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 (Fee Required) For the fiscal year ended September 30, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required) For the transition period from __________ to ____________ Commission File Number 1-10042 ATMOS ENERGY CORPORATION (Exact name of registrant as specified in its charter) TEXAS 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: (214) 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 ___. 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 $301,605,820 as of December 1, 1995. On December 1, 1995, the registrant had 15,900,392 shares of common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of registrant's definitive proxy statement filed for the annual meeting of shareholders on February 14, 1996 are incorporated by reference into Part III. 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. Immediate- ly following the transfer of such business, which had been opera- ted by Pioneer and its predecessors since 1906, Pioneer distrib- uted 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. The Company distributes and sells natural gas to residential, commercial, industrial, agricultural, and other customers in 414 cities, towns, and communities in parts of Texas, Louisiana, Kentucky, Colorado, Kansas, and Missouri. The Company also transports gas for others through parts of its distribution system. The Company is also helping promote the development of a market for natural gas as a clean burning vehicular fuel by opening six public refueling facilities in its service areas. The Company's Texas distribution system is operated through its Energas Company division (the "Energas Division") and is located in the western part of Texas covering an area having a population of approximately 950,000 people. The economy of the area is based primarily on oil and gas production and agricul- ture. The principal cities served by the Energas Division include Amarillo, Lubbock, Midland, and Odessa. At September 30, 1995, the Company had 310,765 gas 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 is located in Louisiana covering 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, 1995, the Company had 70,570 gas 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 Paducah. At September 30, 1995, the Company had 168,529 gas meters in service in Kentucky. In December 1993, the Company acquired Greeley Gas Company ("GGC") of Denver, Colorado in a merger accounted for as a pool- 1 ing of interests, and accordingly, all amounts included herein have been restated to include GGC's operating results. Since the merger, the business of GGC has been operated through the Company's Greeley Gas Company division (the "Greeley Gas Division"). It serves customers in areas of Colorado, Kansas, and Missouri having a combined population of approximately 228,000 people. The economies of the areas served are based on oil and gas production, agriculture and resort business in Colorado. The principal cities served include Greeley, Durango and Lamar, Colorado and Bonner Springs, Herington and Ulysses, Kansas. At September 30, 1995 the Greeley Gas Division had 108,250 meters in service. The natural gas distribution industry is subject to numerous special factors, many of which affect the Company from time to time. These include (i) 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 in local gas distribution service areas; (iii) competition from alternate fuels; (iv) competition with other gas sources for industrial customers, including bypass of 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. ACQUISITIONS 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, and Greeley Gas Company ("GGC") in December 1993. Subsequent to September 30, 1995, the Company acquired Oceana Heights Gas Company ("Oceana") of Thibodaux, Louisiana. Oceana provides natural gas service to approximately 9,200 customers. The Company continues to consider and pursue, where appropriate, additional acquisitions of natural gas distribution properties and other business opportunities. For further information regarding acquisitions, see Note 2 of notes to consolidated financial statements, and Management's Discussion and Analysis of Financial Condition and Results of Operations. FIVE-YEAR OPERATING STATISTICS Certain information with respect to the Company's natural gas operations for the past five years is shown on the following page. 2 Year ended September 30, --------------------------------------------------------- 1995 1994 1993 1992 1991 -------- -------- -------- -------- -------- NUMBER OF ACCOUNTS, at end of year Residential 551,269 549,129 539,309 534,762 529,498 Commercial 55,894 55,027 54,275 55,562 54,703 Industrial (including agricultural) 8,331 8,781 8,924 9,331 9,793 Public authority and other 3,377 3,351 3,267 1,745 1,788 ------- ------- ------- ------- ------- Total 618,871 616,288 605,775 601,400 595,782 ======= ======= ======= ======= ======= METERS IN SERVICE, at end of year 658,114 649,319 636,159 630,365 619,111 ======= ======= ======= ======= ======= METERS IN SERVICE, average 656,259 646,165 635,074 631,130 618,736 ======= ======= ======= ======= ======= HEATING DEGREE DAYS, system average (1) Actual 3,579 3,953 4,046 3,676 3,583 Normal 3,983 3,983 3,983 3,983 3,983 Percent of normal 90% 99% 102% 92% 90% SALES VOLUMES - MMcf (2) Residential 46,765 51,209 51,763 48,223 47,484 Commercial 19,756 21,134 21,872 20,675 20,778 Industrial (including agricultural) 38,046 38,502 31,367 27,489 29,788 Public authority and other 4,779 5,242 4,403 3,333 3,385 ------- ------- ------- ------- ------- Total 109,346 116,087 109,405 99,720 101,435 TRANSPORTATION VOLUMES - MMcf (2) 30,463 35,308 39,782 32,203 35,201 ------- ------- ------- ------- ------- TOTAL VOLUMES HANDLED - MMcf (2) 139,809 151,395 149,187 131,923 136,636 ======= ======= ======= ======= ======= OPERATING REVENUES (000's) Gas Revenues Residential $210,165 $245,931 $237,914 $211,767 $202,486 Commercial 79,982 92,507 91,250 82,311 81,414 Industrial (including agricultural 110,815 119,722 92,455 77,218 81,746 Public authority and other 18,185 22,463 18,315 13,232 13,290 -------- -------- -------- -------- -------- Total gas revenues 419,147 480,623 439,934 384,528 378,936 Transportation Revenues 11,711 14,118 15,013 13,674 16,348 Other Revenue 4,962 5,067 4,694 5,151 4,383 -------- -------- -------- -------- -------- Total operating revenues $435,820 $499,808 $459,641 $403,353 $399,667 ======== ======== ======== ======== ======== AVERAGE SALES PRICE/Mcf Residential $4.49 $4.80 $4.60 $4.39 $4.26 Commercial 4.05 4.38 4.17 3.98 3.92 Industrial (including agricultural) 2.91 3.11 2.95 2.81 2.74 Public authority and other 3.81 4.29 4.16 3.97 3.93 Total 3.83 4.14 4.02 3.86 3.74 AVERAGE COST OF GAS/Mcf SOLD 2.46 2.86 2.71 2.58 2.58 See footnotes on page 4. 3 SALES AND STATISTICAL DATA BY STATE - 1995 Year ended September 30, 1995 ---------------------------------------------------------------- Texas Louisiana Kentucky Colorado Kansas Mo. Total ------- --------- -------- -------- ------ --- ------- METERS IN SERVICE, at end of year Residential 265,192 64,612 149,567 69,865 24,225 519 573,980 Commercial 24,893 4,937 16,989 9,862 3,284 71 60,036 Industrial (including agricultural) 18,130 115 447 98 326 - 19,116 Public authority and other 2,550 906 1,526 - - - 4,982 ------- ------ ------- ------ ------ --- ------- Total 310,765 70,570 168,529 79,825 27,835 590 658,114 ======= ====== ======= ====== ====== === ======= HEATING DEGREE DAYS, system average (1) Actual 3,152 1,448 3,792 6,243 5,093 5,044 3,579 Normal 3,528 1,760 4,376 6,556 5,158 5,028 3,983 Percent of normal 89% 82% 87% 95% 99% 100% 90% SALES VOLUMES (2) Residential 22,338 3,163 11,949 7,007 2,265 43 46,765 Commercial 7,300 1,183 5,276 4,905 1,081 11 19,756 Industrial (including agricultural) 23,875 1,864 9,992 725 1,590 - 38,046 Public authority and other 2,547 789 1,443 - - - 4,779 ------ ----- ------ ------ ----- -- ------ Total 56,060 6,999 28,660 12,637 4,936 54 109,346 TRANSPORTATION VOLUMES (2) 9,571 490 17,103 3,180 119 - 30,463 ------ ----- ------ ------ ----- -- ------- TOTAL VOLUMES HANDLED (2) 65,631 7,489 45,763 15,817 5,055 54 139,809 ====== ===== ====== ====== ===== == ======= OTHER STATISTICS Operating revenues (000's) $207,149 $38,716 $117,154 $51,199 $21,254 $348 $435,820 Gross plant (000's) $245,173 $93,677 $142,699 $73,216 $40,000 $594 $595,359 Net plant (000's) $138,479 $70,899 $87,705 $41,995 $23,772 $402 $363,252 Miles of pipe 13,090 1,863 3,509 2,400 1,318 32 22,212 Employees (3) 833 161 383 204 65 - 1,646 Communities served 92 37 163 62 58 2 414 Estimated population in service area 950,000 250,000 680,000 160,000 66,000 2,000 2,108,000 Estimated square miles in service area 30,000 7,000 12,000 1,050 580 20 50,650 Vehicles in fleet 452 144 295 169 53 - 1,113 Franchises 72 58 63 34 42 2 271 (1) 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 coldness of wea- ther experienced and to compare relative temperatures be- tween one geographic area and another. 4 (2) Volumes are reported as metered in million cubic feet ("MMcf"). (3) The Texas column includes 223 and 224 employees in the Dallas general office in 1995 and 1994, respectively. 5 SALES AND STATISTICAL DATA BY STATE - 1994 Year ended September 30, 1994 --------------------------------------------------------------- Texas Louisiana Kentucky Colorado Kansas Mo. Total ------- ------ ------- ------ ------ --- ------- METERS IN SERVICE, at end of year Residential 263,330 64,401 146,384 67,062 23,692 546 565,415 Commercial 24,899 4,944 16,653 9,594 3,228 71 59,389 Industrial (including agricultural) 18,749 108 268 108 333 - 19,566 Public authority and other 2,518 908 1,523 - - - 4,949 ------- ------ ------- ------ ------ --- ------- Total 309,496 70,361 164,828 76,764 27,253 617 649,319 ======= ====== ======= ====== ====== === ======= HEATING DEGREE DAYS, system average (1) Actual 3,561 1,922 4,342 6,116 5,108 4,990 3,953 Normal 3,528 1,760 4,376 6,556 5,158 5,028 3,983 Percent of normal 101% 109% 99% 93% 99% 99% 99% SALES VOLUMES (2) Residential 24,276 3,604 13,776 7,041 2,464 48 51,209 Commercial 7,933 1,260 5,820 4,943 1,167 11 21,134 Industrial (including agricultural) 25,791 1,606 8,766 734 1,605 - 38,502 Public authority and other 2,714 885 1,643 - - - 5,242 ------ ----- ------ ----- ----- -- ------ Total 60,714 7,355 30,005 12,718 5,236 59 116,087 TRANSPORTATION VOLUMES (2) 14,179 500 17,498 3,071 60 - 35,308 ------ ----- ------ ------ ----- -- ------- TOTAL VOLUMES HANDLED (2) 74,893 7,855 47,503 15,789 5,296 59 151,395 ====== ===== ====== ====== ===== == ======= OTHER STATISTICS Operating revenues (000's) $234,628 $43,374 $143,508 $55,010 $22,880 $408 $499,808 Gross plant (000's) $221,516 $86,771 $127,169 $70,852 $36,819 $565 $543,692 Net plant (000's) $119,616 $66,220 $79,410 $40,355 $21,446 $360 $327,407 Miles of pipe 13,007 1,815 3,425 2,352 1,295 33 21,927 Employees (3) 859 166 387 221 76 - 1,709 Communities served 92 36 163 62 58 2 413 Estimated population in service area 950,000 250,000 680,000 160,000 66,000 2,000 2,108,000 Estimated square miles in service area 30,000 7,000 12,000 1,050 580 20 50,650 Vehicles in fleet 446 137 268 154 52 - 1,057 Franchises 71 58 62 36 42 2 271 See footnotes on page 4. 