $.44 $.53 $.65 Customers, end of year 39,539 37,400 29,097 25 Year ended September 30, 1999 compared with year ended September 30, 1998 Propane revenues decreased $6.2 million from $29.1 million in 1998 to $22.9 million in 1999 primarily due to decreased wholesale volumes sold as a result of the implementation of the Company's plan to exit the wholesale propane supply and transportation business. Partially offsetting this decrease was an increase in the retail gallons sold as a result of the acquisitions of Ingas, Inc. in May, 1998; Harris Propane Gas Company, Inc. in July 1998; Massey Propane Gas Company and E-Con Gas, Inc. in August 1998; and Shaw LP Gas, Inc. in September 1998. The Company exited the less profitable propane transportation, cylinder exchange, and appliance sales and service businesses in 1999. Purchased gas cost decreased $6.5 million from $17.7 million in 1998 to $11.2 million in 1999 due primarily to decreased wholesale volumes sold. Additionally, the average cost per gallon decreased $.09 per gallon from $.53 per gallon in 1998 to $.44 per gallon in 1999. This decrease was partially offset by the cost of increased retail gallons sold due to the acquisitions made during fiscal 1998. Operating expenses increased $1.6 million from $10.8 million in 1998 to $12.3 million in 1999 due primarily to the acquisitions made during fiscal 1998. Interest expense increased $.3 million due to increased debt related to the acquisitions in 1998 and slightly higher interest rates in 1999. Year ended September 30, 1998, compared with year ended September 30, 1997 Revenues from propane operations decreased from $33.2 million in 1997 to $29.1 million in 1998 primarily due to the decreased selling price per gallon to retail and wholesale customers. This decreased selling price was the result of the lower demand because of warmer weather and increased competition for customers as compared to the prior year. Partially offsetting this decrease was an increase in retail gallon sales. The increase in retail volumes sold resulted from the acquisitions discussed above. Purchased gas cost decreased from $21.2 million in 1997 to $17.7 million in 1998 primarily due to the decreased market cost of propane to the Company amounting to approximately $.12 per 26 gallon. Partially offsetting this decrease was increased gas purchased for retail sales in 1998 as compared to 1997. Operating expenses decreased from $11.6 million in 1997 to $10.8 million in 1998 primarily due to decreased administrative and general expenses due to decreased bad debt expense and a reduction of staff through attrition during 1998. Partially reducing this decrease was an increase in depreciation and amortization from $2.1 million in 1997 to $2.3 million in 1998 due to the acquisitions in 1997 and in 1998, and depreciation on additional plant placed in service. Interest expense increased from $.7 million in 1997 to $.9 million in 1998 due to increased short-term borrowings and long-term debt associated with the acquisitions in 1998, as well as increased short-term borrowings to cover cash flow deficits from decreased sales. RESULTS OF OPERATIONS - ENERGY SERVICES This segment is currently composed of four parts. Atmos Storage, Inc., owns underground storage fields in Kansas and Kentucky and provides storage services to the United Cities Division and Greeley Gas Company ("Greeley Division") and other non-regulated customers. Atmos Energy Services, Inc., ("AESI") markets gas to irrigation and industrial customers in West Texas through Enermart Energy Services Trust ("Enermart"), and to industrial customers in Louisiana and is developing plans for marketing various non-regulated services and products. Atmos Energy Marketing, LLC, owns the Company's 45% investment in WMLLC, a gas marketing and energy management services business. Atmos Leasing, Inc., leases buildings and vehicles to the United Cities Division and gas appliances to residential customers. Key financial data for the energy services segment are set forth below. 27 Year ended September 30, -------------------------- 1999 1998 1997 ------- ------- ------ (Dollars in thousands) Operating revenues $53,416 $80,672 $68,389 Purchased gas cost 43,284 61,228 52,448 ------- ------- ------- Gross profit 10,132 19,444 15,941 Operating expenses 4,350 7,849 10,950 ------- ------- ------- Operating income 5,782 11,595 4,991 Other income (loss) (96) 4,834 467 Equity in earnings of unconsolidated investment 7,156 3,920 3,254 Interest charges 215 1,501 1,969 Income taxes 4,814 6,849 2,554 ------- ------- ------- Net income $ 7,813 $11,999 $ 4,189 ======= ======= ======= Gas Sales (MMcf) Irrigation 9,655 17,018 12,743 Industrial 5,185 5,607 6,094 ------- ------- ------- Total 14,840 22,625 18,837 ======= ======= ======= Year ended September 30, 1999 compared with year ended September 30, 1998 Operating revenues decreased 34% from $80.7 million in 1998 to $53.4 million in 1999 due primarily to decreased West Texas non-regulated irrigation and industrial revenues. The decrease in irrigation revenues was due to increased rainfall and cooler summer temperatures in West Texas. Storage revenues also decreased due to decreased volumes withdrawn from underground storage as a result of warmer than normal winter weather in Kansas and Tennessee. Operating expenses decreased $3.5 million in 1999 due primarily to Enermart entering into an all-inclusive gas transportation service agreement with the Energas Division which resulted in costs which Enermart had previously classified as operation expense being classified as cost of gas in 1999. Decreased irrigation volumes in West Texas and storage withdrawals in Kansas and Tennessee also reduced operating costs. 28 Other income decreased $4.9 million in 1999 from 1998 primarily due to a $3.3 million gain on sale of assets in 1998, as discussed below. Equity in earnings of unconsolidated investment increased $3.2 million in 1999 from 1998 primarily because of the $2.4 million of income resulting from WMLLC's adoption of EITF 98-10 in 1999. Interest charges decreased $1.3 million due primarily to decreased short-term debt in 1999 as compared with 1998. Year ended September 30, 1998 compared with year ended September 30, 1997 Operating revenues increased 18% from $68.4 million for 1997 to $80.7 million for 1998 due to increases of $10.7 million in non-regulated West Texas irrigation and industrial revenues, and $1.6 million for gas storage operations. The increase in irrigation and industrial revenues was primarily due to hotter and drier than normal weather in West Texas in 1998. The increase in storage revenues was due to increased volumes withdrawn from underground storage in 1998 as compared with 1997. Like the utility and propane operations, gas storage volumes and revenues vary in relation to winter heating degree days. Operating expenses decreased $3.1 million in 1998 as compared with 1997 due primarily to operating efficiencies and cost savings from restructuring irrigation and gas storage operations. Other income increased to $4.8 million for 1998 as compared with $.5 million for 1997. The increase was primarily due to the sales of UCGC's former headquarters office, two office buildings and a piece of land in Franklin, Tennessee that UCGC had held for investment, and an airplane. Also contributing to the increase was gas brokering and utilization of storage capacity in excess of that dedicated to regulated markets to serve certain non-regulated markets. Interest charges decreased $.5 million in 1998 as compared with 1997 due primarily to reduced debt balances in Enermart, AESI's wholly-owned trust that conducts non-regulated gas marketing operations in West Texas. 29 Equity in earnings of WMLLC The Company accounts for its 45% investment in WMLLC using the equity method of accounting. Against the 45% of WMLLC's net income before tax, the Company records the amortization of the excess of the purchase price over the value of the net tangible assets, amounting to approximately $5.4 million which was allocated to intangible assets consisting of customer contracts and goodwill, and is being amortized over ten and twenty years, respectively, as well as the provision for income taxes. The following table presents the WMLLC financial results recorded by Atmos for the years ended September 30, 1999, 1998 and 1997. WMLLC has adopted the calendar year for financial reporting purposes. Twelve months ended September 30, ----------------------- 1999 1998 1997 ------- ------ ------ (In thousands) WMLLC net income before taxes $15,902 $8,711 $7,231 ======= ====== ====== Atmos share @ 45% 7,156 3,920 3,254 Less: Amortization of excess purchase price 407 400 359 Provision for taxes 2,362 1,337 1,100 ------- ------ ------ Atmos equity in WMLLC earnings $ 4,387 $2,183 $1,795 ======= ====== ====== The net income before taxes of WMLLC increased from $7.2 million for 1997, to $8.7 million for 1998, to $15.9 million for 1999, due to growth in number of customers and gas marketing volumes and revenues each year. Additionally, WMLLC adopted EITF 98-10 in 1999, the effect of which added $2.4 million to the Company's equity in earnings of unconsolidated investment. 30 Factors influencing future performance Performance of the Company in the near future will primarily depend on the results of its utility operations since utility operations are expected to continue to be the substantial contributor to the Company's consolidated net income. Because of the changing energy marketplace, there are several factors that will influence Atmos' future financial performance. Some of these factors are described below. Allowed rate of return The Company's utility business is subject to various regulated returns on its rate base in each of the 12 states in which it operates. The Company constantly monitors the allowed rates of return, its effectiveness in earning such rates, and initiates rate proceedings or operating changes as needed. Outcome of pending rate cases In the normal course of the regulatory environment, assets are placed in service and historical test periods are established before rate cases can be filed. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, the Company must suffer the negative financial effects of having placed assets in service without the benefit of rate relief. Management cannot predict the outcome of the approximately $28.4 million of revenue increases it is seeking in Texas and Kentucky. Weather The Company's natural gas and propane sales volumes and related revenues are directly correlated with space heating requirements that result from cold winter weather. Its agricultural sales volumes are associated with the rainfall levels during the growing season in its West Texas irrigation market. Weather is a significant factor influencing the Company's performance. Control of expenses Historically, the Company has been able to budget and control operating expenses and investment within the amounts authorized to be collected in rates, and intends to continue to do so. The ability to control expenses is an important factor that will influence future results. 31 Environmental matters The Company is involved in certain environmental matters and expenditures to comply with these laws and regulations are expected to be recovered through rates, insurance, or shared with other potentially responsible parties. These matters are not expected to materially affect the results of operations, financial condition or cash flows of the Company. See Note 6 of notes to consolidated financial statements for further information. Performance-based regulation Regulators in Georgia, Kentucky and Tennessee allow the Company and its customers to share in purchased gas cost savings when the Company can obtain gas supplies below certain benchmark indices. Acceptance of such incentives in other states would contribute to the profitability of the Company's utility operations. Deregulation or unbundling The Company is closely monitoring the development of unbundling initiatives in the natural gas industry. Because of its brand loyalty in its service areas, its enhanced technology and distribution system infrastructures, the Company believes that it is now positively positioned as unbundling evolves. Growth through acquisitions Achieving economies of scale, thereby spreading the fixed costs of the utility business over a large customer base is a basic tenet in the Company's plan to continue to be a low cost provider among its industry peers. Inflation The Company believes that inflation has caused, and will continue to cause, increases in certain operating expenses and has required and will continue to require assets to be replaced at higher costs. The Company has a process in place to continually review the adequacy of its gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. 