-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, Z38kh+bU0MjPIrfikFUd8aPSnuMKdrUczcg/KDFUzhd+q311UrFIQFx4CRJYr64U 23h446yrFyMgKwwfTpADDg== 0000731802-94-000018.txt : 19941216 0000731802-94-000018.hdr.sgml : 19941216 ACCESSION NUMBER: 0000731802-94-000018 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941215 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ATMOS ENERGY CORP CENTRAL INDEX KEY: 0000731802 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 751743247 STATE OF INCORPORATION: TX FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-10042 FILM NUMBER: 94564844 BUSINESS ADDRESS: STREET 1: 1800 THREE LINCOLN CTR STREET 2: 5430 LBJ FREEWAY CITY: DALLAS STATE: TX ZIP: 75240 BUSINESS PHONE: 2149349227 FORMER COMPANY: FORMER CONFORMED NAME: ENERGAS CO DATE OF NAME CHANGE: 19881024 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required) For the fiscal year ended September 30, 1994 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 $237,127,039 as of December 1, 1994. On December 1, 1994, the registrant had 15,347,251 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 8, 1995 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 413 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 four 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, 1994, the Company had 309,496 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, 1994, the Company had 70,361 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, 1994, the Company had 164,828 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, 1994 the Greeley Gas Division had 104,634 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. The Company continues to consider and pursue, where appropriate, additional acquisitions of natural gas distribution properties and other business opportunities. For further information regarding the GGC merger, see Note 2 of notes to consolidated financial statements, and Management's Discussion and Analysis. 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, ---------------------------------------------------------- 1994 1993 1992 1991 1990 ------- ------- ------- ------- ------- NUMBER OF ACCOUNTS, at end of year Residential 549,129 539,309 534,762 529,498 523,029 Commercial 55,027 54,275 55,562 54,703 53,992 Industrial (including agricultural) 8,781 8,924 9,331 9,793 10,045 Public authority and other 3,351 3,267 1,745 1,788 1,677 ------- ------- ------- ------- ------- Total 616,288 605,775 601,400 595,782 588,743 ======= ======= ======= ======= ======= METERS IN SERVICE, at end of year 649,319 636,159 630,365 619,111 613,542 ======= ======= ======= ======= ======= HEATING DEGREE DAYS, system average (1) Actual 3,953 4,046 3,676 3,583 3,751 Normal 3,983 3,983 3,983 3,983 3,983 Percent of normal 99% 102% 92% 90% 94% SALES VOLUMES - MMcf (2) Residential 51,209 51,763 48,223 47,484 48,635 Commercial 21,134 21,872 20,675 20,778 21,256 Industrial (including agricultural) 38,502 31,367 27,489 29,788 33,018 Public authority and other 5,242 4,403 3,333 3,385 3,515 ------- ------- ------- ------- ------- Total 116,087 109,405 99,720 101,435 106,424 TRANSPORTATION VOLUMES - MMcf (2) 35,308 39,782 32,203 35,201 32,178 ------- ------- ------- ------- ------- TOTAL VOLUMES HANDLED - MMcf (2) 151,395 149,187 131,923 136,636 138,602 ======= ======= ======= ======= ======= OPERATING REVENUES (000's) Gas Revenues Residential $245,931 $237,914 $211,767 $202,486 $199,818 Commercial 92,507 91,250 82,311 81,414 81,061 Industrial (including agricultural) 119,722 92,455 77,218 81,746 94,653 Public authority and other 22,463 18,315 13,232 13,290 13,115 -------- -------- -------- -------- -------- Total gas revenues 480,623 439,934 384,528 378,936 388,647 Transportation Revenues 14,118 15,013 13,674 16,348 16,919 Other Revenue 5,067 4,694 5,151 4,383 4,409 -------- -------- -------- -------- -------- Total operating revenues $499,808 $459,641 $403,353 $399,667 $409,975 ======== ======== ======== ======== ======== AVERAGE SALES PRICE/Mcf Residential $4.80 $4.60 $4.39 $4.26 $4.11 Commercial 4.38 4.17 3.98 3.92 3.81 Industrial (including agricultural) 3.11 2.95 2.81 2.74 2.87 Public authority and other 4.29 4.16 3.97 3.93 3.73 Total 4.14 4.02 3.86 3.74 3.65 AVERAGE COST OF GAS/Mcf SOLD 2.86 2.71 2.58 2.58 2.57 See footnotes on page 4.
4 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 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 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 14,179 500 17,498 3,071 60 - 35,308 ------ ----- ------ ------ ----- -- ------- TOTAL VOLUMES HANDLED 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 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 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 weather experienced and to compare relative temperatures between one geographic area and another. Degree day information for the small service area in Missouri is not available for 1993 and would not impact the total Company average. 5 Volumes are reported as metered in million cubic feet ("MMcf"). The Texas column includes 224 and 219 employees in the Dallas general office in 1994 and 1993, respectively.
6 SALES AND STATISTICAL DATA BY STATE - 1993
Year ended September 30, 1993 --------------------------------------------------------------- Texas Louisiana Kentucky Colorado Kansas Mo. Total ------- ------ ------- ------ ------ --- ------- NUMBER OF ACCOUNTS, at end of year Residential 256,487 60,042 138,443 61,110 22,740 487 539,309 Commercial 22,974 4,560 15,229 8,402 3,048 62 54,275 Industrial (including agricultural) 8,094 93 312 90 335 - 8,924 Public authority and other 1,024 768 1,475 - - - 3,267 ------- ------ ------- ------ ------ --- ------- Total 288,579 65,463 155,459 69,602 26,123 549 605,775 ======= ====== ======= ====== ====== === ======= METERS IN SERVICE 309,270 68,644 161,971 69,602 26,123 549 636,159 ======= ====== ======= ====== ====== === ======= HEATING DEGREE DAYS, system average (1) Actual 3,661 1,812 4,136 6,955 5,376 N/A 4,046 Normal 3,528 1,760 4,376 6,556 5,158 N/A 3,983 Percent of normal 104% 103% 95% 106% 104% N/A 102% SALES VOLUMES (2) Residential 25,372 3,531 13,314 6,961 2,536 49 51,763 Commercial 8,133 1,230 6,110 5,094 1,294 11 21,872 Industrial (including agricultural) 22,352 1,211 5,708 679 1,417 - 31,367 Public authority and other 2,757 850 796 - - - 4,403 ------ ----- ------ ----- ----- -- ------ Total 58,614 6,822 25,928 12,734 5,247 60 109,405 TRANSPORTATION VOLUMES (2) 17,645 354 18,348 3,092 343 - 39,782 ------ ----- ------ ------ ----- -- ------- TOTAL VOLUMES HANDLED (2) 76,259 7,176 44,276 15,826 5,590 60 149,187 ====== ===== ====== ====== ===== == ======= OTHER STATISTICS Operating revenues (000's) $224,264 $38,954 $125,277 $49,372 $21,356 $418 $459,641 Gross plant (000's) $201,501 $81,848 $116,055 $70,100 $31,579 $429 $501,512 Net plant (000's) $102,684 $62,443 $75,382 $40,663 $17,849 $254 $299,275 Miles of pipe 12,878 1,785 3,364 2,251 1,149 33 21,460 Employees (3) 843 170 390 260 93 - 1,756 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 433 127 265 156 52 - 1,033 Franchises 71 57 64 34 39 2 267 See footnotes on page 4.
7 8 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 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. The Company's revenues are affected by the cost of natural gas, economic conditions in the areas that the Company serves, and weather conditions. 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, excess supply in the natural gas market has led to a decline in natural gas prices and an increase in the number of competing marketers of natural gas to large volume users. In order to compete with these marketers, the Company's three gas marketing subsidiaries purchase gas for resale to various large volume customers. In certain instances, industrial customers purchase gas directly from other marketers or from one of the Company's gas marketing subsidiaries, and the Company transports such gas through its distribution systems to the customers' facilities for a fee. Transportation of customer-owned gas that otherwise would have been sold by the Company reduces the Company's operating revenues and corresponding purchased gas cost. However, the transportation fees received by the Company may offset the loss of gross profit that would have been realized had the Company sold such gas to such customers. 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 interruptible customers under the terms of 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. GAS SUPPLY The principal gas suppliers to the Company in 1994, 1993 and 1992 included Westar Transmission Company ("Westar"), an affiliate of KNEnergy; Anthem Energy Company, L.P. ("Anthem") an affiliate of KNEnergy; Mesa 9 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 Transco; Texaco Gas Marketing; Union Pacific Fuels; Vastar, an affiliate of ARCO; Associated Natural Gas, Inc. ("ANGI"); and Rangeline Corporation ("Rangeline"), an affiliate of Astra Resources. 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. 10 The following table sets forth volumes purchased from the Company's principal gas suppliers for the years ended September 30, 1994, 1993, and 1992. Volumes purchased (MMcf as metered) 1994: Westar and Anthem 47,842 Mesa 9,926 LIG 4,254 Texaco Gas Marketing 5,453 Union Pacific Fuels 5,825 Vastar 6,881 Associated Natural Gas, Inc. 3,283 Rangeline Corporation 2,210 1993: Westar and Anthem 45,031 Mesa 10,659 LIG 4,490 Tennessee Gas 2,575 Texas Gas 10,329 Associated Natural Gas, Inc. 3,291 Rangeline Corporation 1,946 1992: Westar and Anthem 38,539 Mesa 9,823 LIG 5,961 Tennessee Gas 2,594 Texas Gas 16,131 Associated Natural Gas, Inc. 3,049 Rangeline Corporation 1,295 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. Under the Westar contract, the Company has the right annually to elect to buy up to 20% of its monthly re- quirements for its Energas Division from other suppliers. The principal gas supply for the Company's Amarillo, Texas distribution system is furnished by Mesa under a long-term contract 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. In June 1992, the Company renegotiated the pricing provisions of its primary gas supply 11 contract for the Amarillo, Texas distribution system. The contract calls for a pricing formula which determines the prices the Company pays each year during the five year period that began January 1, 1993. 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. Under the contract, the Trans La Division has the right to purchase a portion of its requirements from suppliers other than LIG at market sensitive prices. At the end of the second contract year, the Trans La Division had the right to increase its purchases from others up to approximately 45% of its requirements which right was exercised by Trans La. LIG is required to provide standby service to back up the purchases from the other suppliers. The Company purchases some gas supplies for resale to certain of its Louisiana industrial customers from suppliers other than LIG. The Company's Louisiana industrial sales subsidiary, Trans Louisiana Industrial Gas Company, Inc., has entered into supply contracts at market sensitive prices with Enron Gas Services, Inc. for the major portion of its requirements, with the remainder being purchased under 30-day contracts from other suppliers. Gas provided by these suppliers is transported by LIG with delivery into the Trans La Division's system. The Western Kentucky Division transports its natural gas requirements through firm transportation agreements with 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 periods and to reduce the need to contract additional pipeline volumes to meet such peak demand periods. See "Item 2. Properties" for further information regarding the underground storage facilities. The Company has also bought gas in underground storage facilities of Tennessee Gas in Louisiana and Kentucky under FERC Order 636. The Greeley Gas Division purchases or transports approximately 72% 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 Pipeline Corporation, and NorAm. The state regulated pipelines are Public Service Company of Colorado, KPL Gas Service Company and Kansas Pipeline Partnership in Kansas. Approximately 28% of the Divisions's gas supply is purchased from local sources. Several of the operating areas are in or adjacent to natural gas producing fields. 12 Each of the Greeley Gas Division's operating areas is connected to one of the pipeline suppliers so that gas prices can be managed by using any of three sources: pipeline purchase, pipeline transport, or local purchases. Associated Natural Gas, Inc. is the main supplier to the Greeley Gas Division's largest district, the Greeley District. There are two contracts with ANGI - one contract for fixed-price base load gas put directly into the Greeley Gas Division distribution system from natural gas processing plants, and one contract for monthly market-sensitive spot purchases. Rangeline is the principal gas supplier for the Kansas and Missouri districts. Gas is transported through three different pipeline systems (Williams Natural Gas, KPL, and NorAm). The contract with Rangeline for gas transported through Williams Natural Gas expires in October 1996, the contract for the KPL transported gas expires in August 1996, and the contract for the NorAm transported gas is monthly. The contracts with Rangeline provide for market-sensitive pricing. The Company has not experienced 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. However, the distribution system in Kentucky has occasionally interrupted contractually interruptible industrial and large volume commercial customers. The most recent interruption for these Kentucky customers was in January 1994. 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 industrial 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 operations of the Trans La Division are under the jurisdiction of the Louisiana Public Service Commission, which regulates utility services, 13 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. The operations of the Western Kentucky Division are under the jurisdiction of the Kentucky Public Service 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 subject to the regulatory authority of the Colorado Public Utilities Commission, the Kansas Corporation Commission, and the Missouri Public Service Commission with respect to accounting, rates and charges, operating matters, and the issuance of securities. The Company operates in the various incorporated cities served by it in the states of Colorado, Kansas and Missouri under terms of non-exclusive franchises granted by the various cities. The franchises grant to the Company, among other things, the right to install and operate its gas distribution system within the city limits. Most of the Greeley Gas Division's wholesale gas suppliers are regulated by various federal and state commissions. The Company is 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 fiscal 1994 was derived from sales at rates set by or subject to approval by local or state authorities. The method of determining regulated rates varies among the six states in which the Company operates. 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. The Company has not always agreed with its regulators' decisions on its rate filings and has pursued the appeal and rehearing 14 procedures in Texas in 1985 and 1992 and in Kentucky in 1991. The Company also continually reviews its rates in all of its jurisdictions. 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. The following table sets forth the major rate requests made by the Company and the action taken on such requests: Amount Amount Jurisdiction Effective Date Requested Received ------------ ---------------- --------- -------- Texas West Texas System (a) November 1, 1984 $8,915,000 $5,000,000 September 9, 1991 5,987,000 4,600,000 November 18, 1994 2,581,000 1,502,000 (a) Amarillo December 11, 1985 4,850,000 3,400,000 November 25, 1992 4,398,000 2,130,000 Louisiana April 1, 1987 5,195,000 3,610,000 September 3, 1992 3,409,000 974,000 (b,c) March 1, 1993 (c) 730,000 (c) March 1, 1994 (c) 1,058,000 (c) Kentucky May 29, 1991 8,973,000 3,632,000 Colorado May 9, 1985 1,651,000 1,575,000 November 6, 1990 2,677,000 1,405,000 May 1, 1994 4,527,000 3,246,000 Kansas July 28, 1983 1,214,000 1,003,000 November 14, 1986 934,000 844,000 October 22, 1990 2,485,000 1,376,000 January 6, 1992 1,495,000 505,000 December 1, 1993 2,604,000 2,088,000 Missouri June 1, 1990 N/A (d) 49,000 - --------------------- (a) Excludes the City of Amarillo and certain smaller distribution systems. The $1,502,000 annual increase received in November 1994 applies to customers inside the city limits of the cities in this service area. The portion of the rate request for rural customers, who represent about 10% of the customers in this service area, is pending before the Railroad Commission of Texas. (b) The September 1992 rate order provided 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 provides for an annual adjustment 15 of rates to reflect changes in expenses and investment. The RSC provides the Company the opportunity to earn a return on common equity between 11.75% and 12.25%. (d) The rate request procedures in Missouri that are applicable to the Greeley Gas Division do not require the filing of a formal rate request. The rate increase received is established by the Missouri Public Service Commission on the basis of the Greeley Gas Division's responses to various data requests from the Commission. Consequently, the Greeley Gas Division did not specify a requested rate increase amount. 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. 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 1992, the FERC issued Order 636 and related clarifying orders. These orders provided for further restructuring of interstate pipeline services and are intended to completely unbundle pipeline trans- portation and sales functions. The FERC orders make gas transportation more accessible to users of large quantities of gas and also reduce procedural obstacles allowing such users to bypass local distribution companies, such as the Company, to purchase gas from other suppliers, and to secure transportation directly from pipeline companies. The Company has felt the impact of the competitiveness in the large volume market in some areas resulting from these changes and has dealt with this by seeking regulatory approval for competitive pricing on a case by case basis. 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. The Company competes in all aspects of its business with alternative energy sources, including, in particular, electricity. Competition for the residential and commercial customers is increasing. Promotional incentives, improved equipment efficiencies, and promotional rates all contribute to the acceptability of electric equipment. In late 1991, the Company opened four public retail facilities for the sale of compressed natural gas ("CNG") for vehicular use. The facilities are located at existing local gasoline stations. Prior to that time, the Company provided CNG for vehicular use only in limited situations (such as for school buses in certain school districts and for the fleet vehicles of certain businesses). With the opening of these public refueling stations the Company began competing against gasoline for vehicular fuel sales. 16 Employees At September 30, 1994, the Company employed 1,709 persons. See page 4 for number of employees by state. ITEM 2. PROPERTIES The Company owns an aggregate of 21,927 miles of underground pipelines throughout its gas distribution systems. These pipelines 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 underground gas storage facilities in Kentucky that have a total storage capacity of approximately 11.7 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 112 MMcf. Substantially all of the Company's properties in its Greeley Gas Division with a book value of approximately $59.2 million are subject to a lien under First Mortgage Bonds assumed by the Company in the acquisition of GGC. At September 30, 1994, the lien secured approximately $17.0 million of outstanding 9.4% Series J First Mortgage Bonds due May 1, 2021. The Company leases its executive and administrative headquarters in Dallas, Texas under leases that expire in 1997. The Company also maintains field offices throughout its distribution system, substantially all of which are located in leased premises. The Company holds franchises granted by the incorporated cities and towns and by each Louisiana parish that it serves. At September 30, 1994, 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 11 of notes to consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 17 EXECUTIVE OFFICERS The following table sets forth certain information as of September 30, 1994, regarding the executive officers of the Company: Name Age Office Currently Held ---- --- --------------------- Charles K. Vaughan 56 Chairman of the Board Ronald L. Fancher 51 President and Chief Executive Officer James F. Purser 44 Executive Vice President and Chief Financial Officer Robert F. Stephens 46 Executive Vice President - Corporate Operations H.F. Harber 52 Senior Vice President - Corporate Services Donald E. James 47 Senior Vice President and General Counsel Charles K. Vaughan has served as Chairman of the Board since the Company's inception on October 18, 1983. From October 1983 through February 1993, he additionally served as President and Chief Executive Officer. From March 1993 through May 1994, he served as Chief Executive Officer. Effective October 1, 1994, Mr. Vaughan elected to take early retirement from the Company, although he remains Chairman of the Board of Directors. Ronald L. Fancher served as a member of the Board of Directors from February 1984 through February 1993. He has served as President since March 1993 and has held the additional title of Chief Executive Officer since June 1994. He was also appointed to the Board of Directors in November 1994. Prior to joining the Company, he served as Chairman of the Board and Chief Executive Officer of Texas Commerce Bank in Odessa, Texas from 1983 until 1993. Additionally, he served as Chairman of the Board and Chief Executive Officer of Texas Commerce Bank - Lubbock, N.A. in January and February 1993. James F. Purser 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. Robert F. Stephens was named Executive Vice President - Corporate Operations in May 1989. He served 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. He previously served as Vice President, Corporate Development and Regulatory Affairs from August 1984 until April 1986. 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, as Vice President, Human Resources from May 1990 to July 1991, as Director of Human Resources from November 1987 until May 1990, as Manager, Compensation and Employment from 18 May 1987 until November 1987, and as Affirmative Action Coordinator from December 1983 until May 1987. Donald E. James was named Senior Vice President and General Counsel in August 1993. He previously served 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. 19 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 1994 and 1993 are listed below.