6 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's management believes that the Company 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 these changing markets. In certain instances, customers purchase gas directly from others 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 may offset the loss of gross profit. The Company's distribution systems have experienced aggregate peak day deliveries of approximately 1 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 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 and January 1994. GGC has not curtailed deliveries to its sales customers since prior to 1980. 7 GAS SUPPLY The principal gas suppliers to the Company in 1995, 1994 and 1993 included Westar Transmission Company ("Westar"), an affil- iate of KNEnergy; Anthem Energy Company, L.P. ("Anthem"), an affiliate of KNEnergy; Mesa Operating Company ("Mesa"); Louisiana Intrastate Gas Corporation ("LIG"), an affiliate of Equitable Resources Inc.; Tennessee Gas Pipeline Company ("Tennessee Gas"), an affiliate of Tenneco, Inc.; Texas Gas Transmission Corporation ("Texas Gas"), an affiliate of The Williams Companies, Inc.; Texaco Gas Marketing; Union Pacific Fuels; Vastar, an affiliate of ARCO; Associated Natural Gas, Inc. ("ANGI"), an affiliate of Panhandle Eastern Corporation; and Astra Resources Marketing, Inc. ("Astra"), an affiliate of Western Resources, Inc. The prices paid by the Company for natural gas delivered to it are set by contracts with gas suppliers and/or ratemaking proceedings before regulatory authorities. Charges for gas costs are passed through to the Company's customers under approved or negotiated tariffs or pursuant to contract. 8 The following table sets forth volumes purchased from the Company's principal gas suppliers for the years ended September 30, 1995, 1994, and 1993. Volumes purchased (MMcf as metered) 1995: Associated Natural Gas, Inc. 7,077 Astra Resources Marketing, Inc. 2,565 Chevron 2,154 Hadson Gas 2,902 LIG 2,698 Mesa 9,369 Texaco Gas Marketing 8,427 Union Pacific Fuels 5,298 Vastar 3,490 Westar and Anthem 43,950 1994: Associated Natural Gas, Inc. 3,283 Astra Resources Marketing, Inc. 2,210 LIG 4,254 Mesa 9,926 Texaco Gas Marketing 5,453 Union Pacific Fuels 5,825 Vastar 6,881 Westar and Anthem 47,842 1993: Associated Natural Gas, Inc. 3,291 Astra Resources Marketing, Inc. 1,946 LIG 4,490 Mesa 10,659 Tennessee Gas 2,575 Texas Gas 10,329 Westar and Anthem 45,031 Westar and Anthem supply natural gas to most of the Energas Division under multiple contracts. The Westar contract expires in 1998. The Anthem contracts are renegotiated annually. Westar purchases gas from various pipeline companies and natural gas processing plants and at the wellhead. Westar's gas price to the Company is subject to an annual adjustment in accordance with the existing contract. The principal gas supply for the Company's Amarillo, Texas distribution system is furnished by Mesa under a long-term con- tract that expires upon the depletion of the field from which the gas is produced. Mesa owns the gas rights in certain specified acreage in the West Panhandle field. Pursuant to a contract between Colorado Interstate Gas Company ("CIG") and Mesa, CIG is obligated to deliver to Mesa the volumes of gas required for sale to customers in Amarillo and its environs, subject to certain contractual volume limitations, so long as the gas reserves from the West Panhandle field are commercially producible. The price 9 under the contract is determined each year pursuant to a formula until December 1997. The contract also provides a mechanism for price redetermination each two year period thereafter beginning January 1, 1998. On October 28, 1991, the Company and LIG entered into new agreements which were approved by the Louisiana Public Service Commission ("Louisiana Commission") on November 26, 1991, and became effective June 1, 1992. These agreements provide continued supply by LIG for most of the Trans La Division's gas requirements for a term of ten years (but subject to cancellation by either party after five years). The agreements provide for market sensitive pricing and allow the Company to purchase certain volumes of gas from other suppliers. LIG is required to provide standby service to back up the purchases from the other suppliers. The Company's Louisiana industrial sales subsidiary, Trans Louisiana Industrial Gas Company, Inc., purchases some gas supplies for resale to certain of its Louisiana industrial customers from suppliers other than LIG. The Western Kentucky Division requirements are delivered by Texas Gas and Tennessee Gas with the exception of a small percentage of the requirements being purchased directly from intrastate producers. The Western Kentucky Division purchases its supply under staggered term contracts from major producers and marketers including Texaco, Union Pacific, Vastar, Associated Natural, Hadson and Chevron. The Company's distribution system in the Western Kentucky Division includes six underground storage facilities, which are used to help meet customer requirements during peak demand per- iods and to reduce the need to contract for additional pipeline capacity to meet such peak demand periods. See "Item 2. Proper- ties" for further information regarding the underground storage facilities. The Company also contracted for storage service in underground storage facilities of Tennessee Gas and Texas Gas under FERC Order No. 636. The Greeley Gas Division purchases or transports approximat- ely 82% of its natural gas requirements on eight pipelines. Five of these are regulated by the FERC and the remaining three are state regulated. The FERC pipelines are Colorado Interstate Gas Company, Williams Natural Gas Company, KNEnergy, Northwest Pipe- line Corporation, and NorAm. The state regulated pipelines are Public Service Company of Colorado, Western Resources, Inc. and Kansas Pipeline Partnership in Kansas. Approximately 18% of the Divisions's gas supply is purchased from local sources. Several of the operating areas are in or adjacent to natural gas produc- ing fields. Associated Natural Gas, Inc. is the main supplier to the Greeley Gas Division's largest district, the Greeley District. 10 Astra is the principal gas supplier for the Kansas and Missouri districts. Gas is transported through three different pipeline systems (Williams Natural Gas, Western Resources, Inc. and NorAm). The Company has not experienced supply curtailment in its Texas distribution system since it began independent operations in 1983, in its Louisiana system since its acquisition, or in Colorado, Kansas or Missouri since prior to 1980. A large proportion of the Company's sales are made to high priority residential and commercial consumers; therefore, any curtailment of supply for these customers is unlikely. REGULATION AND RATES Regulation. 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 ("Railroad Commission") 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. The Trans La Division is regulated by the Louisiana Commis- sion, 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. 11 The Western Kentucky Division is regulated by the Kentucky Public Service Commission ("Kentucky Commission"), which regulates utility services, rates, issuances 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 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. The Greeley Gas Division is regulated by the Colorado Public Utilities Commission ("Colorado Commission"), the Kansas Corporation Commission, and the Missouri Public Service Commis- sion 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 Gas Division's wholesale gas suppliers are regulated by various federal and state commissions. 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. Rates. Approximately 87% of the Company's revenues in fis- cal 1995 was derived from sales at rates set by or subject to approval by local or state authorities. The method of determin- ing regulated rates varies among the six states in which the Company operates. For the most part, the regulatory bodies which establish the Company's rates have not yet instituted widespread "incentive regulation" or "performance based rates." Generally, the Company applies for a specific rate structure based upon requirements of the regulatory authority. 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 a reasonable return on invested capital. 12 Substantially all of the sales rates charged by the Company to its customers fluctuate with the cost of gas purchased by the Company. Base 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. 13 The following table sets forth the major rate requests made by the Company and the action taken on such requests: Effective Amount Amount Jurisdiction Date Requested Received ------------ --------- --------- -------- Texas West Texas System 11/01/84 $8,915,000 $5,000,000 09/09/91 5,987,000 4,600,000 11/18/94 2,581,000 1,702,000 (a) Amarillo 12/11/85 4,850,000 3,400,000 11/25/92 4,398,000 2,130,000 Louisiana 04/01/87 5,195,000 3,610,000 09/03/92 3,409,000 974,000 (b,c) 03/01/93 (c) 730,000 (c) 03/01/94 (c) 1,058,000 (c) 03/01/95 (c) 1,071,000 (c) Kentucky 05/29/91 8,973,000 3,632,000 11/01/95 7,665,000 2,300,000 (d) 03/01/96 1,000,000 (d) Colorado 05/09/85 1,651,000 1,575,000 11/06/90 2,677,000 1,405,000 05/01/94 4,527,000 3,246,000 Kansas 07/28/83 1,214,000 1,003,000 11/14/86 934,000 844,000 10/22/90 2,485,000 1,376,000 01/06/92 1,495,000 505,000 12/01/93 2,604,000 2,088,000 Missouri 06/01/90 N/A (e) 49,000 - -------------- (a) The increase includes $200,000 applicable to areas outside the city limits which became effective in January 1995. (b) The September 1992 rate order provided for recovery of an additional $800,000 for franchise tax expense. (c) The September 1992 rate order also approved a Rate Stabilization Clause ("RSC") for three years which provided for an annual adjustment of rates to reflect changes in expenses and investment. The RSC provided the Company the opportunity to earn a return on common equity between 11.75% and 12.25%. (d) The Kentucky rate order provided an increase of $2,300,000, lowered depreciation rates effective November 1, 1995 and 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. (e) The Company applied for relief under alternative rate request procedures in Missouri which do not require a specific dollar request amount. 