32 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS Management is responsible for the preparation, presentation and integrity of the financial statements and other financial information in this report. The accompanying financial statements have been prepared in accordance with generally accepted accounting principles, and include estimates and judgments made by management that were necessary to prepare the statements in accordance with such accounting principles. The Company maintains a system of internal accounting controls designed to provide reasonable assurance that assets are safeguarded from loss and that transactions are executed and recorded in accordance with established procedures. The concept of reasonable assurance is based on the recognition that the cost of maintaining a system of internal accounting controls should not exceed related benefits. The system of internal accounting controls is supported by written policies and guidelines, internal auditing and the careful selection and training of qualified personnel. The financial statements have been audited by the Company's independent auditors. Their audit was made in accordance with generally accepted auditing standards, as indicated in the Report of Independent Auditors, and included a review of the system of internal accounting controls and tests of transactions to the extent they considered necessary to carry out their responsibilities for the audit. Management has considered the internal auditors' and the independent auditors' recommendations concerning the Company's system of internal accounting controls and has taken actions that are believed to be cost-effective in the circumstances to respond appropriately to these recommendations. The Audit Committee of the Board of Directors meets periodically with the internal auditors and the independent auditors to discuss the Company's internal accounting controls, auditing and financial reporting matters. 33 REPORT OF INDEPENDENT AUDITORS Board of Directors Atmos Energy Corporation We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation at September 30, 1999 and 1998, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 consolidated financial position of Atmos Energy Corporation at September 30, 1999 and 1998, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 1999, in conformity with generally accepted accounting principles. Ernst & Young LLP Dallas, Texas November 9, 1999 34 ATMOS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS September 30, ---------------------- 1999 1998 ---------- ---------- (In thousands, except share data) ASSETS Property, plant and equipment $1,526,834 $1,333,556 Construction in progress 22,424 112,864 ---------- ---------- 1,549,258 1,446,420 Less accumulated depreciation and amortization 583,476 528,560 ---------- ---------- Net property, plant and equipment 965,782 917,860 Current assets Cash and cash equivalents 8,585 4,735 Accounts receivable, less allowance for doubtful accounts of $9,231 in 1999 and $1,969 in 1998 70,564 34,887 Inventories 8,209 15,219 Gas stored underground 44,653 48,909 Prepayments 3,142 3,630 ---------- ---------- Total current assets 135,153 107,380 Deferred charges and other assets 129,602 116,150 ---------- ---------- $1,230,537 $1,141,390 ========== ========== (continued) 35 ATMOS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (continued) September 30, --------------------------- 1999 1998 ---------- ---------- (In thousands, except share data) CAPITALIZATION AND LIABILITIES Shareholders' equity Common stock, no par value (stated at $.005 per share); 100,000,000 shares authorized; issued and outstanding: 1999 - 31,247,800 shares, 1998 - 30,398,319 shares $ 156 $ 152 Additional paid-in capital 293,359 271,637 Retained earnings 83,231 99,369 Accumulated other comprehensive income 917 - ---------- ---------- Total shareholders' equity 377,663 371,158 Long-term debt 377,483 398,548 ---------- ---------- Total capitalization 755,146 769,706 Current liabilities Current maturities of long-term debt 17,848 57,783 Short-term debt 168,304 66,400 Accounts payable 64,167 44,742 Taxes payable 848 12,736 Customers' deposits 9,657 12,029 Other current liabilities 25,951 30,369 ---------- ---------- Total current liabilities 286,775 224,059 Deferred income taxes 112,610 80,213 Deferred credits and other liabilities 76,006 67,412 ---------- ---------- $1,230,537 $1,141,390 ========== ========== See accompanying notes to consolidated financial statements. 36 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME Year ended September 30, ------------------------------------ 1999 1998 1997 -------- -------- -------- (In thousands, except per share data) Operating revenues $690,196 $848,208 $906,835 Purchased gas cost 390,402 516,372 577,181 -------- -------- -------- Gross profit 299,794 331,836 329,654 Operating expenses Operation 144,815 131,336 173,683 Maintenance 9,141 10,278 11,974 Litigation settlement 3,250 - - Depreciation and amortization 56,874 47,555 45,257 Taxes, other than income 31,475 29,788 32,131 -------- -------- -------- Total operating expenses 245,555 218,957 263,045 -------- -------- -------- Operating income 54,239 112,879 66,609 Other income (expense) Equity in earnings of unconsolidated investment 7,156 3,920 3,254 Interest income 765 1,510 2,156 Other, net 2,202 4,341 (288) -------- -------- -------- Total other income 10,123 9,771 5,122 Interest charges, net 37,063 35,579 33,595 -------- -------- -------- Income before income taxes 27,299 87,071 38,136 Income taxes 9,555 31,806 14,298 -------- -------- -------- Net income $ 17,744 $ 55,265 $ 23,838 ======== ======== ======== Basic net income per share $ .58 $ 1.85 $ .81 ======== ======== ======== Diluted net income per share $ .58 $ 1.84 $ .81 ======== ======== ======== Cash dividends per share $ 1.10 $ 1.06 $ 1.01 ======== ======== ======== Weighted average shares outstanding: Basic 30,566 29,822 29,409 ======== ======== ======== Diluted 30,819 30,031 29,422 ======== ======== ======== See accompanying notes to consolidated financial statements. 37 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Common stock Accumulated ----------- Additional other Number of Stated paid-in comprehensive Retained shares value capital income earnings Total ------------ ------ ---------- ------------- -------- -------- (In thousands, except share data) Balance, September 30, 1996 29,241,859 $146 $241,658 $ - $ 87,778 $329,582 Net income - - - - 23,838 23,838 Cash dividends ($1.01 per share) - - - - (26,415) (26,415) Common stock issued: Restricted stock grant plan 100,000 1 2,443 - - 2,444 Direct stock purchase plans 85,243 - 1,888 - - 1,888 Outside directors stock-for-fee plan 3,008 - 72 - - 72 ESOP 212,327 1 5,113 - - 5,114 Less: UCGC net income for the quarter ended December 31, 1996 - - - - (9,263) (9,263) ---------- ---- -------- ------------- -------- -------- Balance, September 30, 1997 29,642,437 148 251,174 - 75,938 327,260 Net income - - - - 55,265 55,265 Cash dividends ($1.06 per share) - - - - (31,834) (31,834) Common stock issued: Restricted stock grant plan 114,250 1 2,898 - - 2,899 Direct stock purchase plan 531,353 3 14,482 - - 14,485 ESOP 52,473 - 1,485 - - 1,485 Long-term stock plan for United Cities Division 55,500 - 1,533 - - 1,533 Outside directors stock-for-fee plan 2,306 - 65 - - 65 ---------- ---- -------- ------------- -------- -------- Balance, September 30, 1998 30,398,319 152 271,637 - 99,369 371,158
(continued) 38 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (continued)
Common stock Accumulated ----------------- Additional other Number of Stated paid-in comprehensive Retained shares value capital income earnings Total ---------- ------ ---------- ------------- --------- --------- (In thousands, except share data) Balance, September 30, 1998 30,398,319 $ 152 $271,637 $ - $ 99,369 $371,158 Comprehensive income Net income - - - - 17,744 17,744 Unrealized holding gains on investments, net - - - 917 - 917 Cash dividends ($1.10 per share) - - - - (33,882) (33,882) Common stock issued: Restricted stock grant plan 56,850 - 1,732 - - 1,732 Direct stock purchase plan 694,905 4 17,429 - - 17,433 ESOP 89,435 - 2,362 - - 2,362 Long-term stock plan for United Cities Division 6,450 - 150 - - 150 Outside directors stock-for-fee plan 1,841 - 49 - - 49 ---------- ------ -------- ------------- -------- -------- Balance, September 30, 1999 31,247,800 $ 156 $293,359 $ 917 $ 83,231 $377,663 ========== ====== ======== ============= ======== ========
See accompanying notes to consolidated financial statements. 39 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended September 30, ------------------------------ 1999 1998 1997 -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 17,744 $ 55,265 $ 14,575 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization: Charged to depreciation and amortization 56,874 47,555 39,970 Charged to other accounts 4,800 5,861 2,237 Deferred income taxes 31,874 (3,968) 5,807 Gain on sales of non-utility assets - (3,335) - Changes in assets and liabilities: (Increase) decrease in accounts receivable (35,677) 36,330 32,198 (Increase) decrease in inventories 7,010 (2,886) 1,562 (Increase) decrease in gas stored underground 4,256 (787) (4,772) (Increase) decrease in prepayments 488 2,387 (3,208) Increase in deferred charges and other assets (12,012) (20,671) (29,683) Increase (decrease) in accounts payable 19,425 (17,884) (17,695) Increase (decrease) in taxes payable (11,888) 8,673 (837) Decrease in customers' deposits (2,372) (3,069) (1,714) Increase (decrease) in other current liabilities (4,418) (22,213) 28,716 Increase in deferred credits and other liabilities 8,594 10,393 1,593 -------- -------- -------- Net cash provided by operating activities 84,698 91,651 68,749 (continued) 40 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Year ended September 30, --------------------------------- 1999 1998 1997 --------- --------- --------- (In thousands) CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures $(110,353) $(134,989) $(122,312) Retirements of property, plant and equipment, net 757 178 1,189 Proceeds from sales of assets - 15,997 - --------- --------- --------- Net cash used in investing activities (109,596) (118,814) (121,123) CASH FLOWS FROM FINANCING ACTIVITIES Net increase (decrease) in short-term debt 101,904 (100,900) 38,812 Proceeds from issuance of long-term debt - 154,445 40,000 Repayment of long-term debt (61,000) (16,296) (14,659) Cash dividends paid (33,882) (31,834) (26,415) Issuance of common stock 21,726 20,467 9,518 --------- --------- --------- Net cash provided by financing activities 28,748 25,882 47,256 --------- --------- --------- Net increase (decrease) in cash and cash equivalents 3,850 (1,281) (5,118) Cash and cash equivalents at beginning of year 4,735 6,016 11,134 --------- --------- --------- Cash and cash equivalents at end of year $ 8,585 $ 4,735 $ 6,016 ========= ========= ========= See accompanying notes to consolidated financial statements. 