1994 1993 ---------------------------------- --------------------------------- Dividends Dividends High Low paid High Low paid Quarter ended: --------- --------- --------- -------- -------- --------- December 31 $21 1/8 $16 3/4 $ .22 $15 7/8 $13 1/2 $ .2125 March 31 20 17 3/4 .22 17 3/4 15 1/8 .2125 June 30 20 1/4 18 .22 19 3/4 16 1/4 .2125 September 30 19 16 3/8 .22 20 5/8 18 5/8 .2125 ----- ------ $ .88 $.8500 ===== ======
Prior to its acquisition, GGC made distributions to its shareholders in fiscal 1994 and 1993 of $120,000 and $893,000, respectively. 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, 1994 was 19,881. 20 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, -------------------------------------------- 1994 1993 1992 1991 1990 -------- -------- -------- -------- -------- (In thousands, except per share data) Operating revenues $499,808 $459,641 $403,353 $399,667 $409,975 ======== ======== ======== ======== ======== Net income $ 14,679 $ 17,544 $ 10,998 $ 9,612 $ 7,653 ======== ======== ======== ======== ======== Net income per share $ .97 $ 1.22 $ .80 $ .71 $ .60 ======== ======== ======== ======== ======== Atmos dividends declared per share $ .88 $ .85 $ .83 $ .80 $ .77 ======== ======== ======== ======== ======== Total assets at end of year $416,678 $391,618 $358,363 $338,714 $330,477 ======== ======== ======== ======== ======== Long-term debt at end of year $138,303 $105,853 $112,153 $116,461 $ 88,508 ======== ======== ======== ======== ======== Supplemental net income (1) $ 18,132 $ 10,570 $ 10,130 $ 9,497 ======== ======== ======== ======== Supplemental net income per share $ 1.26 $ .77 $ .75 $ .75 ======== ======== ======== ======== (1) Supplemental net income reflects results if GGC had not made an S Corporation election in 1987. 21 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. A consolidated five-year financial and statistical summary is included elsewhere herein. ACQUISITION OF GREELEY GAS COMPANY THROUGH MERGER 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 and 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. The Company believes that, while the merger may result in some dilution during the short term, it is expected to be non-dilutive over the long term with respect to earnings per share. The Company believes this transaction is consistent with its continuing long-term corporate development strategy of increasing the value of the Company through external growth. The Company believes this acquisition will help to further diversify both the geographic scope of its markets and the mix of its customer profile, thereby reducing its exposure to changes in the economic conditions in any given segment of its service area and will add to diversification in the areas of weather, regulatory environment, and economic environment. Over the longer term, the Company expects this combination to contribute to the stability and predictability of earnings and cash flow. 22 RATE ACTIVITY In September 1994, the Company filed to increase revenues by approximately $2.6 million for a portion of its Energas Company service area ("Energas Division"). The proposed rates would produce an overall increase of approximately 1.9% of current annual revenues generated from approximately 217,000 customers and reflects recovery of accrual accounting of postretirement benefits in accordance with SFAS No. 106. See Note 8 of the accompanying notes to consolidated financial statements. In November 1994, the Company implemented an annual revenue increase of approximately $1.5 million affecting about 90% of the customers in this portion of its Energas Division. GGC filed a request for an increase in annual revenues of $4.5 million with the Colorado Public Utility Commission ("Colorado Commission") in 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. The next step in the rate proceeding will be Phase II, which will address rate redesign issues. 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 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 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 has appealed to the Court of Appeals. During the period of 1991 through 1993, the Company also filed for and received small rate increases in certain other rate jurisdictions in its Energas Division totaling approximately $.3 million annually. The Company filed for a rate increase with the Louisiana Public Service Commission (the "Louisiana Commission") in November 1991 for its Louisiana service area ("Trans La Division"). The proposed rates would produce approximately $3.4 million per year in additional revenues, or an overall increase of approximately 9.8% for the Trans La Division. Effective September 3, 1992, the Louisiana Commission granted an increase of approximately $1.0 million per year in additional revenues, or an overall increase of approximately 2.8%. The rate order also allowed the Company to collect franchise taxes as a line item on the Company's bills which will reduce taxes, other than income taxes, by approximately $800,000 per year. The rate order also approved a rate stabilization clause 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 23 annual review. The rate stabilization clause 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 rate stabilization clause, an increase of $730,000 annually or 2% went into effect on March 1, 1993, and an increase of $1.1 million annually or 2.7% went into effect on March 1, 1994. In September 1990, the Kentucky Public Service Commission (the "Kentucky Commission") issued an order that increased annual revenues approximately $1.0 million for the Company's Kentucky service area. In May 1991, the Kentucky Commission issued an Order on Rehearing increasing allowed revenues an additional $2.6 million. In connection with this rate case the Company filed a Notice of Appeal with the Kentucky Court of Appeals in July 1993. The Company's appeal in Kentucky relates solely to the determination of the appropriate effective date of its last rate increase in Kentucky. The Kentucky Public Service Commission made the increase effective in May 1991, while the Company believes it should have become effective in September 1990. The Company lost the issue at the trial court level. If the Company is successful, it could recover approximately $1 million in additional revenue; if it is unsuccessful, there would be no impact on its revenue. Subsequent to September 30, 1994, the Kentucky Court of Appeals denied the Company's appeal. The Company is currently assessing its options for further appeals. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED The Company has not adopted Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits". See Note 9 of notes to consolidated financial statements. The rate treatment of SFAS No. 112 costs has not been determined at this time. Such costs are currently recorded and recovered in rates on the pay-as-you-go basis. The Company does not expect the adoption of this standard to have a material impact on its financial condition or results of operations. RESULTS OF OPERATIONS 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 received 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 thousand cubic feet ("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 billion cubic feet ("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. 24 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 assimilation 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 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. YEAR ENDED SEPTEMBER 30, 1993 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1992 Operating revenues increased to $459.6 million in 1993 from $403.4 million in 1992 due to colder weather, increased sales volumes and revenues for every customer type, rate increases received in Texas and Louisiana, and an increased number of customers in fiscal 1993. Total sales volumes increased 9.7 Bcf to 109.4 Bcf in 1993, as compared with 1992. Average gas sales revenues per Mcf increased $.16 to $4.02 in fiscal 1993 from 1992, while the average cost of gas per Mcf sold increased $.13 to $2.71. The number of meters in service increased to 636,159 at September 30, 1993 compared with 630,365 at September 30, 1992. Weather was 10% colder in 1993 than 1992, and was 2% colder than normal. Because of this colder weather, sales volumes to weather sensitive residential, commercial and public authority customers increased 5.8 Bcf, or 8%, to 78.0 Bcf in 1993, as compared with 1992. Sales volumes to industrial and agricultural customers increased 3.9 Bcf, or 14%, because of increased irrigation fuel demand in the Company's West Texas service area. Revenues from gas 25 transported for others increased $1.3 million to approximately $15.0 million in 1993. Average transportation fees decreased from $.42 per Mcf to $.38 per Mcf, while transportation volumes increased 7.6 Bcf to 39.8 Bcf in 1993 as compared with 1992. Average transportation fees decreased in 1993 because of increased competition for large volume customers in Kentucky. Gross profit increased by approximately 12% to $163.1 million in 1993 from $146.3 million in 1992. The primary factors contributing to the higher gross profit were increased rates and colder weather, as discussed above. Operating expenses, excluding income taxes, increased to $122.8 million in 1993 from $117.9 million in 1992 due to increased operating activity. Operation expense increased $3.5 million due to increased distribution expenses, outside services, wages and benefits expense. Income taxes increased to $10.1 million for 1993 from $4.8 million for 1992. The primary reasons for the increase were higher pre-tax profits and a higher effective tax rate. The effective tax rate increased to 36.5% in 1993 from 30.2% in 1992 because of reduced significance of permanent differences due to higher pre-tax profits and a one percent increase in the statutory rate to 35%, effective January 1, 1993. Operating income increased in 1993 by approximately 28% to $30.3 million. The increase in operating income resulted primarily from increased gross profit. Net income increased in 1993 by approximately 60% to $17.5 million from $11.0 million in 1992. This increase in net income resulted primarily from the increase in operating income. Also, interest expense decreased $.5 million in 1993, as compared with 1992, due to lower weighted average interest rates. Net income per share increased approximately 53% to $1.22 for 1993 compared with 1992, including the effects of an increase in average shares outstanding of approximately 4%. CAPITAL RESOURCES AND LIQUIDITY (See "Consolidated Statements of Cash Flows") Cash Flows from Operating Activities Cash flows from operating activities totaled $41.2 million for 1994 compared with $37.1 million for 1993 and $31.4 million for 1992. The decrease in net income in 1994 as compared with 1993 was more than offset by the net changes in assets and liabilities. Gas stored underground decreased in 1994 because of substantially lower gas prices during the summer of 1994 when the storage reservoir was 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 $48.4 million in 1994 compared with $42.2 million in 1993 and $39.5 million in 1992. Capital expenditures in fiscal 1994 amounted to $50.4 million compared with $43.1 million in 1993 and $42.2 million in 1992. Currently budgeted capital expenditures for 1995 total $56.1 million and include major expenditures 26 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 $7.7 million for 1994 compared with $3.7 million for 1993 and $8.3 million in 1992. 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 $12.7 million in cash dividends and distributions during 1994. The $2.6 million increase over 1993 primarily reflects an increase in the Company's quarterly dividend rate and an increase in the number of shares of common stock outstanding in 1994. The Company has increased its historical dividend rate in each of the last six years. Short-term financing activities. At September 30, 1994, the Company had committed lines of credit totaling $72.0 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, 1994, the Company also had uncommitted short-term credit lines of $130.0 million, of which $71.9 million was unused. At September 30, 1994, $40.0 million of notes payable to banks were classified noncurrent and long-term financing was completed subsequent to September 30, 1994. During 1994, notes payable increased $22.4 million compared with increases of $2.6 million during 1993 and $18.6 million in 1992. The increases in 1994 and 1992 were primarily due to funding of capital expenditures and repayment of long-term debt. The increase in 1993 was less than the increases in 1994 and 1992, 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 increased $5.4 million to $9.9 million for the year ended September 30, 1994 compared with the year ended September 30, 1993. Payments of long-term debt 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. At September 30, 1994, the Company was negotiating the private placement of $40.0 million of Senior Notes with two insurance companies. Scheduled payments of long-term debt in fiscal 1993 consisted of a $3.5 million installment on the Company's 9.75% Senior Notes and a $1.0 million payment on the 13.75% Series I First Mortgage Bonds. No long-term debt was issued in 1993. The Company entered into an agreement with an insurance company in August 1992, for a private placement of $10.0 million of unsecured Senior Notes due in annual installments of $1.0 million from 1997 through 2006, with interest to be paid semiannually at 7.95%. The net proceeds from the sale of the Senior Notes were used primarily to refinance an 8.4% note in the amount of $9.8 million. The Company also made scheduled installments of $4.5 million on its 9.75% Senior Notes, $1.0 million on the 13.75% Series I First Mortgage Bonds and a $.3 million installment on GGC's 13% Series G First Mortgage Bonds in fiscal 1992. The loan agreements 27 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 428,264, 897,089 and 306,880 shares of common stock in 1994, 1993 and 1992, respectively, for its Direct Stock Purchase Plan ("DSPP"), Employee Stock Ownership Plan and Incentive Stock Option Plan. The DSPP was implemented in August 1992. The DSPP has been amended to remove the direct stock purchase feature of the plan and has been renamed the Atmos Energy Corporation Dividend Reinvestment and Stock Purchase Plan ("DRSPP"). In 1994, 1993 and 1992, 173,801, 760,089 and 132,249 shares, respectively, were issued under the plan, generating proceeds of $3.0 million, $13.4 million and $1.9 million, respectively. At September 30, 1994, 712,596 shares were available for future issuance under the plan. 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 1995. 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 --------------------------------------------------- Year ended September 30, December 31 March 31 June 30 September 30 Total ------------------------ ------------ --------- -------- ------------ ---------- (In thousands, except for percentages) 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% 1993 ---- Operating revenues $130,700 $166,238 $91,219 $71,484 $459,641 28% 36% 20% 16% 100% Net income (loss) $ 6,765 $ 13,760 $ 831 $(3,812) $ 17,544 39% 78% 5% (22)% 100%
Inflation The Company believes that inflation has caused and will continue to cause increases in certain operating expenses and has required assets and will continue to require assets to be re- placed 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, 1994 and 1993, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 1994. Our audits also included the financial statement schedules listed in the Index at Item 14(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1994 and 1993, and its consolidated results of operations and its cash flows for each of the three years in the period ended September 30, 1994 in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. Ernst & Young LLP Dallas, Texas November 9, 1994 31 ATMOS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS September 30, 1994 1993 -------- -------- ASSETS (In thousands, except share data) Property, plant and equipment Utility plant $537,834 $496,153 Construction in progress 5,858 5,359 -------- -------- 543,692 501,512 Less accumulated depreciation and amortization 216,285 202,237 -------- -------- Net property, plant and equipment 327,407 299,275 Current assets Cash and cash equivalents 2,766 2,286 Accounts receivable, less allowance for doubtful accounts of $787 in 1994 and $963 in 1993 29,678 29,200 Inventories 5,888 6,064 Gas stored underground 12,657 17,603 Prepayments 2,309 4,240 -------- -------- Total current assets 53,298 59,393 Deferred charges and other assets 35,973 32,950 -------- -------- $416,678 $391,618 CAPITALIZATION AND LIABILITIES ======== ======== Shareholders' equity Common stock, no par value (stated at $.005 per share); authorized 50,000,000 shares; issued and outstanding 1994 - 15,297,166 shares, 1993 - 14,868,902 shares $ 77 $ 74 Additional paid-in capital 102,456 94,279 Retained earnings 47,023 45,076 -------- -------- Total shareholders' equity 149,556 139,429 Long-term debt 138,303 105,853 -------- -------- Total capitalization 287,859 245,282 Current liabilities Current maturities of long-term debt 4,000 6,300 Notes payable to banks 18,100 35,700 Accounts payable 21,975 27,803 Taxes payable 4,864 3,797 Customers' deposits 8,257 7,862 Other current liabilities 7,038 6,455 -------- -------- Total current liabilities 64,234 87,917 Deferred income taxes 30,184 32,614 Deferred credits and other liabilities 34,401 25,805 -------- -------- $416,678 $391,618 ======== ======== See accompanying notes to consolidated financial statements. 32 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME Year ended September 30, ------------------------------- 1994 1993 1992 -------- -------- -------- (In thousands, except per share data) Operating revenues $499,808 $459,641 $403,353 Purchased gas cost 331,571 296,532 257,091 -------- -------- -------- Gross profit 168,237 163,109 146,262 Operating expenses Operation 92,132 82,185 78,642 Maintenance 5,888 6,335 5,695 Depreciation and amortization 18,841 17,433 17,205 Taxes, other than income 16,808 16,806 16,398 Income taxes 8,102 10,073 4,753 -------- -------- -------- Total operating expenses 141,771 132,832 122,693 -------- -------- -------- Operating income 26,466 30,277 23,569 Other income (expense) Interest income 168 327 376 Other, net 335 239 876 -------- -------- -------- Total other income 503 566 1,252 Interest charges 12,290 13,299 13,823 -------- -------- -------- Net income $ 14,679 $ 17,544 $ 10,998 ======== ======== ======== Net income per share $ .97 $ 1.22 $ .80 ======== ======== ======== Atmos dividends declared per share (Note 2) $ .88 $ .85 $ .83 ======== ======== ======== Average shares outstanding 15,195 14,338 13,789 ======== ======== ======== 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 at September 30, 1991, as adjusted for the 3-for-2 stock split 10,170,938 $ 51 $73,392 $16,867 Adjustment for pooling of interests with GGC (Note 2) 3,493,995 17 941 19,690 ---------- ---- ------- ------- Balance, September 30, 1991, as restated 13,664,933 68 74,333 36,557 Net income - - - 10,998 Cash dividends ($.83 per share) - - - (8,516) GGC distributions - - - (402) Common stock issued Stock option plan 6,750 - 71 - Direct stock purchase plan 132,249 1 1,849 - Employee stock ownership plan 167,881 1 2,288 - ---------- ---- ------- ------- 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 ========== ==== ======= ======= See accompanying notes to consolidated financial statements. 