14 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, electrici- ty. Competition for the residential and commercial customers is increasing. Promotional incentives, improved equipment efficien- cies, and promotional rates all contribute to the acceptability of electric equipment. Beginning in 1985, changes in the federal regulatory environment through 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, the FERC's Order 636 was implemented by the interstate pipelines in the Company's service territories. The FERC policies apply only to interstate pipelines and have not had a direct impact upon the Company's operations which are primarily supplied by intrastate pipelines. However, the Company has felt the impact of increased competitiveness in the large volume market in some areas result- ing from these changes. The Company has sought regulatory approvals for competitive pricing on a case by case basis. The Company has opened six public retail facilities for the sale of compressed natural gas ("CNG") for vehicular use. The most recent of these were opened in Owensboro, Kentucky in April 1995 and at West Texas A&M University in Canyon, Texas in August 1995. Prior to that time, the Company provided CNG for vehicular use only in limited situations (such as for school buses in cer- tain school districts and for the fleet vehicles of certain busi- nesses). With the opening of these public refueling stations the Company began competing with gasoline for vehicular fuel sales. All of these facilities, except those at West Texas A&M, are located at existing local gasoline stations. Employees At September 30, 1995, the Company employed 1,646 persons. See page 4 for number of employees by state. ITEM 2. PROPERTIES The Company owns an aggregate of 22,212 miles of underground pipelines throughout its gas distribution systems. These pipe- lines are located on easements or rights-of-way granted to the Company, which generally provide for perpetual use. The Company maintains its pipelines through a program of continuous inspection and repair and believes that the pipeline system is in good condition. The Company also owns or operates six under- 15 ground gas storage facilities in Kentucky that have a total storage capacity of approximately 10.7 Bcf. However, approximately 6.5 Bcf of gas in the storage facilities must be retained as cushion gas. The maximum daily delivery capability of the storage facilities is approximately 109 MMcf. Substantially all of the Company's properties in its Greeley Gas Division with a recorded value of approximately $66.2 million are subject to a lien under First Mortgage Bonds assumed by the Company in the acquisition of GGC. At September 30, 1995, the lien secured approximately $17.0 million of outstanding 9.4% Series J First Mortgage Bonds due May 1, 2021. The Company has leased its administrative offices in Dallas, Texas under two leases. In 1995 one lease was renegotiated which will allow for the consolidation of its office space. The Company also maintains field offices throughout its distribution system, substantially all of which are located in leased pre- mises. The Company holds franchises granted by the incorporated cities and towns and by each Louisiana parish that it serves. At September 30, 1995, the Company held 271 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 See Note 10 of notes to consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 16 EXECUTIVE OFFICERS The following table sets forth certain information as of September 30, 1995, regarding the executive officers of the Company: Name Age Office Currently Held ---- --- --------------------- Robert F. Stephens 47 President and Chief Operating Officer, Director James F. Purser 45 Executive Vice President and Chief Financial Officer, Director J. Charles Goodman 34 Executive Vice President of Corporate Operations H.F. Harber 53 Senior Vice President of Corporate Services Donald E. James 48 Senior Vice President of Public Affairs Mary S. Lovell 44 Senior Vice President of Utility Services Glen A. Blanscet 38 Vice President, General Counsel and Corporate Secretary Robert F. Stephens was named President and Chief Operating Officer and was appointed to the Board of Directors in February 1995. He previously served as Executive Vice President - Corporate Operations from May 1989 through February 1995, as Senior Vice President, Corporate Operations from January 1988 until May 1989 and as Senior Vice President, Corporate Services from April 1986 until January 1988, and as Vice President, Corporate Development and Regulatory Affairs from August 1984 until April 1986. James F. Purser was appointed to the Board of Directors in February 1995. He was named Executive Vice President and Chief Financial Officer in May 1989. He previously served as Senior Vice President and Chief Financial Officer from August 1988 until May 1989 and as Vice President from September 1986 until August 1988. J. Charles Goodman was named Executive Vice President, Corporate 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 from February 1989 until February 1993. H.F. Harber was named Senior Vice President - Corporate Services in August 1993. He previously served as Vice President, Human Resources and Administration from July 1991 to August 1993, and as Vice President, Human Resources from May 1990 to July 1991. 17 Donald E. James was named Senior Vice President - Public Affairs in May 1995. He previously served as Senior Vice President and General Counsel from January, 1994 to May, 1995, as Senior Vice President - General Counsel and Corporate Secretary from May 1993 until August 1993, as Senior Vice President and General Counsel from May 1989 until May 1993, as Vice President and General Counsel from January 1986 until May 1989, as Assistant Vice President and General Counsel from August 1985 until January 1986, and as Assistant Vice President and Assistant General Counsel from February 1984 until August 1985. Mary S. Lovell was named Senior Vice President, Utility Services in May, 1995. She previously served as Vice President, Rates and Regulatory Affairs from August 1990 to May 1995, as Vice President, Rates from February 1989 to August 1990, as Operating Companies Senior Vice President, Rates from October 1988 until February 1989 and as System Vice President, Rates from May 1988 until October 1988. Glen A. Blanscet was named Vice President, General Counsel and Corporate Secretary in May 1995. He previously served as Assistant General Counsel and Corporate Secretary from January, 1994 to May, 1995, and as Assistant General Counsel from July 1988 to December 1993. 18 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER 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, as adjusted for the 3-for-2 stock split in May 1994, for fiscal 1995 and 1994 are listed below. 1995 1994 ---------------------------------- --------------------------------- Dividends Dividends High Low paid High Low paid Quarter ended: --------- --------- --------- -------- -------- --------- December 31 $18 $15 7/8 $ .23 $21 1/8 $16 3/4 $ .22 March 31 18 1/2 16 1/8 .23 20 17 3/4 .22 June 30 20 1/4 17 1/2 .23 20 1/4 18 .22 September 30 20 5/8 19 .23 19 16 3/8 .22 ----- ----- $ .92 $ .88 ===== ===== Prior to its acquisition, GGC made distributions to its shareholders in fiscal 1994 of $120,000. The "Dividends paid" information above has not been restated for the pooling of interests in December 1993, but reflects historical cash dividends paid per share of Atmos common stock as restated for the 3-for-2 stock split in May 1994. See Note 3 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, 1995 was 23,625. 19 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected financial data with respect to the Company and should be read in conjunction with the consolidated financial statements included herein. Year ended September 30, -------------------------------------------- 1995 1994 1993 1992 1991 -------- -------- -------- -------- -------- (In thousands, except per share data) Operating revenues $435,820 $499,808 $459,641 $403,353 $399,667 ======== ======== ======== ======== ======== Net income $ 18,873 $ 14,679 $ 17,544 $ 10,998 $ 9,612 ======== ======== ======== ======== ======== Net income per share $ 1.22 $ .97 $ 1.22 $ .80 $ .71 ======== ======== ======== ======== ======== Cash dividends per share $ .92 $ .88 $ .85 $ .83 $ .80 ======== ======== ======== ======== ======== Total assets at end of year $445,783 $416,678 $391,618 $358,363 $338,714 ======== ======== ======== ======== ======== Long-term debt at end of year $131,303 $138,303 $105,853 $112,153 $116,461 ======== ======== ======== ======== ======== Supplemental net income (1) $ 18,132 $ 10,570 $ 10,130 ======== ======== ======== Supplemental net income per share (1) $ 1.26 $ .77 $ .75 ======== ======== ======== (1) Supplemental net income reflects results if GGC had not made an S Corporation election in 1987. 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION The Company distributes and sells natural gas to residential, commercial, industrial and agricultural customers in six states. Such business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the Company operates. In addition, the Company's business is affected by seasonal weather patterns, competitive factors within the energy industry, and economic conditions in the areas that the Company serves. RATE ACTIVITY On February 10, 1995, the Company filed with the Kentucky Commission for a rate increase for its Western Kentucky Gas Company Division. The filing requested an annual revenue in- crease of approximately $7.7 million, or 5.5 percent. In July 1995 a settlement agreement was filed with the Kentucky Commission. The Company withdrew from the settlement on August 31, 1995, after the Kentucky Commission issued an order that made modifications which the Company found unacceptable. The Company and all intervenors filed a revised settlement, which was approved by the Kentucky Commission without modifications on October 20, 1995, effective November 1, 1995. The order issued by the Kentucky Commission authorizes the Company to increase its rates by $2.3 million annually, and by an additional $1.0 million annually beginning in March 1996. The settlement includes a decrease in depreciation rates, recovery of expenses related to adoption of SFAS No. 106 and includes a provision for the Company to begin a three-year demand-side management pilot program for the 1996-97 heating season, which could cost up to $450,000 annually, resulting in a total operating income increase of approximately $4.0 million. The Company provides natural gas service to approximately 168,000 