41 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Contents of Notes to Consolidated Financial Statements 1. Summary of significant accounting policies 43 2. Business combinations 49 3. Rates 50 4. Long-term debt and short-term debt 53 5. Income taxes 56 6. Contingencies 58 7. Common stock and stock options 63 8. Employee retirement and stock ownership 67 plans 9. Other postretirement benefits 72 10. Earnings per share 75 11. Statement of cash flows supplemental 76 disclosures 12. Segment information 76 13. Marketable securities 80 14. Leases 81 15. Related party transactions 82 16. Subsequent event 82 17. Selected quarterly financial data (unaudited) 83 42 1. Summary of significant accounting policies Forward-looking statements - These notes to consolidated financial statements, particularly notes 2, 3, 6, 7, 9,14, and 16, may contain "forward- looking statements" as discussed herein in Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995" and should be read in conjunction with such discussion. Description of business - Atmos Energy Corporation and its subsidiaries ("Atmos" or the "Company") are engaged primarily in the natural gas utility business as well as certain non-regulated businesses. The Company distributes through sales and transportation arrangements natural gas to approximately 1.0 million residential, commercial, public authority and industrial customers through its five regulated utility divisions: Energas Company ("Energas Division") in Texas; Trans Louisiana Gas Company ("Trans La Division") in Louisiana; Western Kentucky Gas Company ("Western Kentucky Division") in Kentucky; Greeley Gas Company ("Greeley Division") in Colorado and Kansas; and United Cities Gas Company ("United Cities Division") in Illinois, Tennessee, Iowa, Virginia, Georgia, South Carolina and Missouri. Such business is subject to federal and state regulation and/or regulation by local authorities in each of the twelve states in which the utility divisions operate. Its shared services unit is located in Dallas, Texas and its Customer Support Center is located in Amarillo, Texas. Its nonregulated businesses include propane sales and various energy services businesses as described below. The Company is engaged in the retail and wholesale distribution of propane gas through United Cities Propane Gas, Inc. ("Propane"). It currently has operation and storage centers and storefront offices located in Tennessee, Kentucky, and North Carolina with a total company storage capacity of approximately 2.5 million gallons. As of September 30, 1999, Propane served approximately 40,000 customers in the states listed above as well as Virginia. Through Atmos Storage, Inc. ("Storage"), the Company owns and operates natural gas storage fields in Kentucky and Kansas to supplement natural gas used by customers of the regulated utility divisions in Tennessee, Kansas and Illinois and to provide storage services to other customers that may be in other states. 43 Through Atmos Energy Services, Inc., the Company markets gas to industrial and irrigation customers in West Texas through Enermart Energy Services Trust ("Enermart") and to industrial customers in Louisiana, and is developing plans for marketing various non-regulated services and products. Through Atmos Energy Marketing, LLC's 45% interest in Woodward Marketing, LLC ("WMLLC"), a limited liability company formed in Delaware with headquarters in Houston, Texas, the Company is engaged in gas marketing and energy management services. WMLLC provides gas supply management services to industrial customers, municipalities and local distribution companies, including the Company's five regulated utility divisions. Finally, the Company, through Atmos Leasing Inc. and Atmos Energy Marketing, LLC, leases real estate and vehicles to the United Cities Division and leases appliances to residential customers. Principles of consolidation - The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its subsidiaries. Each subsidiary is wholly owned and intercompany transactions have been eliminated. Accounting for unconsolidated investments - The Company accounts for its 45% interest in WMLLC using the equity method of accounting for investments. Equity in pre-tax earnings of WMLLC included in the consolidated statement of income was $7.2 million, $3.9 million and $3.3 million in 1999, 1998 and 1997, respectively. The Company amortizes the excess of the purchase price over the value of the net tangible assets, amounting to approximately $5.4 million, which was allocated to intangible assets consisting of customer contracts and goodwill over 10 and 20 years, respectively. WMLLC adopted Emerging Issues Task Force 98- 10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," ("EITF 98-10"). EITF 98-10 requires that energy trading contracts should be marked to market (that is, measured at fair value determined as of the balance sheet date) with the gains and losses included in earnings and separately disclosed. Atmos' 45% after-tax share of WMLLC's income from the adoption of EITF 98-10 was $2.4 million or $.08 per share. Restatement for pooling of interests - The consolidated financial statements for all periods prior to July 31, 1997 have been restated for the pooling of interests of the Company with United Cities Gas Company. Certain changes in account 44 classifications have been made to conform United Cities Gas Company's classifications to Atmos' presentation. Regulation - The Company's utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which it operates. Atmos' accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement requires cost-based rate regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. The Company records regulatory assets which represent assets which are being recovered through customer rates or are probable of being recovered through customer rates. Significant regulatory assets as of September 30, 1999 included the following: merger and integration costs of $35.9 million, net of related reserve, environmental costs of $3.9 million, and deferred cost of purchased gas of $.5 million. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. As of September 30, 1999, the Company had recorded a regulatory liability of $2.2 million for deferred income taxes. Revenue recognition - Sales of natural gas are billed on a monthly cycle basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. The Company follows the revenue accrual method of accounting for natural gas revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. Estimated losses due to credit risk are reserved at the time revenue is recognized. Utility property, plant and equipment - Utility property, plant and equipment is stated at original cost net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs, and the estimated cost of an allowance for funds used during construction (See AFUDC below). Major renewals and betterments are capitalized, while the costs of maintenance and 45 repairs are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the utility plant in service account, included in rate base and depreciation begins. Property, plant and equipment is depreciated at various rates on a straight-line basis over the estimated useful lives of the assets. The composite rates were 4.0%, 4.0% and 3.9% for 1999, 1998 and 1997, respectively. At the time property, plant and equipment is retired, the cost, plus removal expenses less salvage, is charged to accumulated depreciation. Allowance for funds used during construction ("AFUDC") - AFUDC represents the estimated cost of funds used to finance the construction of major projects. Under regulatory practices, the costs are capitalized and included in rate base for ratemaking purposes when the completed projects are placed in service. Interest expense of $3.7 million, $4.1 million and $1.2 million was capitalized in 1999, 1998 and 1997, respectively. The increased amounts in 1999 and 1998 were related to the Customer Support Center and customer information, accounting and human resource technology systems that were completed and placed in service in 1999. Non-utility property, plant and equipment - Balances are stated at cost and depreciation is computed generally on the straight-line method for financial reporting purposes. Inventories - Inventories consist primarily of materials and supplies and merchandise held for resale. These inventories are stated at the lower of average cost or market. Inventories also include propane inventories of $768,000 and $979,000 at September 30, 1999 and 1998, respectively. Propane is priced at average cost. Gas stored underground - Net additions of inventory gas to storage and withdrawals of inventory gas from storage are priced using the average cost method for all Atmos utility divisions, except for the United Cities Division, where it is priced on the first-in first-out method. Gas stored underground and owned by Storage is priced on the last-in first-out ("LIFO") method. In accordance with the United Cities Division's purchased gas adjustment ("PGA") clause, the liquidation of a LIFO layer would be reflected in subsequent gas adjustments in customer rates and does not affect the results of operations. Noncurrent gas in storage is classified as property, plant and equipment and is priced at cost. 46 Income taxes - Income taxes are provided based on the deferred method, resulting in income tax assets and liabilities due to temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The deferred method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The deferred method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized. Cash and cash equivalents - The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Deferred charges and other assets - Deferred charges and other assets at September 30, 1999 and 1998 include merger and integration costs of $35.9 million and $39.5 million in 1999 and 1998, respectively, net of the related reserve for possible non-recovery; and the investment in WMLLC of $16.0 million and $11.9 million in 1999 and 1998, respectively. Also included in deferred charges and other assets are assets of the Company's qualified defined benefit retirement plans in excess of the plans' obligations, Company assets related to the nonqualified retirement plans, unamortized debt expense, and deferred compensation expense related to non-vested restricted stock grants. Deferred credits and other liabilities - Deferred credits and other liabilities include customer advances for construction, obligations under capital leases, obligations under other postretirement benefits, and obligations under the Company's nonqualified retirement plans. Earnings per share - The calculation of basic earnings per share is based on net income divided by the weighted average number of common shares outstanding. The calculation of diluted earnings per share is based on net income divided by the weighted average number of shares outstanding plus the dilutive shares related to the United Cities Division's Long-term Stock Plan and Atmos' Restricted Stock Grant Plan. Segment Information - In 1999, the Company adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information," ("SFAS No. 131"). SFAS No. 131 supersedes Statement of Financial Accounting Standards No. 14, "Financial 47 Reporting for Segments of a Business Enterprise," replacing the "industry segment" approach with the "management" approach. The management approach requires financial information to be disclosed for segments whose operating results are reviewed by the "chief operating decision maker." It also requires related disclosures about products and services. The adoption of SFAS No. 131 did not affect results of operations or financial position, but did affect the disclosure of segment information. Comprehensive Income - In 1999, the Company adopted Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income." This statement requires reporting of comprehensive income and its components (revenues, expenses, gains and losses) in any complete presentation of general purpose financial statements. Comprehensive income describes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events including, as applicable, foreign-currency items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. While the primary component of comprehensive income is the Company's reported net income, the other components of comprehensive income relate to unrealized gains and losses associated with certain investments held as available for sale. Use of estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates. Reclassifications - Certain prior year amounts have been reclassified to conform with the current year presentation. Recently Issued Accounting Standards Not Yet Adopted - The Company has not yet adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement will be effective for the Company's fiscal year 2001. It establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This Statement does not allow retroactive application to financial statements of prior periods. The Company's management is currently in the process of 48 evaluating the impact of adopting this Statement on its reported financial condition, results of operations and cash flows. 