34 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended September 30, 1994 1993 1992 -------- ------- ------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES Net income $14,679 $16,594 $10,998 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization Charged to depreciation and amortization 18,841 16,480 17,205 Charged to other accounts 1,476 3,377 4,598 Deferred income taxes 244 2,733 349 Other 2,101 622 281 ------- ------- ------- 37,341 39,806 33,431 Change in assets and liabilities (Increase) decrease in accounts receivable (478) 1,564 (2,202) (Increase) decrease in inventories 176 708 (84) (Increase) decrease in gas stored underground 4,946 (6,176) (14) (Increase) decrease in prepayments 1,931 1,873 (287) (Increase) decrease in deferred charges and other assets (3,824) (10,908) 586 Increase (decrease) in accounts payable (7,128) (58) 1,196 Increase (decrease) in taxes payable (1,314) 195 930 Increase (decrease) in customers' deposits 395 (61) 322 Increase in other current liabilities 583 1,804 803 Increase (decrease) in deferred credits and other liabilities 8,596 8,398 (3,269) ------- ------- ------- Net cash provided by operating activities 41,224 37,145 31,412 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (50,355) (43,143) (42,169) Retirements of property, plant and equipment 1,906 935 2,629 ------- ------- ------- Net cash used in investing activities (48,449) (42,208) (39,540) - Continued - 35 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Year ended September 30, 1994 1993 1992 -------- -------- -------- (In thousands) CASH FLOWS FROM FINANCING ACTIVITIES Net increase in notes payable $ 22,400 $ 2,563 $18,636 Proceeds from issuance of long-term debt - - 10,000 Cash dividends and distributions paid (12,732) (10,155) (8,918) Repayment of long-term debt (9,850) (4,500) (15,608) Issuance of common stock 7,887 15,742 4,210 -------- ------- ------- Net cash provided by financing activities 7,705 3,650 8,320 -------- ------- ------- Net increase (decrease) in cash and cash equivalents 480 (1,413) 192 Cash and cash equivalents at beginning of year 2,286 3,699 3,507 -------- ------- ------- Cash and cash equivalents at end of year $ 2,766 $ 2,286 $ 3,699 ======== ======= ======= 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 Corpora- tion 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 ex- pense. 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 constru- ction. 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 3.5% and 3.7% for the years ended September 30, 1994 and 1993, 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, 1994 and 1993 include assets of the Company's qualified defined benefit retirement plans in excess of the plans' obligations in the amounts of $12,275,000 and $13,289,000, respectively, and Company assets related to the nonqualified retirement plans at September 30, 1994 and 1993 of $15,735,000 and $12,758,000, 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. Deferred credits and other liabilities - Deferred credits and other liabilities include customer advances for construction of $8,428,000 and $7,769,000 at September 30, 1994 and 1993, respect- ively; obligations under capital leases of $6,294,000 and $6,389,000 at September 30, 1994 and 1993, respectively; and obligations under the Company's nonqualified retirement plans of $11,151,000 and $8,317,000 at September 30, 1994 and 1993, respectively. 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 class- es 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 interes- ts; 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 September 30, 1993 balance sheet, as presented, is the combined balance sheets of Atmos and GGC as of September 30, 1993. The restated consolidated statements of income and cash flows for the year ended September 30, 1992 include Atmos operations for the year then ended and GGC operations for the year ended December 31, 1992. The restated consolidated 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, 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 responsib- ility 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 de- ferred 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. Supple- mental 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 1992 -------- -------- (In thousands, except per share data) Supplemental net income $ 18,132 $ 10,570 ======== ======== Supplemental net income per share $ 1.26 $ .77 ======== ======== 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 September 30, December 31, 1993 1993 1992 ----------------- -------- -------- (In thousands) Operating revenues Atmos $119,223 $388,495 $340,117 GGC 26,278 71,146 63,236 -------- -------- -------- $145,501 $459,641 $403,353 ======== ======== ======== Net income Atmos $ 5,458 $ 15,712 $ 10,031 GGC 1,630 1,832 967 -------- -------- -------- $ 7,088 $ 17,544 $ 10,998 ======== ======== ======== 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 dividends declared by Atmos reflect the per share dividends declared by Atmos Energy Corporation for each of the three years ended September 30, 1994. The restated cash dividends and distributions per share reflect the total amounts paid by Atmos and GGC to their shareholders in each of those three 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 1992 ---- ---- ---- Atmos dividends declared per share $.88 $.85 $.83 ==== ==== ==== Restated cash dividends and distributions per share, including GGC $.84 $.71 $.65 ==== ==== ==== 40 3. Long-term debt and notes payable Long-term debt at September 30, 1994 and 1993 consisted of the following: 1994 1993 --------- -------- (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 5,000 8,000 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 18,000 20,000 First Mortgage Bonds, 9.4% Series J, due May 1, 2021 17,000 17,000 First Mortgage Bonds, 13% Series G - 1,600 Unsecured 10% Notes, due December 31, 2011 2,303 2,303 First Mortgage Bonds, 13.75% Series I - 3,250 Notes payable to banks financed with long-term debt 40,000 - -------- -------- 142,303 112,153 Less amounts classified as current (4,000) (6,300) -------- -------- $138,303 $105,853 ======== ======== Subsequent to September 30, 1994, the Company obtained commitments to enter into new note purchase agreements with two insurance companies to issue at par $20,000,000 of unsecured Senior Notes at 8.07% payable in annual installments of $4,000,000 beginning October 31, 2002 through October 31, 2006 with semi- annual interest payments and $20,000,000 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. At September 30, 1994, $40,000,000 of notes payable to banks were classified as long-term. 41 The Company entered into a note purchase agreement with an insurance company in August 1992, for a private placement of $10,000,000 of unsecured Senior Notes at 7.95%. The net proceeds from the sale of the Senior Notes were used primarily to refinance an 8.4% note in the amount of $9.8 million. 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, 1994, approximately $44,492,000 of shareholders' equity was not so restricted. As of September 30, 1994, all of the Company's utility plant assets in Colorado, Kansas and Missouri with a book value of approximately $59,173,000 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): 1995 $ 4,000 1996 7,000 1997 9,000 1998 8,000 1999 8,000 Thereafter 106,303 -------- $142,303 ======== Notes payable to banks The Company has committed short-term, unsecured bank credit facilities totaling $72,000,000, all of which was unused at September 30, 1994. One facility of $60,000,000 requires a commitment fee of 1/8 of 1% on the unused portion. A second facility for $12,000,000 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 $130,000,000, of which $71,900,000 was unused as of September 30, 1994. 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 Information related to notes payable to banks follows: 1994 1993 1992 -------- -------- -------- (In thousands, except for percents) Notes outstanding at September 30 prior to long-term financing $58,100 $35,700 $32,600 Reclassification for long-term financing subsequent to year end (40,000) - - -------- -------- -------- Notes outstanding at September 30 $18,100 $35,700 $32,600 Weighted average interest rate at September 30 5.6% 4.1% 4.7% Maximum amount outstanding during the year $58,100 $50,300 $36,800 Daily average amount outstanding during the year $26,597 $19,801 $12,078 Weighted average interest rate during the year computed on a daily basis 4.3% 4.2% 5.3% Notes payable to shareholders and employees Notes payable to shareholders and employees of GGC were outstanding at times prior to September 30, 1993. They were for six-month terms and bore interest at rates ranging from 4.0% to 4.5%. Interest incurred on such notes aggregated $11,326 and $28,593 for 1993 and 1992, respectively. 4. Income taxes The components of income tax expense for 1994, 1993 and 1992 are as follows: 1994 1993 1992 ------- ------- ------- (In thousands) Current $7,858 $7,340 $4,653 Deferred 244 2,733 100 ------ ------ ------ $8,102 $10,073 $4,753 ====== ====== ====== Included in the provision for income taxes are state income taxes of $328,000, $890,000, and $403,000 for 1994, 1993, and 1992, 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 the new 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 43 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. 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, 1994 and October 1, 1993 are presented below (in thousands): 1994 1993 ------- ------- Deferred tax assets Costs expensed for book purposes and capitalized for tax purposes $ 914 $ 744 Accruals not currently deductible for tax purposes 1,929 689 Customer advances 2,365 2,128 Nonqualified benefit plans 5,074 2,740 Postretirement benefits 1,442 - Other, net 1,198 1,407 ------- ------- Total deferred tax assets 12,922 7,708 Deferred tax liabilities Tax and book basis of utility plant 37,316 31,949 Prepaid pensions 4,640 5,134 Other, net 1,150 565 ------- ------- Total deferred tax liabilities 43,106 37,648 ------- ------- Net deferred tax liabilities $30,184 $29,940 ======= ======= SFAS No. 109 deferred accounts for rate regulated entities (included in other deferred credits): Liabilities $ 2,647 $ 2,673 ======= ======= 44 During 1993 and 1992, 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 and 1992 were as follows: 1993 1992 ------ ------ (In thousands) Excess of tax over financial depreciation and amortization $1,754 $ 351 Items capitalized for financial reporting and recognized currently for tax reporting 416 388 Deferred gas service revenue recognized currently for tax reporting 1,464 453 Other, net (901) (1,092) ------ ------ Total deferred income taxes $2,733 $ 100 ====== ====== Reconciliations of the provisions for income taxes computed at the statutory rate to the reported provisions for income taxes for 1994, 1993 and 1992 are set forth below: Liability Method Deferred Method --------- ----------------- 1994 1993 1992 -------- ------- ------ (In thousands) Tax at statutory rate of 34% through December 31, 1992 and 35% thereafter $ 7,992 $ 9,603 $5,356 Financial expenses, not deductible for tax reporting 503 680 218 Common stock dividends deductible for tax reporting (573) (462) (446) State taxes 328 682 244 Other, net (148) (430) (619) ------- ------- ------ Provision for income taxes $ 8,102 $10,073 $4,753 ======= ======= ====== 5. Stock split On February 9, 1994, the Board of Directors of Atmos approved 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. All share and 45 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 The Company issued 428,264 shares of its common stock in fiscal 1994 in connection with its Direct Stock Purchase Plan, Restricted Stock Grant Plan and Employee Stock Ownership Plan. It also issued common stock in connection with the GGC merger (Note 2) and the stock split (Note 5). The Company has an Employee Stock Ownership Plan as discussed in Note 7. The Company has registered 600,000 shares for issuance under the plan, of which 134,776 shares were available for future issuance on September 30, 1994. 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"). The DRSPP is now available to shareholders of record only. Participants in the DRSPP may have all or part of their dividends reinvested at a 3% discount from market prices. DRSPP participants may purchase additional shares of Company common stock as often as weekly with optional cash payments of at least $25, up to an annual maximum of $60,000. At September 30, 1994, 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 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 46 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 has 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 and 1992: 1993 1992 ------------------- ------------------- Price Price Shares per share Shares per share ------------------ ------- ----------- Outstanding options at beginning of year 6,000 $9.25-10.63 12,750 $9.25-10.63 Exercised (6,000) 9.25-10.63 (6,750) 9.25-10.63 ------ ------ Outstanding options at end of year - - 6,000 9.25-10.63 ====== ====== Exercisable options at end of year - 6,000 Options available for future grants (pre-split) 8,150 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 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 47 previously issued shares purchased in the open market or shares issued directly from the Company. The total number of shares of restricted stock that may be awarded under the plan was increased to 600,000 shares (900,000 post-split shares) after receiving shareholder approval in 1993. During 1994, 1993 and 1992, 109,500, 25,500 and 51,750 shares, respectively, were awarded under the plan. Prior to 1992, 328,950 shares were awarded under the plan. Related compensation expense of $1,164,000, $735,000 and $673,000 was recognized in 1994, 1993 and 1992, respectively. At September 30, 1994, 384,300 shares were available for award. 7. Employee retirement and stock ownership plans At September 30, 1994, 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. The following table sets forth the combined funded status of the Company's defined benefit retirement plans at June 30, 1994 and 1993 and amounts recognized in the Company's balance sheets at September 30, 1994 and 1993 for the plans covering all employees except for employees of the Greeley Gas Division: 1994 1993 --------- --------- (In thousands) Actuarial present value of benefit obligations Accumulated benefit obligation, including vested benefits of $87,906 and $86,141 in 1994 and 1993, respectively $ (89,680) $ (87,006) ========= ========= Projected benefit obligation $(102,223) $(100,214) Plan assets at fair value 110,864 114,772 --------- --------- Funded status 8,641 14,558 Unrecognized net asset being recognized over 13 years (633) (851) Unrecognized prior service cost 1,423 482 Unrecognized net (gain)/loss 1,883 (2,032) --------- --------- Prepaid pension cost $ 11,314 $ 12,157 ========= ========= 48 Net periodic pension cost for 1994, 1993 and 1992 included the following components: 1994 1993 1992 -------- -------- -------- (In thousands) Service cost $ 2,575 $ 2,182 $ 2,117 Interest cost 7,774 7,258 6,783 Actual return on plan assets (631) (15,049) (12,534) Net amortization and deferral (8,875) 6,316 3,981 -------- -------- -------- Net periodic pension cost $ 843 $ 707 $ 347 ======== ======== ======== The weighted-average discount rates used in determining the actuarial present value of the projected benefit obligation were 8.375% and 7.75% at June 30, 1994 and 1993, respectively. The rate of increase in future compensation levels reflected in such determination was 4.5% and 5.0% for the years ended September 30, 1994 and 1993, respectively. The expected long-term rate of return on assets was 9.5%, 8.5% and 9.0% for the years ended September 30, 1994, 1993 and 1992, 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. 49 The following table sets forth the Greeley Gas Division plan's funded status at September 30, 1994 and 1993: 1994 1993 --------- -------- (In thousands) Actuarial present value of benefit obligations Accumulated benefit obligation, including vested benefits of $12,849 and $9,959 in 1994 and 1993, respectively $ (13,206) $ (10,088) ========= ========= Projected benefit obligation $ (15,020) $ (13,359) Plan assets at fair value 13,140 14,204 --------- -------- Funded status (1,880) 845 Unrecognized net asset being recognized over 15 years (2,100) (2,390) Unrecognized prior service cost 455 - Unrecognized net loss 3,186 2,677 --------- -------- (Accrued) prepaid pension cost $ (339) $ 1,132 ========= ======== Net periodic pension cost (credit) for the Greeley Gas Division plan for 1994, 1993 and 1992 included the following components: 1994 1993 1992 ------- ------- ------- (In thousands) Service cost $ 486 $ 374 $ 385 Interest cost on projected benefit obligation 1,039 954 952 Actual return on plan assets 441 (1,180) (1,146) Net amortization and deferral (1,795) (257) (218) ------- ------- ------- Net periodic pension cost (credit) $ 171 $ (109) $ (27) ======= ======= ======= Accumulated plan benefits were computed using the Projected Unit Credit funding method. The discount rate and rate of in- crease in future compensation levels used in determining the actuarial present value of the projected benefit obligations were 8.375% and 4.5%, respectively, in 1994 and 7.75% and 6.25%, respectively, in 1993. The expected long-term rate of return on plan assets was 9.5% and 9.0% in 1994 and 1993, respectively. Plan assets consist primarily of corporate bonds, equity securit- ies, mutual funds, partnership interests, and other miscellaneous investments. The actual return on plan assets in 1994 resulted in a loss of $.4 million due to writedowns of certain plan assets to reflect current market value. 50 Effective October 1, 1987, the Company adopted a nonqualified Supplemental Executive Benefits Plan ("Supplemental Plan") which provides additional pension benefits to the executive officers and certain other employees of the Company. Expense recognized in connection with the Supplemental Plan during fiscal 1994, 1993 and 1992 was $2,062,000, $1,492,000 and $872,000, respectively. The Company sponsors an Employee Stock Ownership Plan ("ESOP"). Full time employees who have completed one year of service, as defined in the plan, are eligible to participate. Each participant enters into a salary reduction agreement with the Company pursuant to which the participant's salary is reduced by an amount not less than 2% nor more than 10%. Taxes on the amount by which the participant's salary is reduced are deferred pursuant to Section 401(k) of the Internal Revenue Code. The amount of the salary reduction is contributed by the Company to the ESOP for the account of the participant. The Company may make a matching contribution for the account of the participant in an amount determined each year by the Board of Directors, which amount must be at least equal to 25% of all or a portion of the participant's salary reduction. For the 1994 plan year, the Board of Directors elected to match 100% of each participant's salary reduction contribution up to 4% of the participant's salary. These matching percentages have also been approved for the 1995 plan year. Matching contributions to the ESOP amounted to $1,780,000, $1,413,000, and $1,324,000 for 1994, 1993 and 1992, respectively. The Directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code of 1986 and applicable regulations of the Internal Revenue Service. The Company recorded a charge of $1,000,000 for a discretionary contribution in the year ended September 30, 1993. Company contributions to the plan are expensed as incurred. Effective January 1, 1988, the Greeley Gas Division adopted a 401(k) plan that covers substantially all the Greeley Gas Division employees. Employee contributions are limited to 6% of base compensation. The Company matches 50% of employee contributions. Total employer contributions to the 401(k) plan were $141,000, $230,000, and $288,000 for the periods ended September 30, 1994, 1993, and 1992, respectively. Contributions to the plan were discontinued on March 31, 1994 and participants were enrolled in the Atmos ESOP on April 1, 1994. 8. Other postretirement benefits In addition to providing pension benefits, the Company provides certain other postretirement benefits for retired employees, the major benefit being health care. To be eligible for these benefits, an employee must retire under the terms of the Company's retirement plans. Prior to 1994, the cost of other postretirement benefits was recognized by expensing claims and annual insurance premiums as incurred. In fiscal 1993 and 1992, these costs totaled $1,453,000 and $1,626,000, respectively. 