customers in Kentucky. In September 1994, the Company filed to increase revenues by approximately $2.6 million for a portion of its Energas Company service area, which includes approximately 217,000 customers. The Company requested recovery of accrual accounting for post- retirement benefits in accordance with SFAS No. 106. See Note 8 of the accompanying notes to consolidated financial statements for SFAS No. 106 information. In November 1994, the Company implemented an annual revenue increase of approximately $1.5 million affecting approximately 195,000 customers located inside the city limits of towns in this portion of its Energas Division. Upon approval of the Railroad Commission of Texas in January 1995, the Company implemented an annual increase of approximately $.2 million relating to the 22,000 remaining rural customers. GGC filed a request for an increase in annual revenues of $4.5 million with the Colorado Public Utility Commission in 21 September, 1993. On May 1, 1994, the Company implemented an annual increase of $3.2 million or 6.9% in Phase I of this proceeding. The Phase I rates reflect recovery of SFAS No. 106 expenses with external funding, consistent with the recommended decision of the presiding administrative law judge. In October 1994, the Colorado Commission issued its order affirming the increase as set forth in Phase I. In March 1995, the Greeley Gas Division filed Phase II in the rate proceeding, which addressed rate structure. In September 1995 all parties to the proceeding entered into a stipulation and agreement which became final in November 1995 upon the recommendation by an administrative law judge of the Colorado Commission. Effective December 1, 1993, GGC received an annual rate increase of approximately $2.1 million or 10.6% in its Kansas service area. The increase reflects recovery of SFAS No. 106 expenses with external funding and a moratorium on rate requests in Kansas until December 1, 1996. On February 11, 1992, the Company filed a rate case with the city of Amarillo, Texas seeking to increase annual revenues by approximately $4.4 million, or 12%. In June 1992 the city denied the Company's request for rate relief and the Company appealed to the Railroad Commission. In November 1992, the Railroad Commission issued its decision resulting in a total annual increase of $2.1 million. The Company and the city requested a rehearing of the Order. On January 11, 1993, the Railroad Commission denied rehearing to both parties. In February 1993, the city appealed the Railroad Commission's rate order to the District Court of Travis County, Texas. In January 1994, the District Court denied the city's appeal. The city appealed to the Court of Appeals. On March 1, 1995 the Austin Court of Appeals issued its decision affirming the Railroad Commission's 1993 Amarillo Rate Order in all respects. The Texas Supreme Court has declined to review the case. During the period of 1991 through 1993, the Company also filed for and received other rate increases in certain other rate jurisdictions in its Energas Division totaling approximately $.3 million annually. In September 1992, the Louisiana Commission issued a rate order for the Company's Louisiana service area, which included a rate stabilization clause ("RSC") for three years that provides for an annual adjustment to the Company's rates to reflect changes in expenses, revenues and invested capital following an annual review. The RSC provides an opportunity for a return on jurisdictional common equity of between 11.75% and 12.25%. As a result of the Company's filings under the RSC, an increase of $730,000 annually or 2% went into effect on March 1, 1993, an increase of $1.1 million annually or 2.7% went into effect on March 1, 1994, and the third increase of $1.1 million annually or 2.0% went into effect on March 6, 1995. The Company expects to have a hearing before the Louisiana Commission on extending the rate stabilization mechanism. 22 ACQUISITIONS The Company has expanded its customer base and sought to diversify the regulations, weather patterns and local economic conditions to which it is subject through acquisitions in 1986, 1987 and 1993. The Company continues to consider and pursue, where appropriate, additional acquisitions of natural gas distribution properties and other business opportunities. In December 1993, the Company acquired Greeley Gas Company ("GGC") of Denver, Colorado in a merger transaction accounted for as a pooling of interests; therefore, all historical financial statements and notes thereto have been restated to retroactively reflect this merger. At that time, GGC was a privately held company providing natural gas service to nearly 100,000 customers in 122 communities in Colorado, Kansas and a small service area in Missouri. The transaction was structured to be a tax-free reorganization. The Company exchanged 2,329,330 shares of its common stock before the 3-for-2 stock split (3,493,995 shares on a post-split basis) for all of the outstanding stock of GGC. For further information regarding the merger, see Note 2 of notes to consolidated financial statements. Subsequent to September 30, 1995, the Company acquired privately held Oceana Heights Gas Company ("Oceana") of Thibodaux, Louisiana. Oceana provides natural gas service to approximately 9,200 customers and is located adjacent to a system in LaFourche Parish that was acquired by Atmos in 1994. The transaction will be accounted for as a pooling of interests. The outstanding shares of Oceana Heights capital stock were converted into shares of Atmos common stock having a market value equal to the $6.4 million purchase price. The Louisiana Commission's approval included regulatory and rate making terms acceptable to Atmos. Although significant for the Trans La Division's opera- tions which currently serve over 70,000 customers in Louisiana, the transaction is not expected to have a material impact on the Company's financial condition and results of operations. The acquisition is consistent with the Company's long-standing corporate development strategy. RESULTS OF OPERATIONS YEAR ENDED SEPTEMBER 30, 1995 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1994 Operating revenues decreased 13% to $435.8 million in 1995 from $499.8 million in 1994 due to weather that was 9% warmer than in 1994 and a 14% decrease in the average cost of gas per thousand cubic feet ("Mcf") sold. Average gas sales revenues per Mcf decreased from 1994 by $.31 to $3.83 in 1995, while the average cost of gas per Mcf sold decreased $.40 to $2.46 in 1995. The number of meters in service increased to 658,114 at September 30, 1995 compared with 649,319 at September 30, 1994. Sales to weather sensitive residential, commercial and public authority 23 customers decreased approximately 6.3 billion cubic feet ("Bcf") in 1995 while sales to industrial and agricultural customers decreased approximately .5 Bcf. Total sales volumes decreased 5.8% to 109.3 Bcf in 1995, as compared with 1994. Revenues from gas transported for others decreased $2.4 million to approximately $11.7 million in fiscal 1995 due to a decrease in volumes transported of 4.8 Bcf to 30.5 Bcf in 1995. Gross profit decreased by approximately 1% to $167.0 million in 1995 from $168.2 million in 1994. The primary factor contributing to the lower gross profit was lower volumes sold and transported due to warmer weather. The effect of warmer weather on gross profit was substantially reduced by implementing rate increases totaling $2.8 million and $6.4 million in 1995 and 1994, respectively. Operating expenses, excluding income taxes, decreased 6% to $125.1 million in 1995 from $133.7 million in 1994, due primarily to decreased operation and maintenance expense. Operation and maintenance expense decreased $10.3 million due to decreased distribution expense, customer accounts expenses, employee welfare and pension expenses, rent expense, and outside services expense. In 1994 GGC acquisition and assimilation costs were approximately $1.5 million and the cost of an early retirement program was approximately $1.3 million. The acquisition and assimilation costs as well as the early retirement program were one-time costs associated with the GGC acquisition. The Company also adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" in 1994. It has been successful in seeking recovery of SFAS No. 106 expenses in the majority of its service areas in 1994 and 1995 and will continue to seek recovery in its remaining service areas (Note 8). Income taxes increased to $9.6 million for 1995 from $8.1 million for 1994. The primary reason for the increase was higher pre-tax profits. The effective tax rate decreased to 33.7% in 1995 from 35.6% in 1994. This was primarily due to the impact of permanent differences on the higher pre-tax profits in 1995. Operating income increased in 1995 by approximately 22% to $32.4 million from $26.5 million in 1994. The increase in operating income resulted primarily from decreases in 1995 operating expenses as discussed above. The Company expects to see operating expenses return to a more normal level in 1996. Net income increased in 1995 by approximately 29% to $18.9 million from $14.7 million in the prior year. This increase in net income resulted primarily from an increase in operating income, which was partially offset by a $1.4 million increase in interest expense. Net income per share increased to $1.22 for 1995 from $.97 for 1994. The Company estimates that the impact of the weather being 10% warmer than normal for 1995 caused net income to be approximately $4.0 million less than it would have been had the Company experienced normal temperatures in its respective service areas. Weather was approximately 1% warmer than normal for 1994. 