2. Business combinations On July 31, 1997, Atmos acquired by means of a merger all of the assets and liabilities of United Cities Gas Company ("UCGC") in accordance with the terms and provisions of an Agreement and Plan of Reorganization dated July 19, 1996 and amended October 3, 1996. A total of 13,320,221 shares of Atmos common stock was issued in a one-for-one exchange for all outstanding shares of UCGC common stock. UCGC was merged with and into Atmos by means of a tax-free reorganization. The transaction was accounted for as a pooling of interests; therefore, historical financial statements for periods prior to the merger were restated. Following the merger, UCGC's business began operating as United Cities Gas Company, a division of Atmos ("United Cities Division") and integration of the companies began. The United Cities Division is structured like other divisions of Atmos. To achieve this structure, approximately 560 utility positions in the United Cities Division were eliminated by September 1998. An additional 75 Atmos positions were eliminated as part of the integration, resulting in approximately 635 total position reductions in the combined Company by September 1998. Atmos also initiated plans to enhance its customer service in Texas, Louisiana, Kentucky, Colorado, Kansas and Missouri through business process changes which resulted in a net reduction of approximately 240 positions. These changes included restructuring business office operations, establishing a network of payment centers and creating a customer support center, and installing a new customer information center. During fiscal 1997 and 1998, the Company recorded as regulatory assets the costs of the merger and integration of the United Cities Division. The Company believes there are substantial long term benefits to its customers and shareholders from the merger of the two companies. The Company believes a significant amount of the costs to achieve these benefits will be recovered through rates and future operating efficiencies of the combined operations. Therefore, the merger and integration costs are being charged to operations concurrent with the benefits received. However, in the fourth quarter of fiscal 1997 the Company established a general reserve of approximately $20.3 million ($12.6 million after-tax), to account for costs that may not be recovered through rates. 49 3. Rates The following is a discussion of the Company's ratemaking activity for rate cases that are currently pending as of September 30, 1999 or rate proceedings completed during the three years ended September 30, 1999. In August 1999, the Energas Division filed rate cases in its West Texas System cities and Amarillo, Texas, requesting rate increases totaling approximately $13.2 million. In addition to the rate increase to recover investments in technology and distribution plant expansion and maintenance, the proposed rate design would increase the customer charge, reducing the impact on earnings of warmer than normal winter weather. Pursuant to Texas law, municipalities have original jurisdiction in the establishment of rates. The City of Amarillo has until December 1999 to decide on the rate request and the West Texas Cities have until January 2000. If the Company and the cities cannot agree on the amount of a rate increase, the Company must appeal to the Railroad Commission of Texas and a final resolution could be expected in the summer of 2000. Later in 1999 or early 2000, the Company plans to request a rate increase of approximately $1.1 million in the environs areas outside the city limits of the West Texas System cities and Amarillo, Texas for total increases of $14.3 million being sought in Texas. Rates in areas outside the city limits in Texas are subject to the jurisdiction of the Railroad Commission of Texas. Management cannot predict the outcomes of these rate proceedings. In June 1999, the Trans La Division appeared before the Louisiana Public Service Commission for a rate investigation and to redesign rates to mitigate the effects of warm winter weather. A decision was rendered by the Louisiana Commission in October 1999 that increased service charges associated with customer service calls and increased the monthly customer charges from $6 to $9, both effective November 1, 1999. While these changes are revenue neutral, this will mitigate the impact of warmer than normal winter weather on earnings. The decision also included a three-year rate stabilization clause, which will allow the Trans La Division's rates to be adjusted annually to allow the Company to earn a minimum return on equity of 10.5%. In May 1999, the Western Kentucky Division requested from the Kentucky Public Service Commission an increase in revenues of approximately $14.1 million, a weather normalization adjustment ("WNA") and changes in rate design to shift a portion of revenues from commodity charges to fixed rates. The WNA, if approved, would be similar to what the Company has in Georgia 50 and Tennessee and would be in effect from November through April, beginning in November 2000. The Kentucky Commission suspended the proposed rates for six months in July 1999. It must, by statute, make a decision by April 2000. Management cannot predict the outcome of this rate proceeding. In fiscal 1997, the Colorado Office of Consumer Counsel filed a complaint with the Colorado Public Utilities Commission ("Colorado Commission")requesting a $3.5 million reduction in the annual revenues in Colorado of the Greeley Division. On December 17, 1997, a hearing was held at the Colorado Commission presenting a Stipulation and Agreement reached by the Greeley Division and the Colorado Office of Consumer Counsel. It settled the Consumer Counsel's complaint against the Greeley Division for a $1.6 million reduction in annual revenues. The Stipulation and Agreement became effective in January 1998. The reduction decreased 1998 gross profit of the Greeley Division by approximately 4% and the gross profit of the Company by approximately .5%. On June 9, 1998, the Kentucky Public Service Commission issued an Order approving an Experimental Performance-based Ratemaking ("PBR") mechanism related to gas procurement and gas transportation activities filed by the Western Kentucky Division. The PBR mechanism is incorporated into the Western Kentucky Division's Gas Cost Adjustment Clause. It provides for sharing of purchased gas cost savings between the consumers and the Company. The Company recognized other income of $2.0 million under the Kentucky PBR in fiscal 1999. Effective April 1, 1999, the Tennessee Regulatory Authority approved the United Cities Division's request to continue its PBR mechanism related to gas procurement and gas transportation activities for a three-year period. The Authority revised the mechanism from the original two-year experimental period, by increasing the cap for incentive gains and/or losses to $1.25 million per year. Similar to Tennessee, the Georgia Public Service Commission renewed the Company's PBR program for an additional three years effective May 1, 1999. The gas purchase and capacity release mechanisms of the PBRs are designed to provide the Company incentives to find innovative methods to lower gas costs to its customers. The Company recognized other income of $176,000 in fiscal year 1999 for the Georgia and Tennessee PBRs. The Georgia Public Service Commission and the Tennessee Regulatory Authority approved WNAs in fiscal 1991 and 1992, respectively. The WNAs, effective October through May each year in Georgia and November through April each year in Tennessee, 51 allow the United Cities Division to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. The net effect of the WNA was an increase in revenues of $4.4 million, $.7 million and $2.6 million in 1999, 1998 and 1997, respectively. 52 4. Long-term debt and short-term debt Long-term debt at September 30, 1999 and 1998 consisted of the following: 1999 1998 -------------- --------- Unsecured 11.2% Senior Notes, (In thousands) due 2002, payable in annual installments of $2,000 $ 8,000 $ 10,000 Unsecured 9.76% Senior Notes, due 2004, payable in annual installments of $3,000 18,000 21,000 Unsecured 9.57% Senior Notes, due 2006, payable in annual installments of $2,000 14,000 16,000 Unsecured 7.95% Senior Notes, due 2006, payable in annual installments of $1,000 7,000 8,000 Unsecured 10% Notes, due 2011 2,303 2,303 Unsecured 8.07% Senior Notes, due 2006, payable in annual installments of $4,000 beginning 2002 20,000 20,000 Unsecured 8.26% Senior Notes, due 2014, payable in annual installments of $1,818 beginning 2004 20,000 20,000 Medium term notes Series A, 1995-1, 6.67%, due 2025 10,000 10,000 Series A, 1995-2, 6.27%, due 2010 10,000 10,000 Series A, 1995-3, 6.20%, due 2000 2,000 2,000 Unsecured 6.09% Note, due November 1998 - 40,000 Unsecured 6.75% Debentures, due 2028 150,000 150,000 First Mortgage Bonds Series J, 9.40% due 2021 17,000 17,000 Series N, 8.69% due 2000 1,000 3,000 Series P, 10.43% due 2017 22,500 25,000 Series Q, 9.75% due 2020 20,000 20,000 Series R, 11.32% due 2004 10,720 12,860 Series T, 9.32% due 2021 18,000 18,000 Series U, 8.77% due 2022 20,000 20,000 Series V, 7.50% due 2007 10,000 10,000 Rental property, propane and other term notes due in installments through 2013 14,808 21,168 -------- -------- Total long-term debt 395,331 456,331 Less current maturities (17,848) (57,783) -------- -------- $377,483 $398,548 ======== ======== 53 Most of the Senior Notes and First Mortgage Bonds contain provisions that allow the Company to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The Senior Note agreements and First Mortgage Bond indentures provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1988 may not exceed the sum of accumulated net income for periods after December 31, 1988 plus $15.0 million. At September 30, 1999, approximately $44.8 million of retained earnings was unrestricted. As of September 30, 1999, all of the Greeley Division utility plant assets with a net book value of approximately $173.7 million are subject to a lien under the 9.4% Series J First Mortgage Bonds assumed by the Company in the acquisition of Greeley Gas Company. Also, substantially all of the United Cities Division utility plant assets, totaling approximately $293.0 million, are subject to a lien under the Indenture of Mortgage of the Series N through V First Mortgage Bonds. Based on the borrowing rates currently available to the Company for debt with similar terms and remaining average maturities, the fair value of long-term debt at September 30, 1999 and 1998 is estimated, using discounted cash flow analysis, to be $387.7 million and $489.0 million, respectively. It is not currently advantageous for the Company to refinance its long-term debt because of costs of prepayment required in the various debt agreements. Maturities of long-term debt at September 30, 1999 are as follows (in thousands): 2000 $ 17,848 2001 15,434 2002 15,323 2003 20,995 2004 17,656 Thereafter 308,075 -------- $395,331 ======== Short-term debt At September 30, 1999, short-term debt was composed of $152.7 million of commercial paper and $15.6 million outstanding 54 under bank credit facilities. At September 30, 1998, it was composed of $66.4 million outstanding under bank credit facilities. The weighted average interest rate on short-term borrowings outstanding was 5.7% and 6.2% at September 30, 1999 and 1998, respectively. Committed credit facilities The Company has two short-term committed credit facilities. The committed lines are renewed or renegotiated at least annually. One short-term unsecured credit facility from a group of 10 banks is for $250.0 million. This facility expires in August 2000. No balance was outstanding under this facility at September 30, 1999 or 1998. This facility requires a commitment fee of .08% on the unused portion. A second facility is for $12.0 million with a single bank. This facility expires April 1, 2000. It requires a commitment fee of .05% on the unused portion. Borrowings totaling $12.0 million were outstanding under this facility at both September 30, 1999 and 1998. Uncommitted credit facilities The Company also has unsecured short-term uncommitted credit lines from two banks totaling $74.0 million. Borrowings under uncommitted credit facilities totaled $3.6 million and $54.4 million at September 30, 1999 and 1998, respectively. These uncommitted lines expire in May and August 2000, and are renewed or renegotiated at least annually. The uncommitted lines have varying terms and the Company pays no fee for the availability of the lines. Borrowings under these lines are made on a when and as-available basis at the discretion of the banks. Commercial paper program The Company implemented a $250.0 million commercial paper program in October 1998. It is supported by the $250.0 million committed line of credit described above. The Company's commercial paper was rated A-2 by Standard and Poor's and P-2 by Moody's. A total of $152.7 million of commercial paper was outstanding at September 30, 1999. 