51 Effective October 1, 1993, the Company adopted Financial Accounting Standards No. 106 ("SFAS No. 106"), "Employers' Accounting for Postretirement Benefits Other Than Pensions". SFAS No. 106 focuses principally on postretirement health care benefits and significantly changed the practice of accounting for post- retirement benefits on a pay-as-you-go basis by requiring accrual of such benefit costs at Atmos on an actuarial basis from the date each employee reaches age 45 until the date of full eligibility for such benefits. The Company is amortizing on a straight line basis the initial transition obligation of $33,354,000 over 20 years. The effect of adopting the new rules increased net periodic postretirement benefit cost for the year ended September 30, 1994 by $3,789,000 and decreased net income for the period by $2,440,000. Approximately $746,000 of this increased cost was recovered through rates during 1994. Atmos sponsors two defined benefit postretirement plans other than pensions. One plan provides medical, dental, vision and life insurance benefits to retired employees of Greeley Gas Company. The other offers medical benefits to all other retired Atmos employees. Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company and attain 10 consecutive years of service. Participant contributions are required under these plans. Prior to June 1994, the plans were not funded. In June 1994, the Company made its first quarterly payment to the external trust set up to fund SFAS No. 106 costs in excess of the pay-as- you-go cost in Kansas in accordance with an order of the Kansas Corporation Commission. The amount of funding will ultimately depend upon the ratemaking treatment allowed in the Company's various rate jurisdictions. The components of net periodic postretirement benefit cost for the year ended September 30, 1994 are as follows (in thou- sands): Service cost $1,817 Interest cost 2,269 Amortization of transition obligation 1,668 ------ $5,754 ====== 52 The following is a reconciliation of the funded status of the plans to the net postretirement benefits liability on the balance sheet as of September 30, 1994 and October 1, 1993 (in thousands): 1994 1993 -------- -------- Accumulated postretirement benefit obligation Retirees $(18,083) $(18,237) Fully eligible employees (6,827) (8,596) Other employees (4,206) (6,521) -------- -------- (29,116) (33,354) Plan assets 274 - -------- -------- Accumulated postretirement benefit obligation in excess of plan assets (28,842) (33,354) Unrecognized prior service cost (2,256) - Unrecognized net (gain) or loss (4,105) - Unrecognized transition obligation 31,686 33,354 -------- -------- Accrued postretirement benefits liability $ (3,517) $ - ======== ======== In the latest actuarial calculation of the accrued postre- tirement benefits liability, the assumed health care cost trend rate used to estimate the cost of postretirement benefits was 10.5% for the 1993-1994 year, 9.5% for the 1994-1995 year and is assumed to decrease gradually to 5.0% for 1999-2000 and remain at that level thereafter. Similarly, the dental trend rate is 8.0% for the 1993-1994 year and gradually decreases to 7.0% for 1995- 1996 at which time dental benefits will be discontinued. The trend for vision benefits is assumed to remain level for all years at 4.5%. The effect of a 1% increase in the assumed health care cost trend rate for each future year is $410,000 on the annual aggregate of the service and interest cost components of net periodic postretirement benefit costs and $2,279,000 on the accumulated postretirement benefit obligation as of September 30, 1994. The assumed discount rate, the rate at which liabilities could be settled, was 8.25% and 7.0% as of September 30, 1994 and 1993, respectively. The Company is currently recovering other postretirement benefit ("OPEB") costs through its regulated rates on a pay-as- you-go basis in a majority of its service areas in Texas, Kentucky and Louisiana. It is allowed to recover OPEB costs in its remaining service areas under SFAS No. 106 accrual accounting. The rate recovery of SFAS No. 106 cost by jurisdiction is discuss- ed below. Management believes that accrual accounting in accor- dance with SFAS No. 106 is appropriate and will seek rate recovery of accrual-based expenses in all of its ratemaking jurisdictions. In May 1993, the Louisiana Commission issued an order for all utilities under its jurisdiction to continue to use the pay-as- you-go accounting method for rate treatment of SFAS No. 106 costs. 53 Utilities may apply to the Louisiana Commission for authority to recognize a regulatory asset to be amortized on a pay-as-you-go basis to bridge the gap between ratemaking and accounting. The Louisiana Commission retains the flexibility to examine individual companies' accounting for SFAS No. 106 costs to determine if special exceptions to this order are warranted. Recovery of SFAS No. 106 costs were not allowed in the Company's Rate Stabilization Clause increase implemented March 1, 1994. In June 1992, the Kentucky Public Service Commission ("Kentucky Commission") declined a request by a group of utilities to grant a blanket commitment for the future recovery of SFAS No. 106 costs in excess of pay-as-you-go costs for all utilities. The Kentucky Commission's order stated that each utility could file an individual application to seek recovery of such costs. At a rehearing held in December 1992, the Kentucky Commission affirmed its initial order. In May 1993, the Company filed rate requests which included SFAS No. 106 costs in Fritch and Sanford, Texas and for the surrounding environs. The rates for the environs are subject to the jurisdiction of the Railroad Commission of Texas ("Railroad Commission"). In its order of August 30, 1993, the Railroad Commission approved recovery of SFAS No. 106 costs and internal funding. In September 1994 the Company filed for a rate increase with its West Texas cities. The rate case, which included SFAS No. 106 costs, was settled with those cities subsequent to September 30, 1994. In September 1993, GGC filed a rate request for its Colorado service area which included SFAS No. 106 costs. In May 1994, the Company began implementing new rates in its Colorado service area. The new rates increased annual revenues by $3,200,000 and included recovery of accrual-based SFAS No. 106 costs. By order issued in October 1994, the Colorado Public Utility Commission approved recovery of SFAS No. 106 costs with the condition of external funding of the difference between SFAS No. 106 expense and pay-as- you-go expense. By order issued in November 1993, the Kansas Corporation Commission approved recovery of SFAS No. 106 expenses beginning in December 1993 with the condition that the difference between amounts computed as SFAS No. 106 expense and pay-as-you-go expense shall be remitted quarterly to an external trust fund. The Company will seek rate recovery of accrual based SFAS No. 106 expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses. The portion of this additional expense in excess of the pay-as-you-go amount in these ratemaking jurisdictions that will immediately or ultimately be allowed in rates cannot presently be determined. The ultimate impact of the adoption of SFAS No. 106 on the Company's financial position and results of operations will not be known with certain- 54 ty until the regulatory treatment that will be allowed in each of the Company's ratemaking jurisdictions is determined. 9. Postemployment benefits The Company also provides postemployment benefits, primarily workers' compensation, to former or inactive employees after employment but before retirement. The Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" ("SFAS No. 112"), which applies to such benefits and will be effective for the Company's 1995 fiscal year. Under SFAS No. 112, employers are required to recognize the obligation to provide postemployment benefits if certain conditions are met. Postemployment benefit costs are currently recorded and recovered in rates on the pay-as-you-go basis. The rate treatment of SFAS No. 112 accrual based costs has not been determined at this time. The reduction in future earnings, if any, that would result from this accrual would be offset to the extent that it is approved to be recovered in rates. Based on a preliminary actuarial study, the Company currently estimates that the cumulative effect of impleme- ntation of SFAS No. 112 and the increase in future annual costs will not have a material adverse effect on earnings. 10. Supplementary information Taxes, other than income taxes for 1994, 1993 and 1992 consisted of the following: 1994 1993 1992 ------- ------- ------- (In thousands) Gross receipts $ 7,252 $ 7,312 $ 7,393 Ad valorem 5,124 4,992 4,618 Payroll 3,475 3,353 3,322 Other 957 1,149 1,065 ------- ------ ------- $16,808 $16,806 $16,398 ======= ======= ======= 11. Contingencies On March 15, 1991, suit was filed in the 15th Judicial District Court of Lafayette Parish, Louisiana, by the "Lafayette Daily Advertiser" and others against the Trans La Division, Trans Louisiana Industrial Gas Company, Inc. ("TLIG"), a wholly owned subsidiary of the Company, and Louisiana Intrastate Gas Corporati- on and certain of its affiliates ("LIG"). LIG is the Company's primary supplier of natural gas in Louisiana and is not otherwise affiliated with the Company. The plaintiffs purported to represent a class consisting of all residential and commercial gas customers in the Trans La Division's service area. Among other things, the lawsuit alleged 55 that the defendants violated antitrust laws of the state of Louisiana by manipulating the cost-of-gas component of the Trans La Division's gas rate to the purported customer class, thereby causing such purported class members to pay a higher rate. The plaintiffs made no specific allegation of an amount of damages. The defendants brought an appeal to the Louisiana Supreme Court of rulings by the trial court and the Third Circuit Court of Appeal which denied defendants' exceptions to the jurisdiction of the trial court. It was the position of the defendants that the plaintiffs' claims amount to complaints about the level of gas rates and should be within the exclusive jurisdiction of the Louisiana Commission. On January 19, 1993, the Louisiana Supreme Court issued a decision reversing in part the lower courts' rulings, dismissing all of plaintiffs' claims against the defendants which seek damages due to alleged overcharges and further ruling that all such claims are within the exclusive jurisdiction of the Louisiana Commission. Any claims which seek damages other than overcharges were remanded to the trial court but were stayed pending the completion of the Louisiana Commission proceeding referred to below. The Louisiana Commission has instituted a docketed proceeding for the purpose of investigating the costs included in the Trans La Division's purchased gas adjustment component of its rates. Both the Trans La Division and LIG are parties to the proceeding. Much of the discovery in this proceeding has been conducted and a procedural schedule has been established. The Company believes the allegations as they relate to the Company, whether brought in court or at the Louisiana Commission, are without merit, and that the chances of a material adverse outcome are remote. The Company will continue to vigorously protect its interest in this matter. From time to time, claims are made and lawsuits are filed against the Company arising out of the ordinary business of the Company. In the opinion of the Company's management, liabilities, if any, arising from these actions are either covered by insurance, adequately reserved for by the Company or would not have a material adverse effect on the financial condition of the Company. 12. Statement of cash flows Supplemental disclosures of cash flow information for 1994, 1993 and 1992 are presented below: 56 1994 1993 1992 ------- ------- ------- (In thousands) Cash paid for Interest $12,756 $13,436 $14,496 Income taxes 6,352 8,190 3,754 13. Leases The Company has entered into noncancelable leases involving office space and warehouse space. The remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Net property, plant and equipment included amounts for capital leases of $5,664,000 and $6,029,000 at September 30, 1994 and 1993, respectively. The related future minimum lease payments at September 30, 1994 were as follows: Capital Operating leases leases -------- -------- (In thousands) 1995 $ 1,716 $ 5,071 1996 1,717 4,817 1997 1,683 3,808 1998 1,628 2,958 1999 1,504 3,036 Thereafter 11,297 23,335 ------- ------- Total minimum lease payments 19,545 43,025 Less amount representing contingent payments from increases in the Consumer Price Index (946) (20) ------- ------- Net minimum lease payments 18,599 $43,005 ======= Less amount representing interest (12,305) ------- Present value of net minimum lease payments $ 6,294 ======= Consolidated rent expense amounted to $6,490,000, $5,277,000 and $5,395,000 for fiscal 1994, 1993 and 1992, respectively. Rents are expensed and recovered in rates on a pay-as-you-go basis. 57 SUPPLEMENTARY DATA Quarterly Financial Data (Unaudited) Summarized unaudited quarterly financial data are presented below. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts.
Quarter ended ---------------------------------------------------------------------------------- December 31, March 31, June 30, September 30, ----------------- ----------------- ----------------- ----------------- 1993 1992 1994 1993 1994 1993 1994 1993 -------- -------- -------- -------- -------- -------- -------- -------- (In thousands, except per share data) Operating revenues $145,501 $130,700 $186,944 $166,238 $ 90,013 $ 91,219 $ 77,350 $ 71,484 Gross profit 48,421 42,638 59,366 58,606 31,790 34,463 28,660 27,402 Operating income (loss) 10,302 9,730 16,345 16,877 1,433 3,847 (1,614) (177) Net income (loss) 7,088 6,765 13,242 13,760 (1,224) 831 (4,427) (3,812) Net income (loss) per share .47 .48 .87 .97 (.08) .06 (.29) (.26)
58 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding directors is incorporated herein by reference from the Company's definitive proxy statement for the annual meeting of shareholders on February 8, 1995. Information regarding executive officers is included in Part I. ITEM 11. EXECUTIVE COMPENSATION Incorporated herein by reference from the Company's definitive proxy statement for the annual meeting of shareholders on February 8, 1995. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Incorporated herein by reference from the Company's definitive proxy statement for the annual meeting of shareholders on February 8, 1995. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Incorporated herein by reference from the Company's definitive proxy statement for the annual meeting of shareholders on February 8, 1995. 59 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1 and 2. Financial statements and financial statement schedules The financial statements and financial statement schedules listed in the accompanying Index to Financial Statements and Financial Statement Schedules are filed as part of this annual report. 3. Exhibits The exhibits listed in the accompanying Exhibits Index are filed as part of this annual report. The exhibits numbered 10.18(a) through 10.26(c) are management contracts or compensatory plans or arrangements. (b) Reports on Form 8-K None. 60 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES (Item 8, 14(a) 1 and 2) Page Number Financial statements: Consolidated balance sheets at September 30, 1994 and 1993 31 Consolidated statements of income for the years ended September 30, 1994, 1993 and 1992 32 Consolidated statements of shareholders' equity for the years ended September 30, 1994, 1993 and 1992 33 Consolidated statements of cash flows for the years ended September 30, 1994, 1993 and 1992 34 Notes to consolidated financial statements 36-56 Independent auditors' report 30 Financial statement schedules for the years ended September 30, 1994, 1993 and 1992: V - Property, plant and equipment 61 VI - Accumulated depreciation and amortization of property, plant and equipment 62 All other financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and accompanying notes thereto. 61 ATMOS ENERGY CORPORATION SCHEDULE V PROPERTY, PLANT AND EQUIPMENT Balance at Retire- Balance beginning Additions ments at end of of year at cost or sales year --------- --------- -------- --------- (In thousands) Year ended September 30, 1994: Utility plant $496,153 $49,544 $7,863 $537,834 Construction in progress 5,359 811 312 5,858 -------- ------- ------ -------- $501,512 $50,355 $8,175 $543,692 ======== ======= ====== ======== Year ended September 30, 1993: Utility plant $458,548 $41,824 $4,219 $496,153 Construction in progress 4,065 1,319 25 5,359 -------- ------- ------ -------- $462,613 $43,143 $4,244 $501,512 ======== ======= ====== ======== Year ended September 30, 1992: Utility plant $421,048 $41,613 $4,113 $458,548 Construction in progress 3,519 556 10 4,065 -------- ------- ------ -------- $424,567 $42,169 $4,123 $462,613 ======== ======= ====== ======== Depreciation is provided at various rates on a straight-line basis over the estimated useful lives of the assets. Such rates range from 2% to 33% per year with the average rate currently being approximately 3.5% per year. 62 ATMOS ENERGY CORPORATION SCHEDULE VI ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT Additions Deductions Balance charged to at to retirements, Balance beginning costs and renewals and at end of year expenses replacements of year --------- --------- ------------ ------- (In thousands) Year ended September 30, 1994: Utility plant $202,237 $20,317 $ 6,269 $216,285 Year ended September 30, 1993: Utility plant $185,689 $19,857 $ 3,309 $202,237 Year ended September 30, 1992: Utility plant $165,380 $21,803 $ 1,494 $185,689 63 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ATMOS ENERGY CORPORATION (Registrant) By /s/ JAMES F. PURSER ----------------------- James F. Purser Executive Vice President and Chief Financial Officer Date: December 15, 1994 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints James F. Purser, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ CHARLES K. VAUGHAN Chairman of December 15, 1994 ------------------------- the Board Charles K. Vaughan /s/ RONALD L. FANCHER President and December 15, 1994 ------------------------- Chief Executive Ronald L. Fancher Officer 64 /s/ JAMES F. PURSER Executive Vice December 15, 1994 ------------------------- President and James F. Purser Chief Financial Officer /s/ DAVID L. BICKERSTAFF Vice President December 15, 1994 ------------------------- and Controller David L. Bickerstaff (Principal accounting officer) /s/ TRAVIS W. BAIN, II Director December 15, 1994 ------------------------- Travis W. Bain, II /s/ DAN BUSBEE Director December 15, 1994 ------------------------- Dan Busbee /s/ PHILLIP E. NICHOL Director December 15, 1994 ------------------------- Phillip E. Nichol /s/ JOHN W. NORRIS, JR. Director December 15, 1994 ------------------------- John W. Norris, Jr. /s/ CARL S. QUINN Director December 15, 1994 ------------------------- Carl S. Quinn /s/ LEE E. SCHLESSMAN Director December 15, 1994 ------------------------- Lee E. Schlessman /s/ RICHARD WARE II Director December 15, 1994 ------------------------- Richard Ware II /s/ DEWEY G. WILLIAMS Director December 15, 1994 ------------------------- Dewey G. Williams 65 EXHIBITS INDEX Item 14. (a) (3) Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 3.1 Restated Articles of Incorporation Exhibit (3)(a) of Form dated November 10, 1989 10-K for fiscal year ended September 30, 1991 3.2 By-Laws of Atmos Energy Corporation Exhibit (3) of Form 10-Q (Amended and restated as of May 11, for quarter ended June 1994) 30, 1994 4.1 Specimen Common Stock Certificate Exhibit (4) of the (Energas Company) October 28, 1983 Form 10 (File No. 0-11249) 4.2 Specimen Common Stock Certificate Exhibit (4) (b) of Form (Atmos Energy Corporation) 10-K for fiscal year ended September 30, 1988 (File No. 1-10042) 4.3(a) Rights Agreement, dated as of April Exhibit (1) of Form 8-K 27, 1988, between the Company and filed May 10, 1988 (File Morgan Shareholder Services Trust No. 0-11249) Company 4.3(b) Amendment No. 1 to Rights Agreement, dated August 10, 1994 4.3(c) Certificate of Adjusted Price, dated August 15, 1994 9 Not applicable 10.1(a) Note Purchase Agreement, dated Exhibit (10)(a)(i) of December 30, 1986, by and between Form 10-K for fiscal year the Company and John Hancock Mutual ended September 30, 1991 Life Insurance Company Note Purchase Agreement, dated December 30, 1986, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of NYNEX Corporation dated January 1, 1984 for Employee Pension Plans - NYNEX - John Hancock - Private Placement. (Agreement is identical to the Hancock Agreement listed above except as to the parties thereto.) 