24 YEAR ENDED SEPTEMBER 30, 1994 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1993 Operating revenues increased to $499.8 million in 1994 from $459.6 million in 1993 due to rate increases implemented in Kansas, Colorado and Louisiana, an increase in the number of customers, changes in cost of gas and increased volumes sold. Average gas sales revenues per Mcf increased from 1993 by $.12 to $4.14 in 1994, while the average cost of gas per Mcf sold increased $.15 to $2.86 in 1994. The number of meters in service increased to 649,319 at September 30, 1994 compared with 636,159 at September 30, 1993. Although the weather was 2% warmer in 1994 than in 1993, it was only slightly warmer than normal. Sales to residential, commercial and public authority customers decreased approximately .5 Bcf in 1994, but sales to industrial and agricultural customers increased approximately 7 Bcf. Total sales volumes increased 6.7 Bcf to 116.1 Bcf in 1994, as compared with 1993. Revenues from gas transported for others decreased $.9 million to approximately $14.1 million in fiscal 1994 due to a decrease in volumes transported of 4.5 Bcf to 35.3 Bcf in 1994. Gross profit increased by approximately 3% to $168.2 million in 1994 from $163.1 million in 1993. The primary factors contributing to the higher gross profit were increased prices and volumes, as discussed above. Operating expenses, excluding income taxes, increased to $133.7 million in 1994 from $122.8 million in 1993 due to increased operation expense and depreciation. Operation expense increased $9.9 million due to increased distribution expense, employee welfare expenses including adoption of SFAS No. 106, GGC acquisition and assimi- lation costs, and the cost of an early retirement program in the Greeley Gas Division in the fourth quarter. SFAS No. 106 expenses in excess of pay-as-you-go expenses were approximately $3.8 million in 1994. The Company has been successful in seeking recovery of SFAS No. 106 expenses in a portion of its service areas and will continue to seek recovery in its remaining service areas (Note 8). GGC acquisition and assimilation costs were approximately $1.5 million in 1994 compared with approximately $.5 million in 1993. The cost of the early retirement program was approximately $1.3 million in 1994. The acquisition and assimilation costs as well as the early retirement program are one-time costs associated with the GGC acquisition. Income taxes decreased to $8.1 million for 1994 from $10.1 million for 1993. The primary reasons for the decrease were lower pre-tax profits and a lower effective tax rate. The effective tax rate decreased to 35.6% in 1994 from 36.5% in 1993. This was primarily due to the impact of permanent differences on the lower pre-tax profits in 1994. Operating income decreased in 1994 by approximately 13% to $26.5 million from $30.3 million in 1993. The decrease in operating income resulted primarily from increased operating expenses as discussed above. Net income decreased in 1994 by approximately 16% to $14.7 million from $17.5 million in the prior year. This decrease in net income resulted primarily from a decrease in operating 25 income, which was partially offset by a $1.0 million decrease in interest expense. Net income per share decreased to $.97 for 1994 from $1.22 for 1993, reflecting the effects of an increase in average shares outstanding of approximately 6%. One-time acquisition costs, assimilation expenses and an early retirement program in Greeley Gas Company, as well as the effect of adopting SFAS No. 106, reduced earnings per share by approximately $.22 in 1994. CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of Cash Flows") Cash Flows from Operating Activities Cash flows from operating activities totaled $58.5 million for 1995 compared with $41.2 million for 1994 and $37.1 million for 1993. In 1995 the Company experienced increases in both net income and in cash provided by changes in assets and liabilities as compared with 1994 and 1993. Depreciation increased in 1995 because of increasing capital expenditures. Gas stored under- ground decreased in 1995 and 1994 because of substantially lower gas prices during the summers of 1995 and 1994 when the storage reservoirs were being refilled. The $10.9 million increase in deferred charges and other assets in 1993 related to the $8.4 million increase in deferred credits and other liabilities and recognized funding for the Supplemental Executive Benefits Plan. See "Consolidated Statements of Cash Flows" for other changes in assets and liabilities. Cash Flows from Investing Activities Net cash used in investing activities totaled $60.2 million in 1995 compared with $48.4 million in 1994 and $42.2 million in 1993. Capital expenditures in fiscal 1995 amounted to $62.9 million compared with $50.4 million in 1994 and $43.1 million in 1993. Currently budgeted capital expenditures for 1996 total $66.3 million and include major expenditures for mains, services, meters, vehicles and computer software. Such expenditures will be financed from internally generated funds and financing activities, as discussed below. Cash Flows from Financing Activities Net cash provided by financing activities totaled $1.2 million for 1995 compared with $7.7 million for 1994 and $3.7 million for 1993. Financing activities during these periods included issuance of common stock, dividend payments, borrowings from banks, and issuance and repayments of long-term debt. Cash dividends and distributions paid. The Company paid $14.2 million in cash dividends during 1995 compared with $12.7 million in 1994 and $10.2 million in 1993. The $1.5 million increase over 1994 primarily reflects an increase in the Company's quarterly dividend rate and an increase in the number 26 of shares of common stock outstanding in 1995. The Company has increased its historical dividend rate in each of the last seven years. Short-term financing activities. At September 30, 1995, the Company had committed lines of credit totaling $90.0 million, all of which was unused, in order to provide for short-term cash requirements. These credit facilities are negotiated at least annually. At September 30, 1995, the Company also had uncommitted short-term credit lines of $140.0 million, of which $106.5 million was unused. During 1995, notes payable decreased $24.6 million compared with increases of $22.4 million during 1994 and $2.6 million in 1993. The decrease in 1995 was primarily due to repayment of short-term debt with the proceeds from the issuance of long-term debt in November 1994. The increase in 1993 was less than the increase in 1994, partly because of funds provided in 1993 from stock issued under the Direct Stock Purchase Plan. Long-term financing activities. Payments of long-term debt decreased $5.85 million to $4.0 million for the year ended September 30, 1995 compared with the year ended September 30, 1994. Payments of long-term debt in 1995 consisted of a $2.0 million installment on the Company's 9.75% Senior Notes due in 1996 and a $2.0 million installment on the 11.2% Senior Notes. In November 1994, the Company entered into note purchase agree- ments totaling $40.0 million with two insurance companies and issued at par $20.0 million of unsecured Senior Notes at 8.07% payable in annual installments of $4.0 million beginning October 31, 2002 through October 31, 2006 with semiannual interest payments and $20.0 million of unsecured Senior Notes at 8.26% payable in annual installments of $1,818,182 beginning October 31, 2004 through October 31, 2014 with semiannual interest payments. No long-term debt was issued in 1994 or 1993. Pay- ments of long-term debt during fiscal 1994 consisted of a $3.0 million installment on the Company's 9.75% Senior Notes due in 1996, a $2.0 million installment on the 11.2% Senior Notes, the balance of $3.25 million on the 13.75% Series I First Mortgage Bonds and the balance of $1.6 million on the 13% Series G First Mortgage Bonds. The loan agreements pursuant to which all the Company's Senior Notes 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. Also see Note 3 of notes to consolidated financial statements. Issuance of common stock. The Company issued 221,946, 428,264 and 897,089 shares of common stock in 1995, 1994 and 1993, respectively, for its Direct Stock Purchase Plan ("DSPP"), Employee Stock Ownership Plan, Restricted Stock Grant Plan, and Incentive Stock Option Plan. See the Consolidated Statements of Shareholders' Equity for the number of shares issued under each of the plans. The DSPP was implemented in August 1992. In 1993 the DSPP was amended to remove the direct stock purchase feature of the plan and the plan was renamed the Atmos Energy Corporation 27 Dividend Reinvestment and Stock Purchase Plan ("DRSPP"). How- ever, in January 1995 the direct stock purchase feature was rein- stated and the name was changed back to the Direct Stock Purchase Plan. Shares purchased under the DSPP in 1995 were purchased on the open market. No new shares were issued under the DSPP in 1995. In 1994 and 1993, 173,801 and 760,089 shares, respective- ly, were issued under the DRSPP, generating proceeds of $3.0 million and $13.4 million, respectively. At September 30, 1995, 712,596 shares were available for future issuance under the DSPP. The Company believes that internally generated funds, its short-term credit facilities and access to the debt and equity capital markets will provide necessary working capital and liquidity for capital expenditures and other cash needs for 1996. Seasonality The Company's natural gas distribution business is seasonal due to weather conditions in the Company's service areas. Gas sales are affected by winter heating season requirements, and sales to agricultural customers (who use natural gas as fuel in the operation of irrigation pumps) during the period from April through September may be 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 following table sets forth, on an unaudited basis, the Company's quarterly operating revenues, quarterly operating revenues as a percentage of annual operating revenues, quarterly net income (loss) and quarterly net income (loss) as a percentage of annual net income for its past two fiscal years. 28 Quarter ended --------------------------------------------------- December 31 March 31 June 30 September 30 Total ------------ --------- -------- ------------ ---------- (In thousands, except for percentages) 1995 - ---- Operating revenues $117,848 $157,294 $84,685 $75,993 $435,820 27% 36% 19% 18% 100% Net income (loss) $ 6,476 $ 13,945 $ 82 $(1,630) $ 18,873 34% 74% 1% (9)% 100% 1994 - ---- Operating revenues $145,501 $186,944 $90,013 $77,350 $499,808 29% 37% 18% 16% 100% Net income (loss) $ 7,088 $ 13,242 $(1,224) $(4,427) $ 14,679 48% 90% (8)% (30)% 100% 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 continually reviews 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. 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 oper- ated in substantial conformity with all applicable environmental statutes and regulations. There are no administrative or judi- cial 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. 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page no. Report of independent auditors 30 Consolidated balance sheets 31 Consolidated statements of income 32 Consolidated statements of shareholders' equity 33 Consolidated statements of cash flows 34 Notes to consolidated financial statements 36 Supplementary data (unaudited) 57 30 REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS Board of Directors Atmos Energy Corporation We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation at September 30, 1995 and 1994, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 1995. 