55 5. Income taxes The components of income tax expense for 1999, 1998 and 1997 are as follows: 1999 1998 1997 --------- -------- -------- (In thousands) Current Federal $(18,761) $31,694 $ 7,917 State (4,081) 4,503 1,000 Deferred Federal 27,370 (3,352) 4,807 State 5,321 (616) 1,000 Investment tax credits (294) (423) (426) -------- ------- ------- $ 9,555 $31,806 $14,298 ======== ======= ======= Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that give rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 1999 and 1998 are presented below: 56 1999 1998 ---------- ---------- (In thousands) Deferred tax assets: Costs expensed for book purposes and capitalized for tax purposes $ 629 $ 1,049 Accruals not currently deductible for tax purposes 12,657 7,189 Customer advances 4,535 3,730 Nonqualified benefit plans 7,947 11,297 Postretirement benefits 10,356 10,093 Unamortized investment tax credit 1,304 1,427 Regulatory liabilities 3,159 3,175 Tax net operating loss and credit carryforwards 12,504 - Other, net 4,787 2,838 --------- --------- Total deferred tax assets 57,878 40,798 Deferred tax liabilities: Difference in net book value and net tax value of assets (139,324) (114,229) Pension funding (5,480) (4,120) Gas cost adjustments 3,997 8,943 Regulatory assets (4,462) (4,941) Cost capitalized for book purposes and expensed for tax purposes (19,112) - Other, net (6,107) (6,664) --------- --------- Total deferred tax liabilities (170,488) (121,011) --------- --------- Net deferred tax liabilities $(112,610) $ (80,213) ========= ========= SFAS No. 109 deferred accounts for rate regulated entities (included in other deferred credits) $ 1,896 $ 1,548 ========= ========= 57 Reconciliations of the provisions for income taxes computed at the statutory rate to the reported provisions for income taxes for 1999, 1998 and 1997 are set forth below: 1999 1998 1997 ------- -------- -------- (In thousands) Tax at statutory rate of 35% $9,555 $30,474 $13,348 Common stock dividends deductible for tax reporting (701) (695) (706) State taxes 841 2,526 1,300 Other, net (140) (499) 356 ------ ------- ------- Provision for income taxes $9,555 $31,806 $14,298 ====== ======= ======= The Company has net operating loss carryforwards amounting to $23.9 million which will expire in the year 2019. The Company also has tax credit carryforwards amounting to $4.1 million, the majority of which represent alternative minimum tax credits which do not expire. 6. Contingencies Litigation Trans La Division In November 1997, a jury in Plaquemine, Louisiana awarded Brian L. Heard General Contractor, Inc., ("Heard") a total of approximately $178,000 in actual damages and $15 million in punitive damages resulting from a lawsuit by Heard against the Trans La Division, the successor in interest to Oceana Heights Gas Company, which the Company acquired in November 1995. The trial judge also awarded interest on the total judgment amount. The claims were for events that occurred prior to the time Atmos acquired Oceana Heights Gas Company. Heard filed the suit against the Trans La Division and two other defendants, alleging that gas leaks had caused delays in Heard's completion of a sewer project, resulting in lost business opportunities for the contractor during 1994. The Company immediately appealed the verdict. However, on March 24, 1999, the Company announced that it had reached a settlement of the case as a result of mediation discussions. The parties agreed to settle the case for $3.5 million. In the settlement, neither Atmos nor the Trans La Division conceded liability. Atmos paid $3.25 million and the remaining $.25 million was paid by Oceana Heights Gas Company's insurers. In exchange, the Company obtained a full release from Heard of all claims against Atmos and the Trans La Division. 58 Greeley Division In Colorado, the Greeley Division is a defendant in several lawsuits filed as a result of a fire in a building in Steamboat Springs, Colorado on February 3, 1994. The plaintiffs claimed that the fire resulted from a leak in a severed gas service line owned by the Greeley Division. On January 12, 1996, the jury awarded the plaintiffs approximately $2.5 million in compensatory damages and approximately $2.5 million in punitive damages. The jury assessed the Company with liability for all of the damages awarded. The Company appealed the judgment to the Colorado Court of Appeals, which reversed the trial court verdict and ordered a new trial. The Colorado Supreme Court upheld the Court of Appeals reversal and order for a new trial. As a result of mediation, a settlement was reached with five of the claimants, leaving only three remaining claimants with aggregate claims of approximately $2 million. The Company does not expect the final outcome of this case to have a material adverse effect on the financial condition, the results of operations or the cash flows of the Company because the Company believes it has adequate insurance and reserves to cover any damages that may ultimately be awarded. On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto, against more than 200 companies in the natural gas industry, including the Company and the Greeley Gas Division. The plaintiffs, who purport to represent a class consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, accuse the defendants of underpaying royalties on gas taken from wells situated on non-federal and non- Indian lands throughout the United States and offshore waters predicated upon allegations that the defendants' gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they do contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. Since the filing of the petition, this case has been removed to the United States District Court in Wichita, Kansas, where there are numerous and various motions pending, including a request for remand by the plaintiffs as well as a notice filed to consolidate this case with other similar pending litigation in federal court in Wyoming in which the Company is also a defendant along with over 200 other defendants, the case of Jack J. Grynberg, on behalf of the United States of America. 59 The Company believes that the plaintiffs' claims are lacking in merit and intends to vigorously defend this action. However, the Company cannot assess, at this time, the likelihood of whether or not the plaintiffs may prevail on any one or more of their asserted claims. In any event, the Company does not expect the final outcome of this case to have a material adverse effect on the financial condition, the results of operations or the net cash flows of the Company because the Company believes that it has adequate reserves to cover any damages that may ultimately be awarded. The Company is a party to other litigation matters and claims that arise out of the ordinary business of the Company. While the results of these litigation matters and claims cannot be predicted with certainty, the Company does not believe the final outcome of such litigation and claims will have a material adverse effect on the financial condition, the results of operations or the cash flows of the Company because the Company believes that it has adequate insurance and reserves to cover any damages that may ultimately be awarded. Guarantees The Company's wholly-owned subsidiary, Atmos Energy Marketing, LLC ("AEM"), and Woodward Marketing, Inc. ("WMI"), sole members of Woodward Marketing, LLC ("WMLLC"), act as guarantors of up to $12.5 million of balances outstanding under a $30.0 million bank credit facility for WMLLC. AEM guarantees the payment of up to $5.6 million of borrowings under this facility. No balance was outstanding under this credit facility at September 30, 1999. AEM and WMI also act as joint and several guarantors on payables of WMLLC up to $40.0 million of natural gas purchases and transportation services from suppliers. WMLLC payable balances outstanding that were subject to these guarantees amounted to $18.8 million at September 30, 1999. 60 Environmental Matters The United Cities Division is the owner or previous owner of manufactured gas plant sites in Keokuk, Iowa; Johnson City and Bristol, Tennessee; and Hannibal, Missouri, which were used to supply gas prior to availability of natural gas. The gas manufacturing process resulted in certain by-products and residual materials including coal tar. The manufacturing process used by the Company was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, the Company may be responsible for response actions with respect to such materials, if response actions are necessary. As of September 30, 1999, the Company had accrued and deferred for recovery $1.1 million, including $258,000 that was incurred for an insurance recoverability study, and $750,000 for the investigations of the Johnson City and Bristol, Tennessee and Hannibal, Missouri sites. As of September 30, 1999, the Company has incurred costs of approximately $492,000 for these sites. Iowa sites In June 1995, UCGC entered into an agreement to pay $1.8 million to Union Electric Company, now Ameren, whereby Union Electric agreed to assume responsibility for UCGC's continuing investigation and environmental response action obligations as outlined in the feasibility study related to a former manufactured gas plant in Keokuk. The $1.8 million was paid in five annual installments, with the last installment being paid in July 1999. In a rate case effective June 1, 1996, UCGC began collecting increased rates which included a 10-year amortization of the $1.8 million payment to Union Electric. Tennessee sites UCGC and the Tennessee Department of Environment and Conservation entered into a consent order effective January 23, 1997, for the purpose of facilitating the investigation, removal and remediation of the Johnson City site. UCGC began the implementation of the consent order in the first quarter of 1997 which continued throughout fiscal year 1999. The Company is unaware of any information which suggests that the Bristol site gives rise to a present health or environmental risk as a result of the manufactured gas process or that any response action will be necessary. 61 The Tennessee Regulatory Authority granted UCGC permission to defer, until its next rate case, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements. Missouri sites On July 22, 1998, Atmos entered into an Abatement Order on Consent with the Missouri Department of Natural Resources addressing the former manufactured gas plant located in Hannibal, Missouri. Atmos, through its United Cities Division, agreed in the order to perform a removal action, a subsequent site evaluation and to reimburse the response costs incurred by the state of Missouri in connection with the property. The removal action was conducted and completed in August 1998 and the site evaluation field work was conducted in August 1999. On March 9, 1999, the Missouri Public Service Commission issued an Order authorizing Atmos to defer the costs associated with this site until the next rate increase, which must be proposed before March 9, 2001. Kansas sites Atmos is currently conducting investigation and remediation activities pursuant to Consent Orders between the Kansas Department of Health and Environment ("KDHE") and UCGC. The Orders provide for the investigation and remediation of mercury contamination at gas pipeline sites which utilize or formerly utilized mercury meter equipment in Kansas. As of September 30, 1999, the Company had identified approximately 720 sites where mercury may have been used and had incurred $100,000 for recovery. In addition, based upon available current information, the Company accrued and deferred for recovery an additional $280,000 for the investigation of these sites. The Kansas Corporation Commission has authorized the Company to defer these costs and seek recovery in a future rate case. The Company is a party to other environmental matters and claims that arise out of the ordinary business of the Company. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, the Company does not believe the final outcome of such response actions will have a material adverse effect on the financial condition, the results of operations or the cash flows of the Company because the Company believes that the expenditures related to such response actions will either be recovered through rates, shared with other parties, or covered by adequate insurance or reserves. 62 7. Common stock and stock options Shareholders' Rights Plan On November 12, 1997, the Board of Directors approved a new Rights Agreement to become effective upon the expiration of the then existing Rights Agreement on May 10, 1998. Under the Rights Agreement, each right ("Right") will entitle the holder thereof, until May 10, 2008 or the date of redemption of the Rights, to buy one share of Common Stock of the Company at the exercise price of $80.00, subject to adjustment. At no time will the Rights have any voting rights. The exercise price payable and the number of shares of Common Stock or other securities or property issuable upon exercise of the Rights are subject to adjustment from time to time to prevent dilution. At the date upon which the rights become separate from the Company's Common Stock (the "Distribution Date"), the Company will issue one right with each share of Common Stock that becomes outstanding so that all shares of Common Stock will have attached Rights. After the Distribution Date, the Company may issue Rights when it issues Common Stock if the Board deems such issuance to be necessary or appropriate. The Rights will separate from the Common Stock and a Distribution Date will occur upon the occurrence of certain events specified in the Agreement, including but not limited to, the acquisition by certain persons of at least 15% of the beneficial ownership of the Company's Common Stock. The Rights have certain anti-takeover effects and may cause substantial dilution to a person or entity that attempts to acquire the Company on terms not approved by the Board of Directors except pursuant to an offer conditioned upon a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by the Board of Directors because, prior to the time that the Rights become exercisable or transferable, the Rights may be redeemed by the Company at $.01 per Right. 63 Shares issued under various plans The following table presents the number of shares issued under various plans in 1999 and 1998, as well as the number of shares available for future issuance at September 30, 1999. Shares available for issuance at Shares issued September 30, 1999 1998 1999 -------- ------ --------- Restricted Stock Grant Plan 56,850 114,250 731,400 Employee Stock Ownership Plan 89,435 52,473 370,963 Direct Stock Purchase Plan 694,905 531,353 273,312 Outside Directors Stock-For-Fee Plan 1,841 2,306 40,538 United Cities Long-Term Stock Plan 6,450 55,500 188,050 Long-Term Incentive Plan - - 1,175,000 Restricted Stock Grant Plan The Company's Restricted Stock Grant Plan ("Plan") for management and key employees of the Company, which became effective October 1, 1987 and was amended and restated in November 1997, provides for awards of common stock that are subject to certain restrictions. The Plan is administered by the Board of Directors. The members of the Board who are not employees of the Company make the final determinations regarding participation in the Plan, awards under the Plan, and restrictions on the restricted stock awarded. The restricted stock may consist of previously issued shares purchased on the open market or shares issued directly from the Company. During 1998, the Company increased the number of shares of its common stock that may be issued under the plan by 650,000 shares. Compensation expense of $1,595,000, $1,238,000 and $437,000 was recognized in 1999, 1998 and 1997, respectively, in connection with the vesting of shares awarded under the Plan. Employee Stock Ownership Plan Prior to January 1, 1999, Atmos had an Employee Stock Ownership Plan ("ESOP") and the United Cities Division had a 401(k) savings plan. The ESOP was amended effective January 1, 1999, as is more fully discussed in Note 8. 64 Direct Stock Purchase Plan The Company also has a Direct Stock Purchase Plan ("DSPP"). Participants in the DSPP may have all or part of their dividends reinvested at a 3% discount from market prices. DSPP participants may purchase additional shares of Company common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000. Outside Directors Stock-For-Fee Plan In November 1994, the Board adopted the Outside Directors Stock-for-Fee Plan, which was approved by the shareholders of the Company in February 1995 and was amended and restated in November 1997. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash. Stock-Based Compensation Plans The Company has two stock-based compensation plans that provide for the granting of stock options to officers, key employees and non-employee directors. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives, and promoting the success of the Company by providing employees the opportunity to acquire common stock. United Cities Long-Term Stock Plan Prior to the merger with Atmos, certain United Cities Gas Company officers and key employees participated in the United Cities Long-Term Stock Plan implemented in 1989. At the time of the merger on July 31, 1997, Atmos adopted this plan by registering a total of 250,000 shares of Atmos stock to be issued under the Long-Term Stock Plan for the United Cities Division. Under this plan, incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock or any combination thereof may be granted to officers and key employees of the United Cities Division. Options granted under the plan become exercisable at a rate of 20% per year and expire 10 years after the date of grant. During 1999, 6,450 options were exercised under the plan. At September 30, 1999, there were 80,150 options outstanding, of which 56,850 options had vested. No incentive stock options, nonqualified stock options, stock appreciation rights, or restricted stock have been granted under the plan since 1996. 65 Long-Term Incentive Plan On August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (the "LTIP"), which became effective October 1, 1998. The LTIP represents a part of the Company's Total Rewards strategy, which the Company developed as a result of a study it conducted of all employee, executive and non-employee director compensation and benefits. The LTIP is a comprehensive, long-term incentive compensation plan, providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to help attract, retain, and reward employees and non-employee directors of the Company and its subsidiaries. The Company is authorized to grant awards for up to a maximum of 1,500,000 shares of common stock under the LTIP, subject to certain adjustment provisions. The option price is equal to the market price of the Company's stock at the date of grant. The stock options expire in 10 years from the date of the grant, and options vest annually over a service period ranging from one to three years. During 1999, no options were exercised under the plan. At September 30, 1999, the Company had 325,000 options outstanding under the LTIP at an exercise price ranging from $24.41 to $25.66. In October 1995, Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation," was issued. This statement establishes a fair value-based method of accounting for employee stock options or similar equity instruments and encourages, but does not require, all companies to adopt that method of accounting for all of their employee stock compensation plans. SFAS 123 allows companies to continue to measure compensation cost for employee stock options or similar equity instruments using the intrinsic value method of accounting described in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). The Company has elected to continue using the intrinsic value method as prescribed by APB 25. Under this method no compensation cost for stock options is recognized for stock option awards granted at or above fair market value. Because of the limited nature of the Company's stock-based compensation plans, the pro forma effects of applying SFAS 123 would have less than a $.01 per diluted share effect on earnings per share or approximately $84,000 for 1999. 66 8. Employee retirement and stock ownership plans Defined benefit plans Prior to January 1, 1999, the Company had four defined benefit pension plans, covering the Western Kentucky Division employees, the Greeley Division employees, the United Cities Division employees, and the fourth covering all other Atmos employees. The plans provided similar benefits to all employees, which were based upon years of service and the highest paid five consecutive calendar years of compensation within the last 10 years of employment. Effective January 1, 1999, the plans were merged into the Western Kentucky Gas plan, which was amended and restated as the Atmos Pension Account Plan which covers all employees of the Company. Opening account balances were established for participants as of January 1, 1999 equal to the present value of their respective accrued benefits under the pension plans as of December 31, 1998. The Pension Account Plan credits an allocation to each participant's account at the end of each year according to a formula based on the participant's age, service and total pay (excluding incentive pay). The Pension Account Plan provides for an additional annual allocation based upon a participant's age as of January 1, 1999 for those participants who were participants in the prior pension plans. The plan will credit this additional allocation each year through December 31, 2008. In addition, at the end of each year, a participant's account will be credited with interest on the employee's prior year account balance. A special grandfather benefit also applies through December 31, 2008, for participants who were at least age 50 as of January 1, 1999, and who were participants in one of the prior plans on December 31, 1998. Participants are fully vested in their account balances after five years of service and may choose to receive their account balances as a lump sum or an annuity. The obligations shown herein reflect the changes which were effective January 1, 1999. The Company's funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. 