66 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.1(b) Letter, dated November 13, 1987, Exhibit 28(a) of Form 8-K from John Hancock Mutual Life filed January 7, 1988 Insurance Company to the Company (File No. 0-11249) Letter, dated November 13, 1987, from Mellon Bank, N.A., Trustee under Master Trust Agreement of NYNEX Corporation dated January 1, 1984 for Employee Pension Plans - NYNEX - John Hancock - Private Placement to the Company (Mellon letter is identical to the Hancock letter listed above except as to the parties thereto.) 10.1(c) Amendment to Note Purchase Exhibit (10)(a)(iii) of Agreement, dated October 11, 1989, Form 10-K for fiscal year by and between the Company and John ended September 30, 1989 Hancock Mutual Life Insurance (File No. 1-10042) Company revising Note Purchase Agreement dated December 30, 1986 Amendment to Note Purchase Agreement, dated October 11, 1989, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of NYNEX Corporation dated January 1, 1984 for Employee Pension Plans - NYNEX - John Hancock - Private Placement revising Note Purchase Agreement dated December 30, 1986. (This amendment is identical to the Hancock amendment listed above except as to the parties thereto.) 10.1(d) Amendment to Note Purchase Exhibit (10)(a)(iv) of Agreement, dated November 12, 1991, Form 10-K for fiscal year by and between the Company and John ended September 30, 1991 Hancock Mutual Life Insurance Company revising Note Purchase Agreement dated December 30, 1986. 67 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- Amendment to Note Purchase Agreement, dated November 12, 1991, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of NYNEX Corporation dated January 1, 1984 for Employee Pension Plans - NYNEX - John Hancock - Private Placement revising Note Purchase Agreement dated December 30, 1986. (This amendment is identical to the Hancock amendment listed above except as to the parties thereto.) 10.2(a) Note Purchase Agreement, dated as of Exhibit 10(c) of Form 8-K December 21, 1987, by and between filed January 7, 1988 the Company and John Hancock Mutual (File No. 0-11249) Life Insurance Company Note Purchase Agreement, dated as of December 21, 1987, by and between the Company and John Hancock Charitable Trust I (Agreement is identical to Hancock Agreement listed above except as to the parties thereto.) Note Purchase Agreement dated as of December 21, 1987, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement (Agreement is identical to Hancock Agreement listed above except as to the parties thereto.) 10.2(b) Amendment to Note Purchase Exhibit (10)(b)(ii) of Agreement, dated October 11, 1989, Form 10-K for fiscal year by and between the Company and John ended September 30, 1989 Hancock Mutual Life Insurance (File No. 1-10042) Company revising Note Purchase Agreement dated December 21, 1987 68 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- Amendment to Note Purchase Agreement, dated October 11, 1989, by and between the Company and John Hancock Charitable Trust I revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment listed above except as to the parties thereto.) Amendment to Note Purchase Agreement, dated October 11, 1989, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987 (Amendment is identical to Hancock amendment listed above except as to the parties thereto.) 10.2(c) Amendment to Note Purchase Exhibit 10(b)(iii) of Agreement, dated November 12, 1991, Form 10-K for fiscal year by and between the Company and John ended September 30, 1991 Hancock Mutual Life Insurance Company revising Note Purchase Agreement dated December 21, 1987 Amendment to Note Purchase Agreement, dated November 12, 1991, by and between the Company and John Hancock Charitable Trust I revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment listed above except as to the parties thereto.) 69 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- Amendment to Note Purchase Agreement, dated November 12, 1991, by and between the Company and Mellon Bank, N.A., Trustee under Master Trust Agreement of AT&T Corporation, dated January 1, 1984, for Employee Pension Plans - AT&T - John Hancock - Private Placement revising Note Purchase Agreement dated December 21, 1987. (Amendment is identical to Hancock amendment above except as to the parties thereto.) 10.3(a) Note Purchase Agreement, dated as of Exhibit 10(c) of Form 10- October 11, 1989, by and between the K for fiscal year ended Company and John Hancock Mutual Life September 30, 1989 (File Insurance Company No. 1-10042) 10.3(b) Amendment to Note Purchase Exhibit 10(c)(ii) of Form Agreement, dated as of November 12, 10-K for fiscal year 1991, by and between the Company and ended September 30, 1991 John Hancock Mutual Life Insurance Company revising Note Purchase Agreement dated October 11, 1989 10.4(a) Note Purchase Agreement, dated as of Exhibit 10(f)(i) of Form August 29, 1991, by and between the 10-K for fiscal year Company and The Variable Annuity ended September 30, 1991 Life Insurance Company 10.4(b) Amendment to Note Purchase Exhibit 10(f)(ii) of Form Agreement, dated November 26, 1991, 10-K for fiscal year by and between the Company and The ended September 30, 1991 Variable Annuity Life Insurance Company revising Note Purchase Agreement dated August 29, 1991 10.5 Note Purchase Agreement, dated as of Exhibit (10)(f) of Form August 31, 1992, by and between the 10-K for fiscal year Company and The Variable Annuity ended September 30, 1992 Life Insurance Company 10.6(a) Service Agreement No. 50,772 between Greeley Gas Company and Public Service Company of Colorado (West Gas Supply Co. prior to merger with PSCO) dated August 1, 1992 70 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.6(b) Transportation Storage Service Agreement No. TA-0544 between Greeley Gas Company and Williams Natural Gas Company dated October 1, 1993 10.6(c) No-Notice Transportation Service Agreement No. 31013, Rate Schedule NNT-1, between Greeley Gas Company and Colorado Interstate Gas Company, as amended, dated October 1, 1993 10.6(d) Firm Transportation Service Agreement No. 35009, Rate Schedule TF2, between Greeley Gas Company and Colorado Interstate Gas Company, as amended, dated October 1, 1993 10.7(a) Amarillo Supply Agreement dated January 2, 1993 between the Company and Mesa Operating Company 10.7(b) Interruptible Gas Transportation and Exhibit (10)(g)(iv) of Sales Agreement dated January 1, Form 10-K for fiscal year 1991, between Mesa Operating Limited ended September 30, 1992 Partnership and Energas Company regarding transportation charges to Mesa 10.7(c) Letter agreement between the Company Exhibit (10)(h)(vi) of and Mesa Operating Limited Form 10-K for fiscal year Partnership dated March 21, 1989, ended September 30, 1989 regarding transportation rates (File No. 1-10042) 10.8(a) Gas Sales Agreement between the Exhibit (10)(i)(i) of Company and Westar Transmission Form 10-K for fiscal year Company dated January 1, 1986, as ended September 30, 1989 amended by Letter Agreement dated (File No. 1-10042) November 21, 1986, and Agreement dated December 9, 1988, revising the pricing formula for city gate sales 10.8(b) Amendment to Gas Sales Agreement, Exhibit (10)(h)(ii) of dated February 27, 1987, between the Form 10-K for fiscal year Company and Westar Transmission ended September 30, 1992 Company 10.8(c) Amendment to Gas Sales Agreement, Exhibit (10)(h)(iii) of dated January 1, 1988, between Cabot Form 10-K for fiscal year Gas Supply Corporation ("CGSC") and ended September 30, 1992 the Company 71 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.9(a) Gas Transportation Agreement between Exhibit 10(i)(i) of Form the Company and Westar Transmission 10-K for fiscal year Company dated January 1, 1986, as ended September 30, 1991 amended by letter agreement dated November 21, 1986 10.9(b) Amendment to Gas Transportation Exhibit (10)(i)(ii) of Agreement, dated January 1, 1988, Form 10-K for fiscal year between CGSC and the Company ended September 30, 1992 10.10 Supplemental Gas Sales Agreement, Exhibit (10)(j) of Form dated January 1, 1988, between CGSC 10-K for fiscal year and the Company ended September 30, 1992 10.11 Gas Purchase and Sales Agreement, Exhibit (10)(k) of Form dated January 1, 1988, between Cabot 10-K for fiscal year Energy Marketing Corporation and ended September 30, 1992 EnerMart, Inc. 10.12 Gas Sales Agreement, dated January Exhibit (10)(l) of Form 1, 1988, between the Company and Gas 10-K for fiscal year Marketing, Inc. ("GMI"), relating to ended September 30, 1992 Amarillo supplemental supplies 10.13 Gas Sales Agreement, dated January Exhibit (10)(m) of Form 1, 1988, between the Company and 10-K for fiscal year GMI, relating to West Texas ended September 30, 1992 supplemental supplies 10.14 Settlement Agreement, dated January Exhibit (10)(n) of Form 15, 1988, between CGSC and the 10-K for fiscal year Company ended September 30, 1992 10.15(a) Agreement for Natural Gas Service Exhibit 10(o)(ii) of Form for Distribution and Resale between 10-K for fiscal year Trans La and LIG dated October 28, ended September 30, 1991 1991 10.15(b) Agreement for Intrastate Exhibit 10(o)(iii) of Transportation of Natural Gas Form 10-K for fiscal year between Trans La and LIG dated ended September 30, 1991 October 28, 1991 10.16(a) Gas Transportation Agreement between Exhibit 10.1 of Form 10-Q Texas Gas Transmission Corporation for quarter ended ("Texas Gas") and Western Kentucky December 31, 1993 Gas Company, a division of Atmos Energy Corporation ("Western Ken- tucky") dated November 1, 1993 (Contract no. T3817, zone 2) 72 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.16(b) Gas Transportation Agreement between Exhibit 10.2 of Form 10-Q Texas Gas and Western Kentucky dated for quarter ended November 1, 1993 (Contract no. December 31, 1993 T3770, zone 2) 10.16(c) Gas Transportation Agreement between Exhibit 10.3 of Form 10-Q Texas Gas and Western Kentucky Gas for quarter ended dated November 1, 1993 (Contract no. December 31, 1993 T3355, zone 3) 10.16(d) Gas Transportation Agreement between Exhibit 10.4 of Form 10-Q Texas Gas and Western Kentucky Gas for quarter ended dated November 1, 1993 (Contract no. December 31, 1993 T3819, zone 4) 10.16(e) Gas Transportation Agreement between Exhibit 10.5 of Form 10-Q Texas Gas and Western Kentucky Gas for quarter ended dated November 1, 1993 (Contract no. December 31, 1993 N0210, zone 2, Contract no. N0340, zone 3, Contract no. N0435, zone 4) 10.17(a) Gas Transportation Agreement, Exhibit 10.17(a) of Form Contract No. 2550, dated September 10-K for fiscal year 1, 1993, between Tennessee Gas ended September 30, 1993 Pipeline Company, a division of Tenneco, Inc. ("Tennessee Gas"), and Western Kentucky, Campbellsville Service Area 10.17(b) Gas Transportation Agreement, Exhibit 10.17(b) of Form Contract No. 2546, dated September 10-K for fiscal year 1, 1993, between Tennessee Gas and ended September 30, 1993 Western Kentucky, Danville Service Area 10.17(c) Gas Transportation Agreement, Exhibit 10.17(c) of Form Contract No. 2385, dated September 10-K for fiscal year 1, 1993, between Tennessee Gas and ended September 30, 1993 Western Kentucky, Greensburg et al Service Area 10.17(d) Gas Transportation Agreement, Exhibit 10.17(d) of Form Contract No. 2551, dated September 10-K for fiscal year 1, 1993, between Tennessee Gas and ended September 30, 1993 Western Kentucky, Harrodsburg Service Area 73 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.17(e) Gas Transportation Agreement, Exhibit 10.17(e) of Form Contract No. 2548, dated September 10-K for fiscal year 1, 1993, between Tennessee Gas and ended September 30, 1993 Western Kentucky, Lebanon Service Area 10.18(a) *Employment Agreement amended and Exhibit 10(r)(i) of Form restated as of August 8, 1991, 10-K for fiscal year between the Company and Charles K. ended September 30, 1991 Vaughan 10.18(b) *Employment Agreement amended and Exhibit 10(r)(ii) of Form restated as of August 8, 1991, 10-K for fiscal year between the Company and Robert F. ended September 30, 1991 Stephens 10.18(c) *Employment Agreement amended and Exhibit 10(r)(iii) of restated as of August 8, 1991, Form 10-K for fiscal year between the Company and Don E. James ended September 30, 1991 10.18(d) *Employment Agreement amended and Exhibit 10(r)(iv) of Form restated as of August 8, 1991, 10-K for fiscal year between the Company and James F. ended September 30, 1991 Purser 10.18(e) *Employment Agreement dated March 1, Exhibit 10.1 of Form 10-Q 1993, between the Company and Ronald for quarter ended March L. Fancher 31, 1993 10.18(f) *Employment Agreement dated August Exhibit 10.18(g) of Form 11, 1993, between the Company and 10-K for fiscal year H.F. Harber ended September 30, 1993 10.19 *1983 Incentive Stock Option Plan of Exhibit 10(u) of Form 10- Energas Company K for fiscal year ended September 30, 1990 10.20 *The Atmos Energy Corporation Exhibit (10)(t) of Form Supplemental Executive Benefits 10-K for fiscal year Plan, effective October 1, 1987, ended September 30, 1992 Restated as of November 11, 1992 10.21(a) *The Atmos Energy Corporation Exhibit (10)(u) of Form Restricted Stock Grant Plan, 10-K for fiscal year effective October 1, 1987, amended ended September 30, 1992 and restated as of May 13, 1992 10.21(b) *Amendment No. 1 to the Atmos Energy Exhibit 10.1 of Form 10-Q Corporation Restricted Stock Grant for the quarter ended Plan (Restated as of May 13, 1992) December 31, 1992 74 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.21(c) *Amendment No. 2 to the Atmos Energy Exhibit 10 of Form 10-Q Corporation Restricted Stock Grant for the quarter ended Plan (Restated as of May 13, 1992) June 30, 1993 10.21(d) *Amendment No. 3 to the Atmos Energy Exhibit 10.21(d) of Form Corporation Restricted Stock Grant 10-K for fiscal year Plan (Restated as of May 13, 1992) ended September 30, 1993 10.22 *Atmos Energy Corporation Annual Exhibit 10(x) of Form 10- Performance Bonus Plan for Corporate K for fiscal year ended Officers, restated as of November 8, September 30, 1990 1989 10.23(a) *Atmos Energy Corporation Mini-Med Exhibit 10(w)(i) of Form Plan, as restated effective April 1, 10-K for fiscal year 1989 ended September 30, 1992 10.23(b) *Amendment No. 1 to the Atmos Energy Exhibit (10)(w)(ii) of Corporation Mini-Med Plan Form 10-K for fiscal year ended September 30, 1992 10.23(c) *Amendment No. 2 to the Atmos Energy Exhibit (10)(w)(iii) of Corporation Mini-Med Plan Form 10-K for fiscal year ended September 30, 1992 10.23(d) *Amendment No. 3 to the Atmos Energy Exhibit 10(w)(iv) of Form Corporation Mini-Med Plan 10-K for fiscal year ended September 30, 1992 10.23(e) *Amendment No. 4 to the Atmos Energy Exhibit 10.23(e) of Form Corporation Mini-Med Plan 10-K for fiscal year ended September 30, 1993 10.24 *Atmos Energy Corporation Deferred Exhibit 10(x) of Form 10- Compensation Plan for Outside K for fiscal year ended Directors September 30, 1992 10.25 *Atmos Energy Corporation Retirement Exhibit 10(y) of Form 10- Plan for Outside Directors K for fiscal year ended September 30, 1992 10.26(a) *Description of Car Allowance Exhibit 10.26(a) of Form Payments 10-K for fiscal year ended September 30, 1993 10.26(b) *Description of Financial and Estate Exhibit 10.26(b) of Form Planning Program 10-K for fiscal year ended September 30, 1993 10.26(c) *Description of Sporting Events Exhibit 10.26(c) of Form Program 10-K for fiscal year ended September 30, 1993 75 Page Number or Exhibit Incorporation by Number Description Reference to -------- ------------------------------------ ------------------------- 10.27(a) Seventh Supplemental Indenture, Exhibit 10.1 of Form 10-Q dated as of October 1, 1983 between for quarter ended June Greeley Gas Company ("The Greeley 30, 1994 Gas Division") and the Central Bank of Denver, N.A. ("Central Bank") 10.27(b) Ninth Supplemental Indenture, dated Exhibit 10.2 of Form 10-Q as of April 1, 1991, between The for quarter ended June Greeley Gas Division and Central 30, 1994 Bank 10.27(c) Bond Purchase Agreement, dated as of Exhibit 10.3 of Form 10-Q April 1, 1991, between The Greeley for quarter ended June Gas Division and Central Bank 30, 1994 10.27(d) Tenth Supplemental Indenture, dated Exhibit 10.4 of Form 10-Q as of December 1, 1993, between the for quarter ended June Company and Colorado National Bank, 30, 1994 formerly Central Bank 11 Not applicable 12 Not applicable 13 Not applicable 16 Not applicable 18 Not applicable 21 Subsidiaries of the registrant Exhibit 22 of Form 10-K for fiscal year ended September 30, 1992 22 Not applicable 23 Consent of independent auditors 24 Power of Attorney Signature page of Form 10-K for fiscal year ended September 30, 1994 27 Financial Data Schedule for Atmos for year ended September 30, 1994 28 Not applicable 99 Not applicable _________________________ * This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement." 76 EX-4 2 EXHIBIT 4.3(b) AMENDMENT NO. 1 TO RIGHTS AGREEMENT WHEREAS, Atmos Energy Corporation ("Atmos") and First National Bank of Boston ("Bank of Boston") are parties to that certain Rights Agreement dated April 27, 1988 (the "Rights Agreement"); and WHEREAS, Atmos and the Bank of Boston desire to amend the Rights Agreement; NOW, THEREFORE, effective as of August 10, 1994, the Rights Agreement is hereby revised and amended in the following respects; 1. Section 11(a)(i) is amended by adding the following language at the end of the first sentence of such Section: "; provided, however, that if the record date for any such dividend, subdivision, combination or reclassification shall occur prior to the Distribution Date, the Company shall make an appropriate adjustment to the Purchase Price (taking into account any additional Rights which may be issued as a result of such dividend, subdivision, combination or reclassification), in lieu of adjusting (as described above) the number of Common Shares (or other capital shares, as the case may be) issuable upon exercise of the Rights." IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 1 to be duly executed and their respective corporate seals to be hereunto affixed and attested, all as of August 10, 1994. ATMOS ENERGY CORPORATION ATTEST: BY: /s/ Glen A. Blanscet By: /s/ Ronald L. Fancher -------------------------- -------------------------- Glen A. Blanscet, Secretary Ronald L. Fancher, President and Chief Executive Officer FIRST NATIONAL BANK OF BOSTON ATTEST: BY: /s/ David Cosden By: /s/ Colleen H. Shea --------------------------- -------------------------- EX-4 3 EXHIBIT 4.3(c) CERTIFICATE OF ADJUSTED PRICE Pursuant to Section 12 of that certain Rights Agreement dated as of April 27, 1988 (the "Rights Agreement") by and between Atmos Energy Corporation (successor to Energas Company) ("Company") and First National Bank of Boston (successor in interest to Morgan Shareholder Services Trust Company) (the "Rights Agent"), the Company does hereby make the following certification: 1. As of May 16, 1994, The Company completed a three-for-two split of its common stock, effected in the form of a stock dividend. 2. Pursuant to Section 11(a)(i) of the Rights Agreement, as amended, the Purchase Price for each share of common stock pursuant to the exercise of a Right must be adjusted to reflect such stock split. 