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, 1995 and 1994, and its consolidated results of operations and its cash flows for each of the three years in the period ended September 30, 1995 in conformity with generally accepted accounting principles. Ernst & Young LLP Dallas, Texas November 8, 1995 31 ATMOS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS September 30, 1995 1994 -------- -------- ASSETS (In thousands, except share data) Property, plant and equipment Utility plant $589,801 $537,834 Construction in progress 5,558 5,858 -------- -------- 595,359 543,692 Less accumulated depreciation and amort. 232,107 216,285 -------- -------- Net property, plant and equipment 363,252 327,407 Current assets Cash and cash equivalents 2,294 2,766 Accounts receivable, less allowance for doubtful accounts of $916 in 1995 and $787 in 1994 25,690 29,678 Inventories 6,747 5,888 Gas stored underground 10,758 12,657 Prepayments 2,747 2,309 -------- -------- Total current assets 48,236 53,298 Deferred charges and other assets 34,295 35,973 -------- -------- $445,783 $416,678 ======== ======== CAPITALIZATION AND LIABILITIES Shareholders' equity Common stock, no par value (stated at $.005 per share); authorized 75,000,000 shares; issued and outstanding 1995 - 15,519,112 shares, 1994 - 15,297,166 shares $ 78 $ 77 Additional paid-in capital 106,496 102,456 Retained earnings 51,704 47,023 -------- -------- Total shareholders' equity 158,278 149,556 Long-term debt 131,303 138,303 -------- -------- Total capitalization 289,581 287,859 Current liabilities Current maturities of long-term debt 7,000 4,000 Notes payable to banks 33,500 18,100 Accounts payable 24,945 21,975 Taxes payable 1,926 4,864 Customers' deposits 9,343 8,257 Other current liabilities 10,641 7,038 -------- -------- Total current liabilities 87,355 64,234 Deferred income taxes 33,120 30,184 Deferred credits and other liabilities 35,727 34,401 -------- -------- $445,783 $416,678 ======== ======== See accompanying notes to consolidated financial statements. 32 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME Year ended September 30, -------------------------------- 1995 1994 1993 -------- -------- -------- (In thousands, except per share data) Operating revenues $435,820 $499,808 $459,641 Purchased gas cost 268,810 331,571 296,532 -------- -------- -------- Gross profit 167,010 168,237 163,109 Operating expenses Operation 83,431 92,132 82,185 Maintenance 4,276 5,888 6,335 Depreciation and amortization 20,741 18,841 17,433 Taxes, other than income 16,611 16,808 16,806 Income taxes 9,574 8,102 10,073 -------- -------- -------- Total operating expenses 134,633 141,771 132,832 -------- -------- -------- Operating income 32,377 26,466 30,277 Other income (expense) Interest income 459 168 327 Other, net (242) 335 239 -------- -------- -------- Total other income 217 503 566 Interest charges 13,721 12,290 13,299 -------- -------- -------- Net income $ 18,873 $ 14,679 $ 17,544 ======== ======== ======== Net income per share $ 1.22 $ .97 $ 1.22 ======== ======== ======== Cash dividends per share $ .92 $ .88 $ .85 ======== ======== ======== Average shares outstanding 15,416 15,195 14,338 ======== ======== ======== See accompanying notes to consolidated financial statements. 33 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Common stock ----------------- Additional Number of Stated paid-in Retained shares value capital earnings ----------- ------ --------- -------- (In thousands, except share data) Balance, September 30, 1992 13,971,813 $70 $ 78,541 $38,637 Net income - - - 17,544 Cash dividends ($.85 per share) - - - (9,262) GGC distributions - - - (893) Common stock issued Stock option plan 6,000 - 60 - Direct stock purchase plan 760,089 3 13,401 - Employee stock ownership plan 131,000 1 2,277 - Less: GGC net income for the quarter ended December 31, 1992 (Note 2) - - - (950) ---------- --- ------- ------- Balance, September 30, 1993 14,868,902 74 94,279 45,076 Net income - - - 14,679 Cash dividends ($.88 per share) - - - (12,612) GGC distributions - - - (120) Common stock issued Restricted stock grant plan 105,000 1 2,134 - Direct stock purchase plan 173,801 1 3,037 - Employee stock ownership plan 149,463 1 2,713 - Other - - 293 - ---------- --- ------- ------- Balance, September 30, 1994 15,297,166 77 102,456 47,023 Net income - - - 18,873 Cash dividends ($.92 per share) - - - (14,192) Common stock issued Restricted stock grant plan 7,000 - 119 - Employee stock ownership plan 214,946 1 3,876 - Other - - 45 - ---------- --- -------- ------- Balance, September 30, 1995 15,519,112 $78 $106,496 $51,704 ========== === ======== ======= See accompanying notes to consolidated financial statements. 34 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended September 30, ------------------------- 1995 1994 1993 --------------- ------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES Net income $18,873 $14,679 $16,594 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization Charged to depreciation and amortization 20,741 18,841 16,480 Charged to other accounts 3,592 1,476 3,377 Deferred income taxes 2,809 244 2,733 Other 2,011 2,101 622 ------- ------- ------- 48,026 37,341 39,806 Change in assets and liabilities (Increase) decrease in accounts receivable 3,988 (478) 1,564 (Increase) decrease in inventories (859) 176 708 (Increase) decrease in gas stored underground 1,899 4,946 (6,176) (Increase) decrease in prepayments (438) 1,931 1,873 Decrease in deferred charges and other assets (333) (3,824) (10,908) Increase (decrease) in accounts payable 2,970 (7,128) (58) Increase (decrease) in taxes payable (2,766) (1,314) 195 Increase (decrease) in customers' deposits 1,086 395 (61) Increase in other current liabilities 3,603 583 1,804 Increase in deferred credits and other liabilities 1,326 8,596 8,398 ------- ------- ------- Net cash provided by operating activities 58,502 41,224 37,145 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (62,927)(50,355) (43,143) Retirements of property, plant and equipment 2,749 1,906 935 ------- ------- ------- Net cash used in investing activities (60,178)(48,449) (42,208) - Continued - 35 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Year ended September 30, 1995 1994 1993 -------- -------- -------- (In thousands) CASH FLOWS FROM FINANCING ACTIVITIES Net increase (decrease) in notes payable $(24,600)$ 22,400 $ 2,563 Proceeds from issuance of long-term debt 40,000 - - Repayment of long-term debt (4,000) (9,850) (4,500) Cash dividends and distributions paid (14,192) (12,732) (10,155) Issuance of common stock 3,996 7,887 15,742 ------- ------- ------- Net cash provided by financing activities 1,204 7,705 3,650 ------- ------- ------- Net increase (decrease) in cash and cash equivalents (472) 480 (1,413) Cash and cash equivalents at beginning of year 2,766 2,286 3,699 ------- ------- ------- Cash and cash equivalents at end of year $ 2,294 $ 2,766 $ 2,286 ======= ======= ======= See accompanying notes to consolidated financial statements. 36 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of significant accounting policies Description of business - Atmos Energy Corporation and its subsidiaries ("Atmos" or the "Company") are in the business of distributing natural gas to residential, commercial, industrial and agricultural customers within service areas located in Texas, Louisiana, Kentucky, Colorado, Kansas and a small portion of Missouri. Such business is subject to federal and state regulation and/or regulation by local authorities in each of the six states in which the Company operates. The Company has no other material business segments. Principles of consolidation - The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its subsidiaries. Each subsidiary is wholly- owned and all material intercompany items have been eliminated. 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 ac- counting 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. Property, plant and equipment - Property, plant and equipment is stated at original cost net of contributions in aid of construction. The cost of additions includes an allowance for funds used during construction and applicable overhead charges. Major renewals and betterments are capitalized, while the costs of maintenance and repairs are charged to expense as incurred. Property, plant and equipment is depreciated at various rates on a straight-line basis over the estimated useful lives of the assets. In the first quarter of fiscal 1993, the Company changed the estimated average useful lives used to compute depreciation for certain utility plant assets. These changes resulted from revised estimates of the projected economic life of the affected assets based on recent orders received from regulatory bodies having jurisdiction over the Company and independently performed depreciation service life studies. The effect of this change on net income for the year ended September 30, 1993 was an increase of $1,104,000. The composite rates were 4.1% and 3.5% for the years ended September 30, 1995 and 1994, respectively. At the time property, plant and equipment is retired, the cost, plus removal expenses and less salvage, is charged to accumulated depreciation. 37 Inventories - Inventories consist of materials and supplies and merchandise held for resale. Inventories are stated at the lower of average cost or market. Gas stored underground - Net additions of inventory gas to underground storage and withdrawals of inventory gas from storage are priced using the average cost method. Non-current gas in storage is classified as property, plant and equipment and is priced at cost. Income taxes - The Company provides deferred income taxes for significant temporary differences in the recognition of revenues and expenses for tax and financial reporting purposes. 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, 1995 and 1994 include assets of the Company's qualified defined benefit retirement plans in excess of the plans' obligations in the amounts of $9,962,000 and $12,275,000, respectively, and Company assets related to the nonqualified retirement plans at September 30, 1995 and 1994 of $16,510,000 and $15,735,000, respectively. Deferred credits and other liabilities - Deferred credits and other liabilities include customer advances for construction of $8,212,000 and $8,428,000 at September 30, 1995 and 1994, respectively; obligations under capital leases of $2,882,000 and $6,294,000 at September 30, 1995 and 1994, respectively; and obligations under the Company's nonqualified retirement plans of $16,125,000 and $11,151,000 at September 30, 1995 and 1994, respectively. At September 30, 1994, a payable of $1,300,000 was recorded for expenses related to an early retirement program under Greeley Gas Company's qualified defined benefit retirement plan. Earnings per share - The calculation of primary earnings per share is based on reported net income divided by weighted average common shares outstanding. The Company does not have other classes of stock or dilutive common stock equivalents. See Note 2 for a discussion of supplemental net income per share. 