67 In the 1998 annual report the defined benefit plans were grouped with the Supplemental Executive Benefits Plans. In the 1999 annual report they are presented separately. The Company records the accrued pension asset in deferred charges and other assets. The following table sets forth the total for the Pension Account Plan's funded status for 1999 and 1998: 1999 1998 -------- -------- (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $218,245 $217,152 Service cost 4,232 5,256 Interest cost 14,696 15,655 Curtailments/special termination benefits - (2,645) Plan amendments - (14,605) Actuarial (gain)loss (21,390) 10,638 Benefits paid (15,318) (13,206) -------- -------- Benefit obligation at end of year 200,465 218,245 Change in plan assets: Fair value of plan assets at beginning of year 286,708 259,851 Actual return on plan assets 11,108 40,063 Benefits paid (15,318) (13,206) -------- -------- Fair value of plan assets at end of year 282,498 286,708 -------- -------- Funded status 82,033 68,463 Unrecognized transition asset (625) (873) Unrecognized prior service cost (9,680) (10,382) Unrecognized net gain (48,780) (45,616) -------- -------- Accrued pension asset $ 22,948 $ 11,592 ======== ======== 68 1999 1998 1997 ----- ----- ----- Weighted average assumptions for end of year disclosure: Discount rate 7.5% 7.0% 7.5% Rate of compensation increase 4.0% 4.0% 4.0% Expected return on plan assets 10.0% 9.0% 9.0% The plan assets consist primarily of investments in common stocks, interest bearing securities and interests in commingled pension trust funds. Net periodic pension cost for the Pension Account Plan for 1999, 1998 and 1997 included the following components: 1999 1998 1997 -------- -------- -------- (In thousands) Components of net periodic pension cost: Service cost $ 4,232 $ 5,256 $ 6,640 Interest cost 14,696 15,655 15,301 Expected return on assets (27,846) (23,249) (19,730) Amortization of: Transition obligation(asset) (248) (241) (431) Prior service cost (703) 851 921 Actuarial (gain) (1,487) (1,225) - -------- -------- -------- Net periodic pension cost (11,356) (2,953) 2,701 Curtailment (gain)loss and special termination benefits - (1,840) 4,758 -------- -------- -------- Total pension cost accruals $(11,356) $ (4,793) $ 7,459 ======== ======== ======== Supplemental Executive Benefits Plans The Company has a nonqualified Supplemental Executive Benefits Plan ("Supplemental Plan") which provides additional pension, disability and death benefits to the officers and certain other employees of the Company. The Supplemental Plan was amended and restated in August 1998. In addition, in August 1998, the Company adopted the Performance-Based Supplemental Executive Benefits Plan, which will cover all employees who become officers or business unit presidents after August 12, 1998. 69 The Company records accrued pension cost in deferred credits and other liabilities. The following table sets forth the total for the Supplemental Plans' funded status for 1999 and 1998: 1999 1998 -------- -------- (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 36,770 $ 30,796 Service cost 1,151 505 Interest cost 2,488 2,246 Plan amendments - 565 Actuarial (gain)loss 331 4,389 Benefits paid (1,915) (1,731) -------- -------- Benefit obligation at end of year 38,825 36,770 Change in plan assets: Fair value of plan assets at beginning of year - - Employer contribution 1,915 1,731 Benefits paid (1,915) (1,731) -------- -------- Fair value of plan assets at end of year - - -------- -------- Funded status (38,825) (36,770) Unrecognized transition asset 484 580 Unrecognized prior service cost 8,837 9,858 Unrecognized net loss 6,886 6,772 -------- -------- Accrued pension cost $(22,618) $(19,560) ======== ======== 70 1999 1998 1997 ---- ---- ---- Weighted average assumptions for end of year disclosure: Discount rate 7.5% 7.0% 7.5% Rate of compensation increase 4.0% 4.0% 4.0% Expected return on plan assets 10.0% 9.0% 9.0% Assets for the Supplemental Plans are held in the Company's rabbi trusts (see Note 13) and consist primarily of investments in equity mutual funds. The market value of the rabbi trusts amounted to $26.1 million at September 30, 1999. The assets in the rabbi trusts are included on the Company's balance sheet under deferred charges and other assets and not presented above as plan assets. The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the Supplemental Plans with accumulated benefit obligations in excess of plan assets were $38.8 million, $32.8 million, and none, respectively, as of September 30, 1999, and $36.8 million, $31.4 million, and none, respectively, as of September 30, 1998. Net periodic pension cost for the Supplemental Plans for 1999, 1998 and 1997 included the following components: 1999 1998 1997 ------ ------ ------ (In thousands) Components of net periodic pension cost: Service cost $1,151 $ 505 $ 263 Interest cost 2,488 2,246 1,932 Expected return on assets - - - Amortization of: Transition obligation (asset) 96 96 96 Prior service cost 1,022 810 810 Actuarial (gain) loss 216 133 390 ------ ------ ------ Net periodic pension cost $4,973 $3,790 $3,491 ====== ====== ====== Employee Stock Ownership Plan Atmos sponsors an ESOP for all employees of the Company. Effective January 1, 1999 the ESOP was amended to provide for deferral of a portion of a participant's salary of up to 21%. In addition, among other changes to the ESOP, participants are provided with automatic matching contributions of 100% of each 71 participant's salary reduction up to 4% of the participant's salary, and are provided the option of taking out loans against their ESOP accounts, subject to certain restrictions. Each participant enters into a salary reduction agreement with the Company pursuant to which the participant's salary is reduced by an amount not more than 21%. Taxes on the amount by which the participant's salary is reduced are deferred pursuant to Section 401(k) of the Internal Revenue Code. The amount of the salary reduction is contributed by the Company to the ESOP for the account of the participant. Matching contributions to the ESOP were expensed as incurred and amounted to $2.4 million, $1.8 million, and $2.1 million for 1999, 1998 and 1997, respectively. The directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code of 1986 and applicable regulations of the Internal Revenue Service. No discretionary contributions were made for 1999 and 1998. 401(k) savings plan Prior to January 1, 1999, the Company sponsored a 401(k) savings plan for the United Cities Division employees. The Company made fixed matching contributions of $102,000 for the three months ended December 31, 1998, $648,000 for the nine months ended September 30, 1998, and $694,000 for the year ended December 31, 1997. In addition, a discretionary matching contribution of $227,000 was made for 1998. The 401(k) savings plan was merged into the ESOP effective January 1, 1999, and the United Cities Division employees subsequently receive the same benefits as other Atmos employees. 9. Other postretirement benefits Prior to January 1, 1999, Atmos sponsored two postretirement plans other than pensions. Each provided health care benefits to retired employees. One provided benefits to the United Cities Division retirees and the other provided medical benefits to all other retired Atmos employees. Effective January 1, 1999, the United Cities plan was merged into the Atmos plan and began providing benefits to future retirees that are essentially the same as provided to other Atmos employees. The obligations as of September 30, 1999 and 1998 reflect this plan change. Substantially all of the Company's employees become eligible for these benefits if they reach retirement age while working for the Company and attain certain specified years of service. In addition, participant contributions are required under the plan. 72 The Company records the accrued postretirement cost primarily in deferred credits and other liabilities. The following table sets forth the total liability currently recognized for the postretirement plan other than pensions: 1999 1998 -------- -------- (In thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 64,494 $ 53,295 Service cost 2,150 1,659 Interest cost 4,360 3,809 Plan participants' contributions 763 382 Curtailments/special termination benefits - 2,125 Plan amendments - 1,888 Actuarial (gain)loss (10,195) 6,210 Benefits paid (4,740) (4,874) -------- -------- Benefit obligation at end of year 56,832 64,494 Change in plan assets: Fair value of plan assets at beginning of year 6,380 5,614 Actual return on plan assets 377 295 Employer contribution 7,184 4,963 Plan participants' contribution 763 382 Benefits paid (4,740) (4,874) -------- -------- Fair value of plan assets at end of year 9,964 6,380 -------- -------- Funded status (46,868) (58,114) Unrecognized transition obligation 21,732 23,243 Unrecognized prior service cost 3,094 3,614 Unrecognized net (gain)loss (2,300) 8,571 -------- -------- Accrued postretirement cost $(24,342) $(22,686) ======== ======== 73 1999 1998 1997 ---- ---- ---- Weighted average assumptions for end of year disclosure: Discount rate 7.5% 7.0% 7.5% Expected return on plan assets 5.3% 5.3% 5.3% Initial trend rate 9.0% 9.0% 7.5% Ultimate trend rate 5.0% 4.5% 5.0% Number of years from initial to ultimate trend 5 6 3 Net periodic postretirement cost for the combined postretirement benefit plans for 1999, 1998 and 1997 included the following components: 1999 1998 1997 ------- ------- ------- (In thousands) Components of net periodic postretirement cost: Service cost $ 2,150 $ 1,659 $ 1,772 Interest cost 4,360 3,809 3,467 Expected return on assets (349) (235) (225) Amortization of: Transition obligation(asset) 1,511 1,862 1,994 Prior service cost 520 269 202 Actuarial (gain)loss 648 (58) 4 ------- ------- ------- Net periodic postretirement cost 8,840 7,306 7,214 Curtailment (gain)loss and special termination benefits - 5,915 3,043 ------- ------- ------- Total postretirement cost accruals $ 8,840 $13,221 $10,257 ======= ======= ======= Assumed health care cost trend rates have a significant effect on the amounts reported for the plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations: 74 1-Percentage 1-Percentage Point Increase Point Decrease -------------- -------------- (In thousands) Effect on total of service and interest cost components $ 603 $ (591) Effect on postretirement benefit obligation $6,361 $(5,378) The Company is currently recovering other postretirement benefits ("OPEB") costs through its regulated rates under SFAS No. 106 accrual accounting in Colorado, Kansas, the majority of its Texas service area and Kentucky. It receives rate treatment as a cost of service item for OPEB costs on the pay-as- you-go basis in Louisiana. OPEB costs have been specifically addressed in rate orders in each jurisdiction served by the United Cities Division or have been included in a rate case and not disallowed. However, the Company was required to recover the portion of the UCGC transition obligation applicable to Virginia operations over 40 years, rather than 20 years, as in other states. Management believes that accrual accounting in accordance with SFAS No. 106 is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses. 10. Earnings per share Basic earnings per share has been computed by dividing net income for the period by the weighted average number of common shares outstanding during the period. Diluted earnings per share has been computed by dividing net income for the period by the weighted average number of common shares outstanding during the period adjusted for restricted stock and other contingently issuable shares of common stock. Net income for the years ended September 30, 1999, 1998 and 1997 for basic and diluted earnings per share are the same, as there were no contingently issuable shares of stock whose issuance would have impacted net income. A reconciliation between basic and diluted weighted average common shares outstanding at September 30 follows: 75 1999 1998 1997 ------ ------ ------ (In thousands) Weighted average common shares - basic 30,566 29,822 29,409 Effect of dilutive securities: Restricted stock 238 199 13 Stock options 15 10 - ------ ------ ------ Weighted average common shares - diluted 30,819 30,031 29,422 ====== ====== ====== 11. Statement of cash flows supplemental disclosures Supplemental disclosures of cash flow information for 1999, 1998 and 1997 are presented below. 1999 1998 1997 ------- ------- ------- (In thousands) Cash paid (received) for Interest $40,446 $29,980 $25,216 Income taxes $(7,184) $25,598 $ 9,736 12. Segment Information In fiscal 1999, the Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS No. 131"). SFAS No. 131 established standards for the way that public business enterprises report information about operating segments in annual financial statements and requires that those enterprises report selected information about operating segments in interim financial reports issued to shareholders. The determination of reportable segments under SFAS No. 131 differs from that required in previous years; therefore, business segment information for 1998 and 1997 has been restated to comply with the provisions of SFAS No. 131. The Company's determination of reportable segments considers the strategic operating units under which the Company manages sales of various products and services to customers in differing regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. All intersegment sales prices are market based. The Company evaluates performance based on net income or loss of the respective operating units. 