3. The Purchase Price has been adjusted from $45 per share to $30 per share. Executed this 15th day of August, 1994. ATMOS ENERGY CORPORATION ATTEST: /s/ Glen A. Blanscet By: Don E. James --------------------------- ------------------------ Glen A. Blanscet, Secretary Don E. James Sr. Vice President and General Counsel EX-10 4 EXHIBIT 10.6(a) WestGas Document No. 50772 SERVICE AGREEMENT THIS AGREEMENT made and entered into as of this 2nd day of October, 1992, by and between WESTERN GAS SUPPLY COMPANY (Seller) and GREELEY GAS COMPANY (Buyer); WITNESSETH: That the parties hereto in consideration of the covenants and payments herein set forth, do mutually covenant and agree as follows: 1. SALE AND PURCHASE Seller agrees to sell and deliver and Buyer agrees to receive, purchase and pay for natural gas under the rate schedules, at the points of delivery and under the terms and conditions as herein set forth. 2. VOLUMETRIC OBLIGATIONS Volumes in MCF @ Billing Pressure p.s.i.a. and 60 deg. F. ------------------ Demand Volumes -------------- Contract Demand 38,007 Peaking Service Demand 7,943 Annual Volumes -------------- Peaking Service Capacity Volumes 72,000 Total Annual Volumes 5,240,000 3. POINTS OF DELIVERY, MAXIMUM VOLUME OBLIGATIONS AND PRESSURES Maximum Maximum Assumed Delivery Delivery Atmospheric Billing Pressure Obligation Pressure Pressure Location P.S.I.G. MCF/day (psia) (psia) See Attached Exhibit "B" - Greeley Eastern 4. APPLICABLE RATE SCHEDULE The natural gas delivered hereunder shall be paid for by Buyer under Seller's Rate Schedule CG and CPS, or any superseding rate schedule or schedules, on file and in effect from time to time with The Public Utilities Commission of the State of Colorado (Commission). This agreement in all respects shall be subject to the provisions of such rate schedule or schedules and to the applicable provisions of Seller's General Terms and Conditions of service on file and in effect from time to time with said Commission, all of which are available for inspection by Buyer and are made a part hereof by reference. 5. TERM This agreement shall become effective August 1, 1992, and continue and remain in force and effect for a primary term ending September 30, 1995. This agreement shall continue after the expiration of said primary term for additional periods of five (5) years each, unless written notice is given not later than two (2) years prior to the expiration of said primary term by either party to the other of its desire to cancel this agreement at the end of said primary term, or at the end of any such five (5) year period by notice given not later than two (2) years prior to the expiration of such five (5) year period. 6. CANCELLATION OF PRIOR CONTRACTS When this agreement becomes effective, it supersedes and cancels the following contracts or service agreements between the parties hereto: Service Agreement dated November 16, 1986, WestGas Document No. 50772. 7. BILLING PERIOD The billing period for gas purchased under this agreement shall be from the 1st day of one month to the 1st day of the next succeeding month; provided, however, that Seller reserves to itself the right to change such billing period upon the giving of not less than thirty (30) days notice to Buyer. 8. CHANGES Nothing in this agreement, either expressed or implied, shall prohibit such future changes in the rate, terms or conditions under which service is rendered as may become applicable to the sale of gas hereunder in accordance with law. 9. CONDITIONS OF SERVICE (a) Minimum Charges: The Demand Charge of the CG rate plus the Peaking Service Demand Charge and Peaking Capacity Charge of the CPS rate. (b) Billing: On or before the tenth (10th) day of each month, Seller shall render to Buyer a statement of the quantities of natural gas delivered to Buyer during the preceding billing period and the amount due from Buyer to Seller. When information necessary for billing purposes is in control of Buyer, Buyer shall furnish such information to Seller on or before the twenty- eighth (29th) day of each month. (c) Payment: On or before the twentieth (20th) day of each month, Buyer shall pay Seller, at the location designated on the billing statement, the amount due from Buyer for the Preceding billing period as billed by Seller. (d) Seller odorizes its natural gas only to meet require- ments of the Department of Transportation, as stated in the Transportation of Natural and Other Gas by Pipeline, Minimum Safety Standards, Part 192.625. Seller assumes no responsibility for odorization of the natural gas after its delivery to Buyer and it is agreed that Buyer shall not rely on Seller's odorization of the natural gas to meet any requirement or duty imposed on Buyer with respect to the odorization of natural gas. Buyer agrees to indemnify Seller from claims arising out of injury, death or damage from gas after its delivery to Buyer based upon lack of or inadequate odorization of the gas. 10. ASSIGNMENT This agreement may be assigned by either of the parties hereto to: (a) Any person, firm or corporation acquiring all, or substantially all, of the business of said party; or (b) A trustee or trustees, individual or corporate, as security for bonds or other obligations or securities; but it may not be otherwise assigned without the consent of the other party hereto. Any assignment by Buyer shall not be effective, and Buyer shall remain liable to pay for all gas delivered hereunder, until Seller receives a written statement, executed by the assignee, agreeing to assume all of Buyer's obligations hereunder. Except as above restricted, this agreement shall be binding upon and inure to the benefit of the successors and assignees of each of the parties hereto. IN WITNESS WHEREOF, the parties hereto have caused this agreement to be duly signed by their respective officers the day and year first above written. TRANSPORTER: WESTERN GAS SUPPLY COMPANY Witness/Attest: By /s/ Linn T. Leeburg ---------------------------- Linn T. Leeburg Executive Vice President /s/ - ---------------------------- Assistant Secretary Taxpayer I.D. Number 84-6015506 SHIPPER: GREELEY GAS COMPANY Witness/Attest: By /s/ Richard W. Remley ---------------------------- Richard W. Remley ---------------------------- Name Senior Vice President ---------------------------- Title /s/ September 28, 1992 - ---------------------------- ---------------------------- Dated WestGas Document No. 50772 Taxpayer I.D. Number 84-1152755 Exhibit "B" Effective August 1, 1992 Supersedes Exhibit "B" Effective May 26, 1986 POINTS OF DELIVERY, MAXIMUM DAILY VOLUME OBLIGATIONS AND PRESSURES Maximum Maximum Assumed Delivery Delivery Atmospheric Billing Pressure Obligation Pressure Pressure Location P.S.I.G. MCF/day (psia) (psia) Ault T. B. Station 45 850 12.29 14.65 Corsey 35 95 12.27 14.65 E. Keenesburg 100 105 12.27 14.65 Eaton 100 2,200 12.37 14.65 Gilcrest 60 550 12.37 14.65 Hill-N-Park 60 270 12.37 14.65 Hudson 40 400 12.27 14.65 Keenesburg 40 340 12.27 14.65 Kersey 125 1,050 12.43 14.65 La Salle 45 1,200 12.40 14.65 Lucerne 45 700 12.37 14.65 Monfort Fed Lots #2 70 650 12.39 14.65 North Greeley 175 16,000 12.39 14.65 Nunn 40 150 12.20 14.65 Pierce 70 400 12.24 14.65 Platteville 50 750 12.32 14.65 Prospect Valley 60 100 12.33 14.65 Roggen 60 50 12.37 14.65 South Gate 60 50 12.39 14.65 South Greeley 70 5,300 12.39 14.65 South Roggen 35 50 12.37 14.65 West Greeley 175 22,000 12.39 14.65 West Hudson 80 4001 2.27 14.65 West La Salle 35 90 12.40 14.65 Plus Miscellaneous Mainline Taps EX-10 5 EXHIBIT 10.6(b) TRANSPORTATION STORAGE SERVICE AGREEMENT UNDER RATE SCHEDULE TSS THIS AGREEMENT is made and entered into this 1st day of October, 1993 by and between WILLIAMS NATURAL GAS COMPANY, a Delaware corporation, having its principal office in Tulsa, Oklahoma, hereinafter referred to as "WNG," and GREELEY GAS COMPANY, a Delaware corporation, having its principal office in Denver, Colorado, hereinafter referred to as "Shipper." IN CONSIDERATION of the premises and of the mutual covenants and agreements herein contained, WNG and Shipper agree as follows: ARTICLE I QUANTITY 1.1 Subject to the provisions of this Agreement and of WNG's Rate Schedule TSS, WNG agrees to receive such quantities of natural gas as Shipper may cause to be tendered to WNG at the Primary Receipt Point(s) designated on Exhibit A which are selected from WNG's Master Receipt Point List, as revised from time to time, for transportation and storage on a firm basis; provided, however, that in no event shall WNG be obligated to receive on any day in excess of the Maximum Daily Quantity (MDQ) for each Primary Receipt Point or of the Maximum Daily Transportation Quantity (MDTQ) for all Primary Receipt Points within any area, all as set forth on Exhibit A. 1.2 WNG agrees to deliver and Shipper agrees to accept (or cause to be accepted) at the Primary Delivery Point(s) taken from the Master Delivery Point List and designated on Exhibit B a quantity of natural gas thermally equivalent to the quantity received by WNG for transportation and withdrawn from storage as provided in Article 1.3 hereunder less appropriate reductions for fuel and loss as provided in WNG's Rate Schedule TSS; provided, however, that WNG shall not be obligated to deliver on any day quantities in excess of the MDQ for each Primary Delivery Point or in excess of the MDTQ within any area for all Primary Delivery Points, all as set forth on Exhibit B. 1.3 Subject to the provisions of this Agreement and of WNG's Rate Schedule TSS, WNG agrees to (a) inject and store such quantities of natural gas up to the Maximum Storage Quantity (MSQ) and the Maximum Daily Injection Quantity (MDIQ) as Shipper may cause to be tendered to WNG for injection into storage, less appropriate reductions for fuel and loss, and (b) withdraw such quantities of natural gas up to Shipper's gas in storage and the Maximum Daily Withdrawal Quantity (MDWQ) reflected on Exhibit C, all on a firm basis. ARTICLE II DELIVERY POINT(S) AND DELIVERY PRESSURE 2.1 Natural gas to be delivered hereunder by WNG to or on behalf of Shipper shall be delivered at the outlet side of the measuring station(s) at or near the Delivery Point(s) designated on Exhibit B at WNG's line pressure existing at such Delivery Point(s). ARTICLE III RATE, RATE SCHEDULE AND GENERAL TERMS AND CONDITIONS 3.1 Shipper shall pay WNG each month for all service rendered hereunder the then-effective, applicable rates and charges under WNG's Rate Schedule TSS, as such rates and charges and Rate Schedule TSS may hereafter be modified, supplemented, superseded or replaced generally or as to the service hereunder. Shipper agrees that WNG shall have the unilateral right from time to time to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service hereunder, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions incorporated by reference in such rate schedule(s); provided, however, Shipper shall have the right to protest any such changes. 3.2 This Agreement in all respects is subject to the provisions of Rate Schedule TSS, or superseding rate schedule(s), and applicable provisions of the General Terms and Conditions included by reference in said Rate Schedule TSS, all of which are by reference made a part hereof. ARTICLE IV TERM 4.1 This Agreement shall become effective on the date of execution and shall continue in full force and effect for an original term until 7:00 a.m., local time on October 1, 2013; provided, however, this Agreement shall be considered as renewed and extended beyond such original term for successive five (5) year terms thereafter, unless canceled, effective at the end of the primary term or at the end of any subsequent five (5) year term, by six (6) months advance written notice by either party. 4.2 This Agreement may be suspended or terminated by WNG in the event Shipper fails to pay all of the amount of any bill rendered by WNG hereunder when that amount is due; provided, however, WNG shall give Shipper and the FERC thirty (30) days notice prior to any suspension or termination of service. Service may continue hereunder if within the thirty-day notice period satisfactory assurance of payment is made by Shipper in accord with Article 18 of the General Terms and Conditions. Suspension or termination of this Agreement shall not excuse 2 Shipper's obligation to pay all demand and other charges for the original term of the Agreement. ARTICLE V NOTICES 5.1 Unless otherwise agreed to in writing by the parties, any notice, request, demand, statement or bill respecting this Agreement shall be in writing and shall be deemed given when placed in the regular mail or certified mail, postage prepaid and addressed to the other party, or sent by overnight delivery service, or by facsimile, at the following addresses or facsimile numbers, respectively: To Shipper: Billing: GREELEY GAS COMPANY 1301 Pennsylvania St., #800 Denver, CO 80203 Attn: Director, Gas Supply Phone: 303/861-8080 Fax: 303/837-9549 Notices: GREELEY GAS COMPANY 1301 Pennsylvania St., #800 Denver, CO 80203 Attn: Director, Gas Supply Phone: 303/861-8080 Fax: 303/837-9549 To WNG: Payments: Williams Natural Gas Company P.O. Box 3288 Tulsa, OK 74101 Attention: Revenue Accounting All Notices: Williams Natural Gas Company P.O. Box 3288 Tulsa, OK 74101 Attention: Manager - Transportation Services Fax: 918/588-3108 ARTICLE VI 3 MISCELLANEOUS 6.1 The interpretation, performance and enforcement of this Agreement shall be construed in accordance with the laws of the State of Oklahoma. 6.2 As of the date of execution of Exhibits A, B, and C attached to this Agreement, such executed exhibits shall be incorporated by reference as part of this Agreement. The parties may amend Exhibits A, B, and C by mutual agreement, which amendment shall be reflected in a revised Exhibit A, B, and C and shall be incorporated by reference as part of this Agreement. 6.3 Any Service Agreements under Rate Schedule TSS shall not cover service under both TSS-P and TSS-M. 6.4 OTHER THAN AS MAY BE SET FORTH HEREIN, WNG MAKES NO OTHER WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WITHOUT LIMITATION WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR MERCHANTABILITY. 6.5 Other Miscellaneous IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written. ATTEST: WILLIAMS NATURAL GAS COMPANY By: By: /s/ James O. Henderson ------------------------- -------------------------- Assistant Secretary Title: Director, Transportation Services --------------------------------- ATTEST/WITNESS: GREELEY GAS COMPANY By: /s/ Richard W. Remley By: /s/ Gary L. Schlessman ---------------------------- -------------------------- Title: Assistant Secretary Title: President ------------------------- ----------------------- As Shipper 4 EXHIBIT A - MARKET TO TRANS-STORAGE REQUEST TR-0005 DATED OCTOBER 1, 1993 BETWEEN WILLIAMS NATURAL GAS COMPANY AND GREELEY GAS COMPANY ______________________________________________________________________________ MAX RECEIPT LOCATION(S) POINT DPY RATE TYP SEC-TWN- COUNTY ST DAILY NUMBER AREA RNG QTY ______________________________________________________________________________ 1 WNG-PRD/MKT POOL 999000 909 M MPT 5,619 2 WNG-MKT STORAGE 999021 909 M STW 8,254 POOL WITHDRAWAL 3 WNG-MASTER RECEIPT POINT LIST IN EFFECT ______________________________________________________________________________ TOTAL MAXIMUM DAILY QUANTITY: 13,873 DTH EFFECTIVE DATE OF THIS EXHIBIT A: October 1, 1993 GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY BY: /s/ W. H. Warburton BY: /s/ James O. Henderson ------------------------ ------------------------ EXHIBIT A - PRODUCTION TO TRANS-STORAGE REQUEST TR-0005 SERVICE AGREEMENT DATED OCTOBER 1, 1993 BETWEEN WILLIAMS NATURAL GAS COMPANY AND GREELEY GAS COMPANY _______________________________________________________________________________ MAX RECEIPT LOCATION(S) POINT DPY RATE TYP SEC-TWN-RNG COUNTY ST DAILY NUMBER AREA QTY _______________________________________________________________________________ 1 CIG-CIG-RINER 13031 492 P TER 34-21N-090W SWEETWATER WY 1,496 2 WNG-G/T OK 999400 377 P INT 4,279 HUGOTON INTERFACE 3 WNG-MASTER RECEIPT POINT LIST IN EFFECT _______________________________________________________________________________ TOTAL MAXIMUM DAILY QUANTITY: 5,775 DTH EFFECTIVE DATE OF THIS EXHIBIT A: October 1, 1993 GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY BY: /s/ W. H. Warburton BY: /s/ James O. Henderson ------------------------ ---------------------- EXHIBIT B - MARKET TO TRANS-STORAGE REQUEST TR-0005 SERVICE AGREEMENT DATED OCTOBER 1, 1993 BETWEEN WILLIAMS NATURAL GAS COMPANY AND GREELEY GAS COMPANY ________________________________________________________________________________ MAXIMUM DELIVERY LOCATION(S) POINT DPY RATE TYP ST DAILY NUMBER AREA QTY ________________________________________________________________________________ 1 GREELEY - JOHNSON CO. 104 190 M DCL KS 500 2 GREELEY - BOURBON COUNTY 48015 095 M DCL KS 2,743 3 GREELEY - BONNER SPRGS ETC 77308 113 M DCL KS 8,070 4 GREELEY - EUREKA, TORONTO AND NEAL 77512 300 M DCL KS 2,560 5 WNG-MASTER DELIVERY POINT LIST IN EFFECT ________________________________________________________________________________ TOTAL MAXIMUM DAILY QUANTITY: 13,873 DTH EFFECTIVE DATE OF THIS EXHIBIT B: October 1, 1993 GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY BY: /s/ W. H. Warburton BY: /s/ James O. Henderson ------------------------- -------------------------- EXHIBIT B - PRODUCTION TO TRANS-STORAGE REQUEST TR-0005 SERVICE AGREEMENT DATED OCTOBER 1, 1993 BETWEEN WILLIAMS NATURAL GAS COMPANY AND GREELEY GAS COMPANY _____________________________________________________________________________ MAXIMUM DELIVERY LOCATION(S) POINT DPY RATE TYP ST DAILY NUMBER AREA QTY _____________________________________________________________________________ 1 PRD/MKT POOL DELIVERY 999000 909 P PPT KS 5,775 2 WKG- MASTER DELIVERY POINT LIST IN EFFECT ______________________________________________________________________________ TOTAL MAXIMUM DAILY QUANTITY: 5,775 DTH EFFECTIVE DATE OF THIS EXHIBIT B: October 1, 1993 GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY BY: /s/ W. H. Warburton BY: /s/ James O. Henderson --------------------------- ------------------------- 9 EXHIBIT C - STORAGE TO TRANS-STORAGE REQUEST TR-0005 SERVICE AGREEMENT DATED OCTOBER 1, 1993 BETWEEN WILLIAMS NATURAL GAS COMPANY AND GREELEY GAS COMPANY ________________________________________________________________________ MAXIMUM DAILY WITHDRAWAL QUANTITY: 8,254 DTH MAXIMUM STORAGE QUANTITY:** 272,382 DTH **MAXIMUM DAILY WITHDRAWAL QUANTITY TIMES 33 EFFECTIVE DATE OF THIS EXHIBIT C: October 1, 1993 GREELEY GAS COMPANY WILLIAMS NATURAL GAS COMPANY BY: /s/ W. H. Warburton BY: /s/ James O. Henderson -------------------------- -------------------------- 11 EX-10 6 EXHIBIT 10.6(c) Contract No. 31013 NO-NOTICE TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE NNT-1 between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY DATED: October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. TABLE OF CONTENTS Article Page No. I QUANTITIES OF GAS TO BE TRANSPORTED AND STORED . . . 1 II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY . . . . 2 III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 3 IV TERM . . . . . . . . . . . . . . . . . . . . . . . . 4 V CANCELLATION OF PRIOR CONTRACTS . . . . . . . . . . 4 VI OTHER OPERATING PROVISIONS . . . . . . . . . . . . . 4 VII MODIFICATIONS . . . . . . . . . . . . . . . . . . . 6 VIII NOTICES . . . . . . . . . . . . . . . . . . . . . . 6 EXHIBIT "A" EXHIBIT "B" - 2 - NO-NOTICE TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE NNT-1 THIS AGREEMENT is made and entered into as of this 1st Day of October, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later, by and between COLORADO INTERSTATE GAS COMPANY, hereinafter called "Transporter," and GREELEY GAS COMPANY, hereinafter called "Shipper". In consideration of the mutual promises hereinafter contained, Shipper and Transporter agree as follows: ARTICLE I QUANTITIES OF GAS TO BE TRANSPORTED AND STORED 1.1 Maximum Delivery Quantity ("MDQ"). Shipper's MDQ is 16,005 Dth per Day during the Winter Season and 4,896 Dth per Day during the Summer Season. 