2. Greeley Gas Company acquisition On December 22, 1993, Atmos acquired by means of a merger all of the assets and liabilities of Greeley Gas Company ("GGC") in accordance with the terms and provisions of an Agreement and Plan of Reorganization dated July 2, 1993. GGC is a natural gas utility engaged in the distribution and sale of natural gas to residential, commercial, industrial, agricultural, and other customers throughout Colorado, Kansas, and a small portion of Missouri. All of the shares of GGC's common stock were exchanged for a total of 3,493,995 shares of Atmos common stock as adjusted 38 for a 3-for-2 stock split (2,329,330 shares on a pre-split basis). See Note 5 for information regarding the stock split in May 1994. This merger transaction was accounted for as a pooling of interests; therefore, all historical financial statements and notes thereto have been restated. Subsequent to the merger, the business of GGC has been operated through the Company's Greeley Gas Company division (the "Greeley Gas Division"). GGC prepared its financial statements on a December 31 fiscal year end. GGC's fiscal year has been changed to September 30 to conform to the Company's year end. The restated consoli- dated statement of income for the year ended September 30, 1993 includes Atmos and GGC operations for the twelve months then ended. As a result, GGC's operations for the three months ended December 31, 1992 (operating revenue of $18,322,842 and net income of $950,185) are included in both the 1993 and 1992 restated statements of income, and the GGC net income for this period has been deducted in calculating the shareholders' equity balances at September 30, 1993 and cash flows for the year then ended. In 1987, GGC elected classification as an S Corporation (small business corporation) under the provisions of the Internal Revenue Code. Normally, income taxes are not reported in the financial statements of S Corporations as the liability for payment of federal and state income taxes is the direct responsibility of the shareholders. However, during 1991, as part of the settlement of rate cases filed in the states of Colorado and Kansas, GGC was ordered to begin providing for current and deferred income taxes. Accordingly, the Company's restated 1991 financial statements include a one-time charge to income of $1,081,202 to reinstate deferred income taxes for GGC. Supplemental net income and earnings per share of the Company are presented below to eliminate the one-time charge and to reflect income tax expense in periods prior to 1994 as if GGC had not made the S Corporation election in 1987. Year ended September 30, 1993 ------------------ (In thousands, except per share data) Supplemental net income $ 18,132 ======== Supplemental net income per share $ 1.26 ======== 39 Results of operations and net income for the previously separate companies for periods prior to the merger are as follows: Quarter ended Year ended December 31, 1993 September 30,1993 ----------------- ----------------- (In thousands) Operating revenues Atmos $119,223 $388,495 GGC 26,278 71,146 -------- -------- $145,501 $459,641 ======== ======== Net income Atmos $ 5,458 $ 15,712 GGC 1,630 1,832 -------- -------- $ 7,088 $ 17,544 ======== ======== The dividends per share presentation on the consolidated statements of income reflects Atmos dividends declared per share as adjusted for the 3-for-2 stock split in May 1994. The cash dividends per share reflect the per share dividends declared by Atmos Energy Corporation for the years ended September 30, 1994 and 1993. The restated cash dividends and distributions per share reflect the total amounts paid by Atmos and GGC to their shareholders in each of those two years, divided by the total amount of weighted average shares outstanding in those periods as restated for the shares issued to effect the merger between Atmos and GGC and the 3-for-2 stock split in May 1994. Year ended September 30, -------------- 1994 1993 ---- ---- Cash dividends per share $.88 $.85 ==== ==== Restated cash dividends and distributions per share, including GGC $.84 $.71 ==== ==== 40 3. Long-term debt and notes payable Long-term debt at September 30, 1995 and 1994 consisted of the following: 1995 1994 --------- -------- (In thousands) Unsecured 7.95% Senior Notes, payable in annual installments of $1,000,000 beginning August 31, 1997 through August 31, 2006 with semiannual interest payments $ 10,000 $ 10,000 Unsecured 9.57% Senior Notes, payable in annual installments of $2,000,000 beginning September 30, 1997 through September 30, 2006 with semiannual interest payments 20,000 20,000 Unsecured 9.76% Senior Notes, payable in annual installments of $3,000,000 beginning December 30, 1995 through December 30, 2004 with semiannual interest payments 30,000 30,000 Unsecured 9.75% Senior Notes, payable in varying annual installments through December 30, 1996 3,000 5,000 Unsecured 11.2% Senior Notes, payable in annual installments of $2,000,000 beginning December 30, 1993 through December 30, 2002 with semiannual interest payments 16,000 18,000 First Mortgage Bonds, 9.4% Series J, due May 1, 2021 17,000 17,000 Unsecured 10% Notes, due December 31, 2011 2,303 2,303 Unsecured 8.07% Senior Notes, payable in annual installments of $4,000,000 beginning October 31, 2002 through October 31, 2006 with semiannual interest payments 20,000 20,000 Unsecured 8.26% Senior Notes, payable in annual installments of $1,818,182 beginning October 31, 2004 through October 31, 2014 with semiannual interest payments 20,000 20,000 -------- -------- 138,303 142,303 Less amounts classified as current (7,000) (4,000) -------- -------- $131,303 $138,303 ======== ======== In November 1994, the Company entered into note purchase agreements with two insurance companies and issued at par $20,000,000 of unsecured Senior Notes at 8.07% and $20,000,000 of unsecured Senior Notes at 8.26%. As a result of this financing, 41 $40,000,000 of notes payable to banks was classified as long-term at September 30, 1994. During the quarter ended December 31, 1994, the Company paid installments due of $2,000,000 on its 9.75% Senior Notes and $2,000,000 on its 11.2% Senior Notes. The Company may prepay any of the Senior Notes in whole at any time, subject to a prepayment premium. The note agreements 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 September 30, 1988 may not exceed the sum of 75% of accumulated net income for periods after September 30, 1988 plus $12,000,000 plus the proceeds from the sale of common stock after September 30, 1988. At September 30, 1995, approximately $48,451,000 of shareholders' equity was not so restricted. As of September 30, 1995, all of the Company's utility plant assets in Colorado, Kansas and Missouri with a net book value of approximately $66,170,000 are subject to a lien under the 9.4% Series J First Mortgage Bonds assumed by the Company in the acquisition of GGC. Maturities of long-term debt are as follows (in thousands): 1996 $ 7,000 1997 9,000 1998 8,000 1999 8,000 2000 8,000 Thereafter 98,303 -------- $138,303 ======== Notes payable to banks The Company has committed short-term, unsecured bank credit facilities totaling $90,000,000, all of which was unused at September 30, 1995. One facility of $80,000,000 requires a commitment fee of 1/10 of 1% on the unused portion. A second facility for $10,000,000 requires a commitment fee of 3/16 of 1% on the unused portion. The committed lines are renewed or renegotiated at least annually. The Company also had aggregate uncommitted credit lines of $140,000,000, of which $106,500,000 was unused as of September 30, 1995. 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. 42 The weighted average interest rate on short-term borrowings outstanding at September 30, 1995 and 1994 were 7.0% and 5.6%, respectively. 4. Income taxes The components of income tax expense for 1995, 1994 and 1993 are as follows: 1995 1994 1993 ------- ------- ------- (In thousands) Current $6,765 $7,858 $ 7,340 Deferred 2,809 244 2,733 ------ ------ ------- $9,574 $8,102 $10,073 ====== ====== ======= Included in the provision for income taxes are state income taxes of $506,000, $328,000, and $890,000 for 1995, 1994, and 1993, respectively. Effective October 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS No. 109") and, as permitted under these rules, prior years' financial statements have not been restated. Adoption of the new standard in 1994 had no significant effect on net income. This standard changes the Company's method of accounting for income taxes from the deferred method (APB 11) to the liability method. Previously the Company deferred the past tax effects of timing differences between financial reporting and taxable income. Under the liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the estimated future tax effects of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. 43 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, 1995 and 1994 are presented below: 1995 1994 ------- ------- (In thousands) Deferred tax assets Costs expensed for book purposes and capitalized for tax purposes $ 872 $ 914 Accruals not currently deductible for tax purposes 1,045 1,929 Customer advances 2,020 2,365 Nonqualified benefit plans 7,107 5,074 Postretirement benefits 2,187 1,442 Other, net 2,902 1,198 ------- ------- Total deferred tax assets 16,133 12,922 Deferred tax liabilities Tax and book basis of utility plant 43,549 37,316 Prepaid pensions 4,528 4,640 Other, net 1,176 1,150 ------- ------- Total deferred tax liabilities 49,253 43,106 ------- ------- Net deferred tax liabilities $33,120 $30,184 ======= ======= SFAS No. 109 deferred accounts for rate regulated entities (included in other deferred credits): Liabilities $ 2,580 $ 2,647 ======= ======= 44 During 1993, deferred income taxes were provided for significant timing differences in recognition of revenues and expenses for tax and financial reporting purposes. The effects of these timing differences at September 30, 1993 were as follows: 1993 ------ (In thousands) Excess of tax over financial depreciation and amortization $1,754 Items capitalized for financial reporting and recognized currently for tax reporting 416 Deferred gas service revenue recognized currently for tax reporting 1,464 Other, net (901) ------ Total deferred income taxes $2,733 ====== Reconciliations of the provisions for income taxes computed at the statutory rate to the reported provisions for income taxes for 1995, 1994 and 1993 are set forth below: Deferred Liability Method Method ---------------- -------- 1995 1994 1993 ------ ------- ------- (In thousands) Tax at statutory rate of 34% through December 31, 1992 and 35% thereafter $9,956 $ 7,992 $ 9,603 Financial expenses, not deductible for tax reporting 35 503 680 Common stock dividends deductible for tax reporting (619) (573) (462) State taxes 261 328 682 Other, net (59) (148) (430) ------ ------- ------- Provision for income taxes $9,574 $ 8,102 $10,073 ====== ======= ======= 5. Stock split On February 9, 1994, the Board of Directors of Atmos ap- proved a 3-for-2 split of its common stock implemented in the form of a stock dividend, which resulted in shareholders receiving one new share for every two shares held. Fractional shares were not issued but were paid in cash or credited to the accounts of participants of the Dividend Reinvestment and Stock Purchase Plan ("DRSPP") and ESOP. The record date for the split was May 4, 1994 and the payment date for mailing the new shares and cash for fractional shares to shareholders was May 16, 1994. 