76 In accordance with SFAS No. 131, the Company has identified the Utility, Propane and Energy Services segments, as described in Note 1. Summarized financial information concerning the Company's reportable segments is shown in the following table: Energy Utility Propane Services Total ---------- -------- -------- ---------- (In thousands) As of and for the year ended September 30, 1999: - ------------------- Operating revenues $ 621,211 $22,944 $53,416 $ 697,571 Intersegment revenues 3,898 - 3,477 7,375 Depreciation and amortization 52,503 2,954 1,417 56,874 Operating income (loss) 49,000 (543) 5,782 54,239 Equity in earnings of unconsolidated investment - - 7,156 7,156 Interest charges, net 35,799 1,231 33 37,063 Net income (loss) 10,800 (869) 7,813 17,744 Total assets 1,152,469 16,694 77,933 1,247,096 Equity investment in unconsolidated investee - - 15,973 15,973 Expenditures for additions to long- lived assets 108,454 1,550 349 110,353 77 Energy Utility Propane Services Total -------------- -------- -------- --------- As of and for the (In thousands) year ended September 30, 1998: - ------------------- Operating revenues 739,930 29,091 80,672 849,693 Intersegment revenues 1,485 - - 1,485 Depreciation and amortization 43,324 2,324 1,907 47,555 Operating income 100,665 619 11,595 112,879 Equity in earnings of unconsolidated investment - - 3,920 3,920 Interest charges, net 33,181 897 1,501 35,579 Net income (loss) 43,332 (66) 11,999 55,265 Total assets 1,061,496 36,549 68,252 1,166,297 Equity investment in unconsolidated investee - - 11,914 11,914 Expenditures for additions to long- lived assets 125,741 8,408 840 134,989 As of and for the year ended September 30, 1997: - ------------------- Operating revenues 807,428 33,194 68,389 909,011 Intersegment revenues 2,176 - - 2,176 Depreciation and amortization 40,750 2,117 2,390 45,257 Operating income 61,213 405 4,991 66,609 Equity in earnings of unconsolidated investment - - 3,254 3,254 Interest charges, net 30,882 744 1,969 33,595 Net income (loss) 19,739 (90) 4,189 23,838 Total assets 1,014,263 23,110 69,083 1,106,456 Equity investment in unconsolidated investee - - 9,962 9,962 Expenditures for additions to long- lived assets 117,496 3,271 1,545 122,312 78 The following table presents a reconciliation of the operating revenues to total consolidated revenues for the years ended September 30, 1999, 1998 and 1997. 1999 1998 1997 -------- -------- -------- (In thousands) Total revenues for reportable segments $697,571 $849,693 $909,011 Elimination of intersegment revenues (7,375) (1,485) (2,176) -------- -------- -------- Total operating revenues $690,196 $848,208 $906,835 ======== ======== ======== A reconciliation of total assets for the reportable segments to total consolidated assets for September 30, 1999, 1998 and 1997 is presented below. 1999 1998 1997 ---------- ---------- ---------- (In thousands) Total assets for reportable segments $1,247,096 $1,166,297 $1,106,456 Elimination of intercompany receivables (16,559) (24,907) (18,145) ---------- ---------- ---------- Total consolidated assets $1,230,537 $1,141,390 $1,088,311 ========== ========== ========== The following table summarizes the Company's revenues by products and services for the year ended September 30. 79 1999 1998 1997 ---------- ---------- ---------- (In thousands) Gas sales revenues: Residential $ 349,691 $ 410,538 $ 452,864 Commercial 144,836 184,046 193,302 Public authority and other 22,330 20,504 23,898 Industrial 73,194 91,972 109,241 ---------- ---------- ---------- Total gas sales revenues 590,051 707,060 779,305 Transportation revenues 23,035 23,883 19,804 Other gas revenues 4,227 7,502 6,143 ---------- ---------- ---------- Total utility revenues 617,313 738,445 805,252 Propane revenues 22,944 29,091 33,194 Energy services revenues 49,939 80,672 68,389 ---------- ---------- ---------- Total operating revenues $ 690,196 $ 848,208 $ 906,835 ========== ========== ========== 13. Marketable Securities In accordance with Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities," all marketable securities are classified as available-for-sale and are reported at market value with unrealized gains and losses shown as a component of shareholders' equity labeled "unrealized holding gains (losses)." All marketable securities are held in rabbi trusts for the Supplemental Executive Benefit Plan ("SEBP"). 80 The cost, unrealized holding gain (loss), and the market value of the marketable securities are: Unrealized Holding Market Cost Gain (Loss) Value ------- ----------- ------- (In thousands) As of September 30, 1999 Available-for-sale securities: Domestic equity mutual funds $22,265 $1,041 $23,306 Foreign equity mutual funds 2,359 399 2,758 ------- ------ ------- $24,624 $1,440 $26,064 ======= ====== ======= 14. Leases The Company has entered into non-cancelable operating leases for office and warehouse space used in its operations. The remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. The Company has also entered into capital leases for division offices and operating facilities. Property, plant and equipment included amounts for capital leases of $4.6 million and $4.1 million at September 30, 1999 and 1998, respectively. Accumulated depreciation for these capital leases totaled $1.2 million and $.9 million at September 30, 1999 and 1998, respectively. 81 The related future minimum lease payments at September 30, 1999 were as follows: Capital Operating leases leases -------- --------- (In thousands) 2000 $ 735 $10,413 2001 735 10,010 2002 735 9,811 2003 735 9,262 2004 735 9,091 Thereafter 3,384 48,211 ------- ------- Total minimum lease payments 7,059 $96,798 ======= Less amount representing interest (3,671) ------- Present value of net minimum lease payments $ 3,388 ======= Consolidated lease and rental expense amounted to $10.6 million, $9.2 million and $10.5 million for fiscal 1999, 1998 and 1997, respectively. Rents for the regulated business are expensed and the Company receives rate treatment as a cost of service on a pay-as-you-go basis. 15. Related Party Transactions Included in purchased gas cost were purchases from WMLLC of $117.4 million, $124.7 million and $103.0 million in 1999, 1998 and 1997, respectively. Volumes purchased were 50.9 billion cubic feet ("Bcf"), 53.4 Bcf and 38.6 Bcf in 1999, 1998 and 1997, respectively. These purchases were made in a competitive open bidding process and reflect market prices. Average prices per thousand cubic feet ("Mcf") for gas purchased from WMLLC were $2.31, $2.33 and $2.67 in 1999, 1998 and 1997, respectively. 16. Subsequent Event Subsequent to September 30, 1999, the Company entered into a definitive agreement with Southwestern Energy Company ("Southwestern") to acquire the Missouri natural gas distribution assets of Associated Natural Gas, a division of Arkansas Western Gas, which is a wholly-owned subsidiary of Southwestern. Under the terms of the agreement, the Company will purchase the Missouri gas system for $32.0 million in cash plus working capital adjustments. This transaction, which will 82 add approximately 48,000 customers, is expected to be completed by mid-year 2000, subject to approvals by the Missouri Public Service Commission and the Federal Energy Regulatory Commission. 17. Selected Quarterly Financial Data (Unaudited) Summarized unaudited quarterly financial data are presented below. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The Company's natural gas and propane distribution businesses are seasonal due to weather conditions in the Company's service areas. For further information on its effects on quarterly results, please see the "Seasonality" discussion included in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section herein.
Fiscal year 1999 ------------------------------------------------------- Quarter ended December 31, March 31, June 30, September 30, ------------------------------------------------------- (In thousands, except per share data) Operating revenues $210,227 $261,426 $109,590 $108,953 Gross profit 91,208 112,395 53,376 42,815 Operating income (loss) 31,688 50,843 412 (28,704) Net income (loss) 15,380 28,795 (5,295) (21,136) Net income (loss) per share .50 .94 (.17) (.68) Fiscal year 1998 ------------------------------------------------------- Quarter ended December 31, March 31, June 30, September 30, ------------------------------------------------------- (In thousands, except per share data) Operating revenues $295,331 $288,550 $137,311 $127,016 Gross profit 99,601 123,971 57,366 50,898 Operating income (loss) 40,952 67,203 7,882 (3,158) Net income (loss) 20,122 37,398 1,676 (3,931) Net income (loss) per share .68 1.25 .06 (.13)
83 EX-21 6 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 SUBSIDIARIES OF ATMOS ENERGY CORPORATION Name State of Percent of Incorporation Stock ATMOS ENERGY SERVICES, INC. Delaware 100% GREELEY ENERGY SERVICES, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Delaware 100% TRANS LOUISIANA ENERGY SERVICES, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Delaware 100% UNITED CITIES ENERGY SERVICES, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Delaware 100% WKG ENERGY SERVICES, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Delaware 100% TRANS LOUISIANA INDUSTRIAL GAS COMPANY, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Louisiana 100% EGASCO, LLC (a Texas Limited Liability Company) (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Texas 100% ENERTRUST, INC. (a wholly-owned subsidiary of Atmos Energy Services, Inc.) Delaware 100% ENERMART ENERGY SERVICES TRUST (a Pennsylvania Business Trust) (wholly-owned by Enertrust, Inc.) Pennsylvania 100% ENERGAS ENERGY SERVICES TRUST (a Pennsylvania Business Trust) (wholly-owned by Enertrust, Inc.) Pennsylvania 100% Name State of Percent of Incorporation Stock UNITED CITIES PROPANE GAS, INC. Tennessee 100% ATMOS ENERGY MARKETING, LLC (a Delaware Limited Liability Company) Delaware 100% ATMOS LEASING, INC. Georgia 100% ATMOS NON-REGULATED SHARED SERVICES, INC. Delaware 100% ATMOS STORAGE, INC. Delaware 100% UCG STORAGE, INC. (a wholly-owned subsidiary of Atmos Storage, Inc.) Delaware 100% WKG STORAGE, INC. (a wholly-owned subsidiary of Atmos Storage, Inc.) Delaware 100% ATMOS EXPLORTATION AND PRODUCTION, INC. (a wholly-owned subsidiary of Atmos Storage, Inc.) Delaware 100% EX-23 7 CONSENT OF ERNST & YOUNG LLP Exhibit 23 CONSENT OF INDEPENDENT AUDITOR We consent to the incorporation by reference in the Registration Statements (Form S-3, No. 33-37869; Form S-3 D/A, No. 33-70212; Form S-3, No. 33-58220; Form S-3, No. 33-56915; Form S-3/A, No. 333-03339; Form S-3/A, No. 333-32475; Form S-3/A, No. 333-50477; Form S-4, No. 333-13429; Form S-8, No. 33-68852; Form S-8, No. 33-57687; Form S-8, No. 33-57695; Form S-8, No. 333-32343; and Form S-8, No. 333-46337, Form S-8, No. 333-73143; and Form S-8, No. 333-73145) of Atmos Energy Corporation and in the related Prospectuses of our report dated November 9, 1999, with respect to the consolidated financial statements of Atmos Energy Corporation incorporated by reference in this Annual Report (Form 10-K) for the year ended September 30, 1999. Our audits also included the financial statement schedule of Atmos Energy Corporation listed in Item 14(a). This schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. ERNST & YOUNG LLP Dallas, Texas December 14, 1999 EX-27 8 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF ATMOS ENERGY CORPORATION FOR THE YEAR ENDED SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR SEP-30-1999 SEP-30-1999 PER-BOOK 965,782 0 135,153 129,602 0 1,230,537 156 293,359 84,148 377,663 0 0 377,483 15,650 0 152,654 17,848 0 3,035 353 285,851 1,230,537 690,196 9,555 635,957 645,512 44,684 10,123 54,807 37,063 17,744 0 17,744 33,882 11,807 84,698 0.58 0.58
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