1.2 Transportation Service. Transportation Service between and at Primary Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm basis. Service at and involving Secondary Point(s) of Receipt and Delivery shall be scheduled subject to capacity availability following all firm Transpor- tation Service between Primary Point(s) of Receipt and Delivery and ahead of any interruptible Transportation Service at such point(s). 1.3 Maximum Daily Transportation Quantity ("MDTQ"). Shipper's MDTQ is 4,896 Dth per Day. 1.4 Maximum Available Capacity ("MAC"). Shipper's MAC is 422,142 Dth. 1.5 Maximum Daily Injection Quantity ("MDIQ"). Shipper's MDIQ is 1/150th of Shipper's MAC or 2,814 Dth per Day. 1.6 Maximum Daily Withdrawal Quantity ("MDWQ"). Shipper's MDWQ is 1/38th of Shipper's MAC or 11,109 Dth per Day. MDWQ is subject to adjustment as actual gas in place declines over the Withdrawal Period as explained in Article 1 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 1.7 Authorized Overrun Quantities. On any Day upon request by Shipper and with Transporter's consent, Shipper may Tender and Transporter may accept for service hereunder quantities of gas in excess of Shipper's MDQ or Shipper's Point of Receipt or Delivery Quantities at each Point of Receipt or Delivery. 1.8 Summer Season Overrun. During the Summer Season, Shipper may take Deliveries in excess of the quantities nominated by Shipper at the Point(s) of Receipt up to its full Winter Season MDQ, limited by Shipper's ADWQ and Shipper shall pay the NNT-1 Commodity rate on the Schedule of Rates Sheets for the Summer Season Overrun quantities delivered. Such quantities shall be subject to the same terms and conditions as if they were Winter Season quantities. ARTICLE II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY 2.1 Receipt. Transporter agrees to accept Receipt Quantities at the Point(s) of Receipt identified in the attached Exhibit "A" which is incorporated herein by reference. - 2 - 2.2 Delivery. Transporter agrees to transport and Deliver Delivery Quantities to Shipper (or for Shipper's account) at the Point(s) of Delivery identified in the attached Exhibit "A." 2.3 Secondary Points of Receipt and Delivery. Receipt and Delivery of quantities by Transporter at Secondary Point(s) of Receipt and/or Secondary Point(s) of Delivery will be scheduled and allocated capacity pursuant to Article 5 of the General Terms and Conditions of Transporter's FERC Gas Tariff. Shipper shall be entitled to receive service at Secondary Point(s) of Receipt and Delivery by nominating for service at such locations. When nominating for service at Secondary Point(s), Shipper shall designate the capacity being shifted from Primary Points for service at the Secondary Points. ARTICLE III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 3.1 Rate Schedule. Each Month, Shipper shall pay Transporter for No-Notice Transportation Service rendered hereunder at the rates and surcharges set forth on Exhibit "B," which is incorporated herein by reference, for the Term of Rate provided therein. Once the Term of Rate has expired, payment shall be at the maximum rates and surcharges set forth on the Schedule of Rates Sheets unless otherwise agreed. 3.2 Incorporation by Reference. This Agreement in all respects shall be subject to Rate Schedule NNT-1 and to the General Terms and Conditions of Transporter's FERC Gas Tariff (Tariff) as filed with, and made effective by, the FERC (as they - 3 - may be amended pursuant to Article VII of this Agreement), all of which are by reference made a part hereof. 3.3 Changes in Rates and Terms. Transporter shall have the right to propose to the FERC changes in its rates and terms of service, and this Agreement shall be deemed to include any changes which are made effective pursuant to FERC Order or regulation or provisions of law, without prejudice to shipper's right to protest the same. ARTICLE IV TERM 4.1 Effective Date. This Agreement shall become effective on October 1, 1993, or the date in which Transporter commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. 4.2 Termination Date. This Agreement shall continue in full force and effect for a term extending through September 30, 1996. 4.3 Termination Obligations. Termination of this Agreement shall not relieve Transporter and Shipper of the obligation to correct any imbalances, or relieve Shipper of the obligation to pay money due to Transporter. All warranties and indemnities shall survive the termination of this Agreement. ARTICLE V CANCELLATION OF PRIOR CONTRACTS 5.1 Cancellation of Prior Contracts. When this Agreement becomes effective, it shall supersede and cancel the following contract(s) between the Parties: The Gas Sales Agreement between - 4 - Transporter and Shipper dated February 1, 1993, and any amendments thereto and referred to as Transporter's Agreement No. R-4-AP. ARTICLE VI OTHER OPERATING PROVISIONS 6.1 Shippers under this Rate Schedule NNT-1 shall be subject to the Joint Monthly Operating Plan, Operational Flow Orders, and Configuration Flow Orders as provided in Article 7 of the General Terms and Conditions of the Tariff. 6.2 First of the Month Nominations. At least four Business Days, or, for Shippers using Transporter's electronic bulletin board, two Business Days, before the first Day of each Month, Shipper shall provide Transporter with a schedule (in writing or by Electronic Transmission) showing the daily quantities to be Tendered to Transporter during the first four Days of the Month at each Point of Receipt including the producing area (including county and state) of the gas to be Tendered. Nominations shall be addressed as set forth in Article VIII of this Agreement. 6.3 Daily Nominations. Unless otherwise agreed, Shipper shall submit daily written nominations to Transporter 27 hours prior to the beginning of the Day of Delivery (e.g., nominations shall be made by 10:00 a.m., Central Standard Time, on Monday for gas to be Tendered beginning at 1:00 p.m., Central Standard Time, on Tuesday). For each Agreement, Shipper shall nominate in writing or by Electronic Transmission the quantity which Shipper intends to Tender at the Point(s) of Receipt and to receive at the Point(s) of Delivery, including an allocation of Point of - 5 - Receipt Quantities to each Point of Delivery in the event of multiple Delivery Points. Transporter shall attempt to verify all nominations and confirm service to Shipper no later than four hours prior to the Day for which the nominations are to be effective. Transporter is not responsible for assuring that the nominated quantities are actually Tendered to Transporter at the Point(s) of Receipt. All service performed under this Agreement shall be performed pursuant to 18 CFR 284.221 authority, unless Shipper elects service to be performed pursuant to Transporter's 18 CFR 284.101 (Section 311) authority. In that event, Transporter shall only accept, and Shipper shall only make, nominations for service to be performed pursuant to 18 CFR 284.101 (Section 311) in accordance with the regulations governing the provisions of such service, and after Transporter has received an "on behalf of" letter acceptable to Transporter. 6.4 Estimates. For planning purposes, Transporter may, from time to time, request estimates of Shipper's annual quantity, average daily quantity, or peak Day quantity. In the event that such a request is made, Shipper shall reply in writing within 45 Days of the request. 6.5 Planning Information. Transporter may request other planning information as needed from time to time and Shipper shall comply with all reasonable requests. - 6 - ARTICLE VII MODIFICATIONS 7.1 Modifications. Certain provisions of the General Terms and Conditions and/or Rate Schedule NNT-1 are modified for the purpose of this Agreement, as specified below: None. ARTICLE VIII NOTICES 8.1 Notices, Statements, and Bills. Any notice, statement, or bill provided for in this Agreement shall be in writing and shall be considered as having been given if hand carried, telecopied or mailed by United States Mail, postage prepaid, to the following addresses, respectively: To Shipper: Invoices for Transportation: Greeley Gas Company 1301 Pennsylvania Street, Suite 800 Denver, Colorado 80203-5015 Attention: Bill Warburton All Notices: Greeley Gas Company 1301 Pennsylvania Street, Suite 800 Denver, Colorado 80203-5015 Attention: Bill Warburton To Transporter: Payments for Transportation: Colorado Interstate Gas Company Department 208 Denver, Colorado 80291 All Notices: Colorado Interstate Gas Company P. O. Box 1087 Colorado Springs Colorado 80944 Telecopy No. (719) 520-4810 Attention: Transportation & Exchange Department - 7 - All Nominations: Colorado Interstate Gas Company Colorado Springs, Colorado 80944 Telecopy No. (719) 520-4411 Attention: Volume Management, Transmission 8.2 Agents. Shipper must provide written notice to Transporter of the name, and any other pertinent information, of another person ("Agent") that has agency authority to act for Shipper in connection with (1) the Joint Monthly Operating Plan as discussed in Article 7 of the General Terms and Conditions of the Tariff, (2) operation of pipelines, facilities, and wells in connection with this Agreement, (3) Operational Flow Orders or Configuration Flow Orders as discussed in Article 7 of the General Terms and Conditions of the Tariff, and/or (4) other matters covered by this Agreement. If the Agent has the authority in (2) and (3), above, operating notices shall be served upon the Agent alone. The Shipper remains bound by its obligations under the Tariff, and commitments made by the Agent on behalf of the Shipper are binding on the Shipper as if made by the Shipper. The Shipper must provide prompt written notice of the termination of the agency. - 8 - IN WITNESS WHEREOF, the Parties hereto have executed this Agreement. COLORADO INTERSTATE GAS COMPANY (Transporter) By /s/ S. W. ZUCKWEILER ----------------------------- S. W. Zuckweiler Vice President GREELEY GAS COMPANY (Shipper) Attest: By /s/ Richard W. Remley ----------------------------- Richard W. Remley ----------------------------- By: /s/ W. J. Warburton (Print or type name) ------------------- Title: Director Gas Supply Senior Vice President ------------------- ----------------------------- (Print or type title) - 9 - Page 1 of 3 EXHIBIT "A" to NO-NOTICE TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) DATED: October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. 1. Shipper's Maximum Delivery Quantity: MDQ: 4,896 Dth per Day during the Summer Season and is 16,005 Dth per Day during the Winter Season (Note 4). 2. Shipper's Maximum Daily Transportation Quantity: MDTQ: 4,896 Dth per Day. 3. Shipper's Maximum Available Capacity: MAC: 422,142 Dth. 4. Shipper's Maximum Daily Injection Quantity: MDIQ: 2,814 Dth. 5. Shipper's Maximum Daily Withdrawal Quantity: MDWQ: 11,109 Dth. (1/38th of MAC) Point of Maximum Receipt Quantity Receipt Primary Point(s) of Receipt (Dth per Day) Pressure (Note 1) (Note 2) p.s.i.g. ---------------------------- ---------------- -------- Northern System Uinta 593 720 Echo Springs Master Meter 300 850 Lost Cabin 1,200 1,100 Central System Lakin Master Meter 839 900 As may be mutually agreed by the Parties 30 Page 2 of 3 EXHIBIT "A" Point of Maximum Delivery Quantity Delivery Primary Point(s) of Delivery (Dth per Day) Pressure (Note 1) (Note 3) p.s.i.g. ---------------------------- ----------------- -------- Southern System Bivins Master Meter 674 479 Mocane-Warren Plant 460 800 Greenwood Master Meter 800 761 Canon City 11,855 (Note 5) (Note 6) Colorado State Penitentiary 591 (Note 5) 100 Florence City Gate 2,265 (Note 5) 60 Penrose City Gate 394 (Note 5) 60 Penrose South 74 (Note 5) Line Pressure Portland City Gate 3,073 (Note 5) 100 Pritchett City Gate 295 (Note 5) 150 Fremont County Industrial Park 148 (Note 5) Line Pressure The Piggery 15 (Note 5) Line Pressure Engineer's Station 476+78 15 (Note 5) Line Pressure Penrose PBS-2 295 (Note 5) Line Pressure Eads City Gate 884 (Note 5) 60 Brandon Station 832 (Note 5) 350 L. J. Stafford 156 (Note 5) Line Pressure Springfield 3,120 (Note 5) Line Pressure NOTES: (1) Information regarding Points of Receipt and Points of Delivery, including legal descriptions, measuring parties, and interconnecting parties, shall be posted on Transporter's electronic bulletin board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. Page 3 of 3 EXHIBIT "A" (2) Point of Receipt Quantities may be increased by an amount equal to Transporter's effective fuel reimbursement. (3) The sum of the Primary Point of Delivery Quantities shall be equal to or less than Shipper's MDQ. (4) In Docket No. RP93-99, CIG's conversion to a thermal tariff is subject to review as to methodology, factors, or any other issue involved in the transition from a volumetric basis to a thermal basis. Should such review result in a change in the basis upon which the thermal quantities used in this service agreement were determined, such thermal quantities shall be adjusted as required. (5) Transporter's obligation to make deliveries at this Primary Point of Delivery shall be limited to the amount shown or the meter capacity, whichever is less. Further, Transporter's obligation to make deliveries at these Primary Points of Delivery under this Agreement and under all Firm Service Agreements shall be limited in the aggregate to the amount shown or to the meter capacity whichever is less. (6) Line pressure but not less than 100 p.s.i.g. Page 1 of 2 EXHIBIT "B" to NO-NOTICE TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) DATED: October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later.
R1 Res- Commod- Fuel ervation ity Reimburse- Sur- Point of Receipt Point of Delivery Rate Rate Term of Rate ment charges - ---------------- ----------------- -------- ------- ------------ ---------- ------- All Primary and All Primary and (Note 1) (Note 1) Through (Note 2) (Note 3) Secondary Points Secondary Points 9/30/96
NOTES: (1) The rates for service hereunder shall be Transporter's maximum rates for service under Rate Schedule NNT-1 or other superseding Rate Schedule, as such rates may be changed from time to time. (2) Fuel usage and lost and unaccounted-for deductions shall be as stated on Transporter's Schedule of Surcharges and Fees in the Tariff, as they may be changed from time to time, unless otherwise agreed between the Parties. Page 2 of 2 EXHIBIT "B" NOTES: (3) Applicable Surcharges: All applicable surcharges, unless otherwise specified, shall be the maximum surcharge rate as stated in the Schedule of Surcharges and Fees in the Tariff, as such surcharges may be changed from time to time. Gas Quality Control: The Gas Quality Control Surcharge shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in the Tariff. GRI: The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms and Conditions, both as set forth in the Tariff. Gas Supply Transition: The Gas Supply Transition Surcharge shall be assessed pursuant to Article 21 of the General Terms and Conditions as set forth in the Tariff. ACA: Transporter's applicable ACA Surcharge shall be added to all discounted rates except that in no event shall the discounted rate plus the ACA Surcharge exceed Transporter's maximum rate as stated in the Schedule of Rates in the Tariff. Contract No. 31013000A AMENDMENT DATED: January 1, 1994 to NO-NOTICE TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE NNT-1 DATED: October 1, 1993 between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY AMENDMENT TO NO-NOTICE TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE NNT-1 THIS AGREEMENT, made and entered into this 1st Day of January, 1994, by and between COLORADO INTERSTATE GAS COMPANY, hereinafter referred to as "Transporter," and GREELEY GAS COMPANY, hereinafter referred to as "Shipper." WHEREAS, Transporter and Shipper entered into a Transportation Service Agreement ("Agreement") dated October 1, 1993, providing for the transportation by Transporter for Shipper pursuant to 18 CFR 284.221 authority and/or 18 CFR 284.101 (see Section 6.3 as applicable); and WHEREAS, Transporter and Shipper desire to amend the Agreement effective January 1, 1994, to revise the Primary Points of Delivery as stated in Exhibit "A" to the Agreement; NOW, THEREFORE, in consideration of the premises and the mutual covenants hereinafter contained, Transporter and Shipper agree to amend the Agreement as follows: Effective January 1, 1994, Exhibit "A" shall be deleted in its entirety and the attached Exhibit "A" shall be substituted therefor. This Amendment shall be effective as of January 1, 1994, and except as herein amended, the Agreement shall in all respects remain in full force and effect. IN WITNESS WHEREOF, the Parties have executed this Amendment. COLORADO INTERSTATE GAS COMPANY (Transporter) By /s/ Donald J. Zinko ----------------------------- Donald J. Zinko Senior Vice President GREELEY GAS COMPANY (Shipper) ATTEST: By /s/ Gary L. Schlessman ----------------------------- By Gary L. Schlessman -------------------------- ----------------------------- Title: (Print or type name) President ----------------------------- (Print or type title) - 2 - Page 1 of 3 EXHIBIT "A" to NO-NOTICE TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) Agreement Dated: October 1, 1993 Amendment Dated: January 1, 1994 1. Shipper's Maximum Delivery Quantity: MDQ: 4,896 Dth per Day during the Summer Season and is 16,005 Dth per Day during the Winter Season (Note 4). 2. Shipper's Maximum Daily Transportation Quantity: MDTQ: 4,896 Dth per Day. 3. Shipper's Maximum Available Capacity: MAC: 422,142 Dth. 4. Shipper's Maximum Daily Injection Quantity: MDIQ: 2,814 Dth. 5. Shipper's Maximum Daily Withdrawal Quantity: MDWQ: 11,109 Dth. (1/38th of MAC) Point of Maximum Receipt Quantity Receipt Primary Point(s) of Receipt (Dth per Day) Pressure (Note 1) (Note 2) p.s.i.g. --------------------------- ---------------- -------- Northern System Uinta 593 720 Echo Springs Master Meter 300 850 Lost Cabin 1,200 1,100 Central System Lakin Master Meter 839 900 As may be mutually agreed by the Parties 30 Page 2 of 3 EXHIBIT "A" Point of Maximum Delivery Quantity Delivery Primary Point(s) of Delivery (Dth per Day) Pressure (Note 1) (Note 3) p.s.i.g. Southern System Bivins Master Meter 674 479 Mocane-Warren Plant 460 800 Greenwood Master Meter 800 761 Canon City Group (Note 5): Canon City 11,855 (Note 6) (Note 7) Colorado State Penitentiary 591 (Note 6) 100 Florence City Gate 2,265 (Note 6) 60 Penrose City Gate 394 (Note 6) 60 Penrose South 74 (Note 6) Line Pressure Portland City Gate 3,073 (Note 6) 100 Pritchett City Gate 295 (Note 6) 150 Fremont County Industrial Park 148 (Note 6) Line Pressure The Piggery 15 (Note 6) Line Pressure Engineer's Station 476+78 15 (Note 6) Line Pressure Penrose PBS-2 295 (Note 6) Line Pressure Eads Group (Note 8): Eads City Gate 884 (Note 6) 60 Brandon Station 832 (Note 6) 350 L. J. Stafford 156 (Note 6) Line Pressure Springfield 1,081 (Note 6) Line Pressure McClave Delivery 1,000 (Note 6) 500 NOTES: (1) Information regarding Points of Receipt and Points of Delivery, including legal descriptions, measuring parties, and interconnecting parties, shall be posted on Transporter's electronic bulletin board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. (2) Point of Receipt Quantities may be increased by an amount equal to Transporter's effective fuel reimbursement. (3) The sum of the Primary Point of Delivery Quantities shall be equal to or less than Shipper's MDQ. Page 3 of 3 EXHIBIT "A" (4) In Docket No. RP93-99, CIG's conversion to a thermal tariff is subject to review as to methodology, factors, or any other issue involved in the transition from a volumetric basis to a thermal basis. Should such review result in a change in the basis upon which the thermal quantities used in this service agreement were determined, such thermal quantities shall be adjusted as required. (5) Transporter's obligation to make deliveries at all Primary Points of Delivery included in the Canon City Group shall be limited in the aggregate to 12,644 Dth per Day under this Agreement. (6) Transporter's obligation to make deliveries at this Primary Point of Delivery shall be limited to the amount shown or the meter capacity, whichever is less. Further, Transporter's obligation to make deliveries at these Primary Points of Delivery under this Agreement and under all Firm Service Agreements shall be limited in the aggregate to the amount shown or to the meter capacity whichever is less. (7) Line pressure but not less than 100 p.s.i.g. (8) Transporter's obligation to make deliveries at all Primary Points of Delivery included in the Eads Group shall be limited in the aggregate to 1,280 Dth per Day under this Agreement. EX-10 7 EXHIBIT 10.6(d) Contract No. 35009 FIRM TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-2 between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY DATED: October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. TABLE OF CONTENTS Article Page No. I QUANTITIES OF GAS TO BE TRANSPORTED . . . . . . . . . 