45 All share and per share amounts in the financial statements and notes thereto have been restated to reflect this split, unless otherwise noted. 6. Common stock and stock options At the annual meeting of shareholders on February 8, 1995, the shareholders approved an increase in the number of authorized shares of common stock from 50,000,000 to 75,000,000. The Company issued 221,946 shares of its common stock in fiscal 1995 in connection with its Restricted Stock Grant Plan and Employee Stock Ownership Plan. The Company has an Employee Stock Ownership Plan as dis- cussed in Note 7. The Company has registered 1,600,000 shares for issuance under the plan, of which 874,830 shares were available for future issuance on September 30, 1995. In August 1992, the Company announced a Direct Stock Purchase Plan ("DSPP") which was the successor to and replacement for the Dividend Reinvestment Plan ("DRP"). Members of the DRP were automatically enrolled in the DSPP. In November 1993, the Company amended the DSPP to remove the direct stock purchase feature of the plan and to rename the plan the Atmos Energy Corporation Dividend Reinvestment and Stock Purchase Plan ("DRSPP"). In January 1995, the direct stock purchase feature was reinstated and the name was changed back to the Direct Stock Purchase Plan. 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 com- mon stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000. At September 30, 1995, 712,596 shares were available for future issuance under the plan. On April 27, 1988, the Company adopted a Shareholders' Rights Plan (the "Rights Plan") and declared a dividend of one right (a "Right") for each outstanding pre-split share of common stock of the Company, payable to shareholders of record as of May 10, 1988. Each Right will entitle the holder thereof, until the earlier of May 10, 1998 or the date of redemption of the Rights, to buy one share of common stock of the Company at an exercise price of $30 per share, subject to adjustment by the Board of Directors upon the occurrence of certain events. The Rights will be represented by the common stock certificates and are not exercisable or transferable apart from the common stock until a "Distribution Date" (which is defined in the Rights Agreement between the Company and the Rights Agent as the date upon which the Rights become separate from the common stock). 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 46 dilution. Until 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 a 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 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 the Rights become exercisable or transferable, the Rights may be redeemed by the Company at $.05 per Right. The Company had an Incentive Stock Option Plan for key employees covering an aggregate of 100,000 shares of common stock. The plan provided for options to be granted at prices not less than the fair market value of the stock on the date of grant and to be exercisable over ten years from such date in cumulative annual installments of 25% of the aggregate shares granted, commencing one year after the date of grant. At September 30, 1993, no options were outstanding under the plan. The Company allowed the plan to expire in October 1993 without granting additional options. The following table summarizes the status of the expired Incentive Stock Option Plan as of September 30, 1993: 1993 -------------------- Price Shares per share ------- ----------- Outstanding options at beginning of year 6,000 $9.25-10.63 Exercised (6,000) 9.25-10.63 ------ Outstanding options at end of year - - ====== Exercisable options at end of year - Options available for future grants (pre-split) 8,150 The Company's Restricted Stock Grant Plan for management and key employees of the Company, which became effective October 1, 1987, 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 47 Company make the final determinations regarding participation in the plan, awards under the plan, and restrictions on the re- stricted stock awarded. The restricted stock may consist of previously issued shares purchased on the open market or shares issued directly from the Company. The Company registered 600,000 shares (900,000 post-split shares) for issuance under the plan. Compensation expense of $1,015,000, $1,164,000 and $735,000 was recognized in 1995, 1994 and 1993, respectively, in connection with the issuance of shares under the plan. At September 30, 1995, 377,300 shares were available for future award under the plan. In November 1994, the Board adopted the Outside Directors Stock-for-Fee Plan, which plan was approved by the shareholders of the Company in February 1995. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash. The Company has registered 50,000 shares, all of which were available for future issuance under the plan as of September 30, 1995. 7. Employee retirement and stock ownership plans At September 30, 1995, the Company had three defined benefit pension plans. One covers the Western Kentucky Division employ- ees, one covers the Greeley Gas Division employees, and the third covers all other Atmos employees. The plans provide essentially the same benefits to all employees. Benefits are based on years of service and the employee's compensation during the highest paid five consecutive calendar years within the last 10 years of employment. The Company's funding policy is to contribute annually an amount in accordance with the requirements of the Em- ployee 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. 48 The following table sets forth the Atmos plan's funded status at September 30, 1995 and 1994: 1995 1994 -------- -------- (In thousands) Actuarial present value of benefit obligations Accumulated benefit obligation, including vested benefits of $74,967 and $63,658 in 1995 and 1994, respectively $(75,529) $(64,805) ======== ======== Projected benefit obligation $(84,182) $(73,895) Plan assets at fair value 82,464 73,454 -------- -------- Funded status (1,718) (441) Unrecognized net asset being recognized over 15 years (416) (633) Unrecognized prior service cost (1,812) (1,955) Unrecognized net loss 3,514 3,326 -------- -------- (Accrued) prepaid pension cost $ (432) $ 297 ======== ======== Net periodic pension cost for the Atmos plan for 1995, 1994 and 1993 included the following components: 1995 1994 1993 ------- ------ ------ (In thousands) Service cost $ 1,862 $1,846 $1,543 Interest cost on projected benefit obligation 6,060 5,614 5,242 Actual return on plan assets (12,200) (955) (9,445) Net amortization and deferral 5,007 (5,778) 3,206 ------- ------ ------ Net periodic pension cost $ 729 $ 727 $ 546 ======= ====== ====== 49 The following table sets forth the Western Kentucky Gas Division plan's funded status at September 30, 1995 and 1994: 1995 1994 --------- --------- (In thousands) Actuarial present value of benefit obligations Accumulated benefit obligation, including vested benefits of $27,236 and $24,247 in 1995 and 1994, respectively $(27,262) $(24,874) ======== ======== Projected benefit obligation $(31,642) $(28,328) Plan assets at fair value 42,216 37,409 -------- -------- Funded status 10,574 9,081 Unrecognized prior service cost 2,855 3,378 Unrecognized net gain (2,468) (1,442) -------- -------- Prepaid pension cost $ 10,961 $ 11,017 ======== ======== Net periodic pension cost for 1995, 1994 and 1993 included the following components: 1995 1994 1993 -------- -------- -------- (In thousands) Service cost $ 706 $ 729 $ 639 Interest cost 2,306 2,160 2,016 Actual return on plan assets (6,355) 324 (5,604) Net amortization and deferral 3,399 (3,097) 3,110 -------- -------- -------- Net periodic pension cost $ 56 $ 116 $ 161 ======== ======== ======== The weighted-average discount rates used in determining the actuarial present value of the projected benefit obligations of the Atmos and WKG retirement plans were 7.5% and 8.375% at June 30, 1995 and 1994, respectively. The rate of increase in future compensation levels reflected in such determination was 4.0% and 4.5% for the years ended September 30, 1995 and 1994, respectively. The expected long-term rate of return on plan assets was 10.0%, 9.5% and 8.5% for the years ended September 30, 1995, 1994 and 1993, respectively. The plan assets consist primarily of investments in common stocks, interest bearing securities and interests in commingled pension trust funds. Prepaid pension cost is included in deferred charges and other assets. 50 The following table sets forth the Greeley Gas Division plan's funded status at September 30, 1995 and 1994: 1995 1994 -------- -------- (In thousands) Actuarial present value of benefit obligations Accumulated benefit obligation, including vested benefits of $13,134 and $12,849 in 1995 and 1994, respectively $(13,385) $(13,206) ======== ======== Projected benefit obligation $(15,148) $(15,020) Plan assets at fair value 14,607 13,140 -------- -------- Funded status (541) (1,880) Unrecognized net asset being recognized over 15 years (1,810) (2,100) Unrecognized prior service cost 419 455 Unrecognized net loss 1,370 3,186 -------- -------- Accrued pension cost $ (562) $ (339) ======== ======== Net periodic pension cost (credit) for the Greeley Gas Division plan for 1995, 1994 and 1993 included the following components: 1995 1994 1993 ------ ------- ------- (In thousands) Service cost $ 328 $ 486 $ 374 Interest cost on projected benefit obligation 1,208 1,039 954 Actual return on plan assets (2,530) 441 (1,180) Net amortization and deferral 1,217 (1,795) (257) ------ ------- ------- Net periodic pension cost (credit) $ 223 $ 171 $ (109) ====== ======= ======= Accumu