1 II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY . . . . 2 III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 2 IV TERM . . . . . . . . . . . . . . . . . . . . . . . . 3 V CANCELLATION OF PRIOR CONTRACTS . . . . . . . . . . . 3 VI OTHER OPERATING PROVISIONS . . . . . . . . . . . . . 4 VII MODIFICATIONS . . . . . . . . . . . . . . . . . . . . 5 VIII NOTICES . . . . . . . . . . . . . . . . . . . . . . . 5 EXHIBIT "A" EXHIBIT "B" 2 FIRM TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-2 THIS AGREEMENT is made and entered into as of this 1st Day of October, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later, by and between COLORADO INTERSTATE GAS COMPANY, hereinafter called "Transporter," and GREELEY GAS COMPANY, hereinafter called "Shipper." In consideration of the mutual promises hereinafter contained, Shipper and Transporter agree as follows: ARTICLE I QUANTITIES OF GAS TO BE TRANSPORTED 1.1 Maximum Delivery Quantity. Shipper's Maximum Delivery Quantity is 1,408 Dth per Day. 1.2 Transportation Service. Transportation Service at and between Primary Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm basis. Service involving and at Secondary Point(s) of Receipt and Delivery shall be scheduled, subject to capacity availability, following all firm transportation services between Primary Point(s) of Receipt and Delivery and ahead of any interruptible Transportation Service at such point(s). 1.3 Authorized Overrun Quantity. On any Day upon request of Shipper and with Transporter's consent, Shipper may Tender and Transporter may accept for transportation quantities of gas in excess of Shipper's Maximum Delivery Quantity or Shipper's Point of Receipt or Delivery Quantities at each Point of Receipt or Delivery. ARTICLE II POINT(S) OF RECEIPT AND POINT(S) OF DELIVERY 2.1 Receipt. Transporter agrees to accept Receipt Quantities at the Primary Point(s) of Receipt identified in Exhibit "A," which is incorporated herein by reference. 2.2 Delivery. Transporter agrees to transport and Deliver Delivery Quantities to Shipper (or for Shipper's account) at the Primary Point(s) of Delivery identified in Exhibit "A." 2.3 Secondary Point(s) of Receipt and Delivery. Receipt and Delivery of quantities at Secondary Point(s) of Receipt and/or Secondary Point(s) of Delivery will be scheduled and allocated capacity pursuant to Article 5 of the General Terms and Conditions of this Tariff. Shipper shall be entitled to receive service at Secondary Point(s) of Receipt and Delivery by nominating for service at such locations. When nominating for service at Secondary Point(s), Shipper shall designate the capacity being shifted from Primary Point(s) for service at the Secondary Point(s). ARTICLE III APPLICABLE RATE SCHEDULE, INCORPORATION BY REFERENCE 3.1 Rate Schedule. Each Month, Shipper shall pay Transporter for Transportation Service provided hereunder at the rates and surcharges set forth on Exhibit "B," which is incorporated herein by reference, for the Term of Rate provided therein. Once the Term of Rate has expired, payment shall be at the maximum rates and surcharges set forth on the Schedule of Rates Sheets unless otherwise agreed. 2 3.2 Incorporation by Reference. This Agreement in all respects shall be subject to Rate Schedule TF-2 and the General Terms and Conditions of Transporter's FERC Gas Tariff (Tariff) filed with, and made effective by, the FERC (as they may be amended pursuant to Article VII of this Agreement), all of which are by reference made a part hereof. 3.3 Changes in Rates and Terms. Transporter shall have the right to propose to the FERC changes in its rates and terms of service, and this Agreement shall be deemed to include any changes which are made effective pursuant to FERC Order or regulation or provisions of law, without prejudice to Shipper's right to protest the same. ARTICLE IV TERM 4.1 Effective Date. This Agreement shall become effective on October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. 4.2 Termination Date. This Agreement shall continue in full force and effect for a term extending through September 30, 1996. 4.3 Termination Obligations. Termination of this Agreement shall not relieve Transporter and Shipper of the obligation to correct any quantity imbalances, or relieve Shipper of the obligation to pay money due to Transporter. All warranties and indemnities shall survive the termination of this Agreement. 3 ARTICLE V CANCELLATION OF PRIOR CONTRACTS 5.1 Cancellation of Prior Contracts. When this Agreement becomes effective, it shall only supersede and cancel the following contract(s) between the Parties: None. ARTICLE VI OTHER OPERATING PROVISIONS 6.1 Shippers under this Rate Schedule TF-2 shall be subject to the Joint Monthly Operating Plan, Operational Flow Orders, and Configuration Flow Orders as provided in Article 7 of the General Terms and Conditions of the Tariff. 6.2 First of the Month Nominations. At least four Business Days, or, for Shippers using Transporter's electronic bulletin board, two Business Days, before the first Day of each Month, Shipper shall provide Transporter with a schedule (in writing or by Electronic Transmission) showing the daily quantities to be Tendered to Transporter during the first four Days of the Month at each Point of Receipt including the producing area (including county and state) of the gas to be Tendered and an allocation of such quantity at each Point of Delivery. Nominations shall be addressed as set forth in Article VIII of this Agreement. 6.3 Daily Nominations. Unless otherwise agreed, Shipper shall submit daily written nominations to Transporter 27 hours prior to the beginning of the Day of Delivery (e.g., nominations shall be made by 10:00 a.m., Central Standard Time, on Monday for gas to be Tendered beginning at 1:00 p.m., Central Standard Time, on Tuesday). For each Agreement, Shipper shall nominate in 4 writing or by Electronic Transmission the quantity which Shipper intends to Tender at the Point(s) of Receipt and to receive at the Point(s) of Delivery, including an allocation of Point of Receipt Quantities to each Point of Delivery in the event of multiple Delivery Points. Transporter shall attempt to verify all nominations and confirm service to Shipper no later than four hours prior to the Day for which the nominations are to be effective. Transporter is not responsible for assuring that the nominated quantities are actually Tendered to Transporter at the Point(s) of Receipt. All service performed under this Agreement shall be performed pursuant to 18 CFR 284.221 authority, unless Shipper elects service to be performed pursuant to Transporter's 18 CFR 284.101 (Section 311) authority. In that event, Transporter shall only accept, and Shipper shall only make, nominations for service to be performed pursuant to 18 CFR 284.101 (Section 311) in accordance with the regulations governing the provisions of such service, and after Transporter has received an "on behalf of" letter acceptable to Transporter. 6.4 Estimates. For planning purposes, Transporter may, from time to time, request estimates of Shipper's annual quantity, average daily quantity, or peak Day quantity. In the event that such a request is made, Shipper shall reply in writing within 45 Days of the request. 6.5 Planning Information. Transporter may request other planning information as needed from time to time and Shipper shall comply with all reasonable requests. 5 ARTICLE VII MODIFICATIONS 7.1 Modifications. Certain provisions of the General Terms and Conditions and/or Rate Schedule TF-2 are to be modified for the purpose of this Agreement, as specified below: None. ARTICLE VIII NOTICES 8.1 Notices, Statements, and Bills. Any notice, statement, or bill provided for in this Agreement shall be in writing and shall be considered as having been given if hand carried, telecopied, or mailed by United States mail, postage prepaid, to the following addresses, respectively: To Shipper: Invoices for Transportation: Greeley Gas Company 1301 Pennsylvania Street, Suite 800 Denver, Colorado 80203-5015 Attention: Bill Warburton All Notices: Greeley Gas Company 1301 Pennsylvania Street, Suite 800 Denver, Colorado 80203-5015 Attention: Bill Warburton To Transporter: Payments for Transportation: Colorado Interstate Gas Company Department 208 Denver, Colorado 80291 All Notices: Colorado Interstate Gas Company P. O. Box 1087 Colorado Springs, Colorado 80944 Telecopy No. (719) 520-4810 Attention: Transportation & Exchange Department 6 All Nominations: Colorado Interstate Gas Company Colorado Springs, Colorado 80944 Telecopy No. (719) 520-4411 Attention: Volume Management, Transmission 8.2 Agents. Shipper must provide written notice to Transporter of the name, and any other pertinent information, of another person ("Agent") that has agency authority to act for Shipper in connection with (1) the Joint Monthly Operating Plan as discussed in Article 7 of the General Terms and Conditions of the Tariff, (2) operation of pipelines, facilities, and wells in connection with this Agreement, (3) Operational Flow Orders and Configuration Flow Orders as discussed in Article 7 of the General Terms and Conditions of the Tariff, and/or (4) other matters covered by this Agreement. If the Agent has the authority in (2) and (3), above, operating notices shall be served upon the Agent alone. The Shipper remains bound by its obligations under the Tariff, and commitments made by the Agent on behalf of the Shipper are binding on the Shipper as if made by the Shipper. The Shipper must provide prompt written notice of the termination of the agency. IN WITNESS WHEREOF, the Parties have executed this Agreement. COLORADO INTERSTATE GAS COMPANY (Transporter) By /s/ S. W. Zuckweiler ----------------------------- S. W. Zuckweiler Vice President 7 GREELEY GAS COMPANY (Shipper) Attest: By /s/Richard W. Remley ----------------------------- By /s/ W. F. Warburton Richard W. Remley -------------------------- ----------------------------- Title: (Print or type name) Director Gas Supply Senior Vice President ----------------------------- (Print or type title) 8 Page 1 of 3 EXHIBIT "A" to FIRM TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) DATED: October 1, 1993, or the date in which CIG commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. 1. Shipper's Maximum Delivery Quantity: 1,408 Dth per Day (Note 3). Point of Maximum Receipt Quantity Receipt Primary Point(s) of Receipt (Dth per Day) Pressure (Note 1) (Note 2) p.s.i.g. Lakin Master Meter 1,408 900 Point of Maximum Delivery Quantity Delivery Primary Point(s) of Delivery (Dth per Day) Pressure (Note 1) (Note 4) p.s.i.g. Canon City Group (Note 5) Canon City 1,112 (Note 7) (Note 9) Colorado State Penitentiary 591 (Note 7) 100 Florence City Gate 1,112 (Note 7) 60 Penrose City Gate 394 (Note 7) 60 Penrose South 74 (Note 7) Line Pressure Portland City Gate 1,112 (Note 7) 100 Pritchett City Gate 295 (Note 7) 150 Fremont County Industrial Park 148 (Note 7) Line Pressure The Piggery 15 (Note 7) Line Pressure Engineer's Station 476+78 15 (Note 7) Line Pressure Penrose PBS-2 295 (Note 7) Line Pressure Page 2 of 3 EXHIBIT "A" Point of Maximum Delivery Quantity Delivery Primary Point(s) of Delivery (Dth per Day) Pressure (Note 1) (Note 4) p.s.i.g. Eads Group (Note 6) Eads City Gate 113 (Note 7) 60 Brandon Station 113 (Note 7) 350 L. J. Stafford 113 (Note 7) Line Pressure Springfield 183 (Note 8) Line Pressure NOTES: (1) Information regarding Points of Receipt and Points of Delivery, including legal descriptions, measuring parties, and interconnecting parties, shall be posted on Transporter's electronic bulletin board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. (2) Point of Receipt Quantities may be increased by an amount equal to Transporter's effective fuel reimbursement. (3) In Docket No. RP93-99, CIG's conversion to a thermal tariff is subject to review as to methodology, factors, or any other issue involved in the transition from a volumetric basis to a thermal basis. Should such review result in a change in the basis upon which the thermal quantities used in this service agreement were determined, such thermal quantities shall be adjusted as required. (4) The sum of the Primary Point of Delivery Quantities shall be equal to or less than Shipper's MDQ. (5) Transporter's obligation to make deliveries at all Primary Points of Delivery included in the Canon City Group shall be limited in the aggregate to 1,112 Dth per Day. (6) Transporter's obligation to make deliveries at all Primary Points of Delivery included in the Eads Group shall be limited in the aggregate to 113 Dth per Day. Page 3 of 3 EXHIBIT "A" NOTES: (7) Transporter's obligation to make deliveries at this Point of Delivery under this Agreement and all other Firm Service Agreements shall be limited in the aggregate to the following volumes, or the meter capacity, whichever is less. Canon City 11,855 Colorado State Penitentiary 591 Florence City Gate 2,265 Penrose City Gate 394 Penrose South 74 Portland City Gate 3,073 Pritchett City Gate 295 Fremont County Industrial Park 148 The Piggery 15 Engineer's Station 476+78 15 Penrose PBS-2 295 Eads City Gate 884 Brandon Station 832 L. J. Stafford 156 (8) Transporter's obligation to make deliveries to this Point of Delivery shall be limited to 183 Dth per Day. Further, Transporter's obligation to make deliveries at this Point under this Agreement and all other Firm Service Agreements shall be limited to 3,120 or the meter capacity, whichever is less. (9) Line pressure but not less than 100 p.s.i.g. Page 1 of 2 EXHIBIT "B" to FIRM TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) DATED: October 1, 1993, or the date in which Transporter commences service pursuant to its Compliance Tariff filed in Docket No. RS92-4-000, et al., whichever is later. Primary Primary R1 Res- Commod- Fuel Hourly Point of Point of ervation ity Reimburse- Flex- Sur- Receipt Delivery Rate Rate Term of Rate ment ibility charges - -------- -------- -------- ------- ------------ ---------- ------- ------- All All (Note 1) (Note 1) Through (Note 2) (Note 1) (Note 3) 9/30/96 Secondary Secondary R1 Res- Commod- Fuel Hourly Point of Point of ervation ity Term of Reimburse- Flex- Sur- Receipt Delivery Rate Rate Rate ment ibility charges - --------- --------- -------- ------- ------- ---------- ------- ------- All All (Note 1) (Note 1) Through (Note 2) (Note 1) (Note 3) 9/30/96 NOTES: (1) The rates for service hereunder shall be Transporter's maximum rates for service under Rate Schedules TF-2 and HFS-1, if applicable, or other superseding Rate Schedules, as such rates may be changed from time to time. Transporter shall apply the HFS-1 rate to Shipper's MDQ (1,408 Dth) unless Shipper notifies Transporter in writing that Shipper does not elect this service. (2) Fuel usage and lost and unaccounted-for deductions shall be as stated on Transporter's Schedule of Surcharges and Fees in the Tariff, as they may be changed from time to time, unless otherwise agreed between the Parties. Page 2 of 2 EXHIBIT "B" NOTES: (3) Applicable Surcharges: All applicable surcharges, unless otherwise specified, shall be the maximum surcharge rate as stated in the Schedule of Surcharges and Fees in the Tariff, as such surcharges may be changed from time to time. Gas Quality Control: The Gas Quality Control Surcharge shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in the Tariff. GRI: The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms and Conditions, both as set forth in the Tariff. Gas Supply Transition: The Gas Supply Transition Surcharge shall be assessed pursuant to Article 21 of the General Terms and Conditions as set forth in the Tariff. ACA: Transporter's applicable ACA Surcharge shall be added to all discounted rates except that in no event shall the discounted rate plus the ACA Surcharge exceed Transporter's maximum rate as stated in the Schedule of Rates in the Tariff. Contract No. 35009000A AMENDMENT DATED: November 1, 1993 to FIRM TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-2 DATED: October 1, 1993 between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY AMENDMENT TO FIRM TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-2 THIS AGREEMENT, made and entered into this 1st Day of November, 1993, by and between COLORADO INTERSTATE GAS COMPANY, hereinafter referred to as "Transporter," and GREELEY GAS COMPANY, hereinafter referred to as "Shipper." WHEREAS, Transporter and Shipper entered into a Transportation Service Agreement ("Agreement") dated October 1, 1993, providing for the transportation by Transporter for Shipper pursuant to 18 CFR 284.221 authority; and WHEREAS, Transporter and Shipper desire to amend the Agreement effective November 1, 1993, to revise the Primary Points of Delivery as stated in Exhibit "A" to the Agreement; NOW, THEREFORE, in consideration of the premises and the mutual covenants hereinafter contained, Transporter and Shipper agree to amend the Agreement as follows: Effective November 1, 1993, Exhibit "A" shall be deleted in its entirety and the attached Exhibit "A" shall be substituted therefor. This Amendment shall be effective as of November 1, 1993, and except as herein amended, the Agreement shall in all respects remain in full force and effect. IN WITNESS WHEREOF, the Parties have executed this Amendment. COLORADO INTERSTATE GAS COMPANY (Transporter) By /s/ D. J. Zinko ----------------------------- D. J. Zinko Senior Vice President GREELEY GAS COMPANY (Shipper) ATTEST: By /s/ Gary L. Schlessman ----------------------------- By Gary L. Schlessman ----------------------- -------------------------------- Title: (Print or type name) President -------------------------------- (Print or type title) 2 Page 1 of 2 EXHIBIT "A" to FIRM TRANSPORTATION SERVICE AGREEMENT between COLORADO INTERSTATE GAS COMPANY (Transporter) and GREELEY GAS COMPANY (Shipper) Agreement Dated: October 1, 1993 Amendment Dated: November 1, 1993 1. Shipper's Maximum Delivery Quantity: 1,408 Dth per Day (Note 3). Point of Maximum Receipt Quantity Receipt Primary Point(s) of Receipt (Dth per Day) Pressure (Note 1) (Note 2) p.s.i.g. Lakin Master Meter 1,408 900 Point of Delivery Quantity Delivery Primary Point(s) of Delivery (Dth per Day) Pressure (Note 1) (Note 4) p.s.i.g. Canon City Group (Note 5) Canon City 1,408 (Note 6) (Note 7) Colorado State Penitentiary 591 (Note 6) 100 Florence City Gate 1,408 (Note 6) 60 Penrose City Gate 394 (Note 6) 60 Penrose South 74 (Note 6) Line Pressure Portland City Gate 1,408 (Note 6) 100 Pritchett City Gate 295 (Note 6) 150 Fremont County Industrial Park 148 (Note 6) Line Pressure The Piggery 15 (Note 6) Line Pressure Engineer's Station 476+78 15 (Note 6) Line Pressure Penrose PBS-2 295 (Note 6) Line Pressure Page 2 of 2 EXHIBIT "A" NOTES: (1) Information regarding Points of Receipt and Points of Delivery, including legal descriptions, measuring parties, and interconnecting parties, shall be posted on Transporter's electronic bulletin board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. (2) Point of Receipt Quantities may be increased by an amount equal to Transporter's effective fuel reimbursement. (3) In Docket No. RP93-99, CIG's conversion to a thermal tariff is subject to review as to methodology, factors, or any other issue involved in the transition from a volumetric basis to a thermal basis. Should such review result in a change in the basis upon which the thermal quantities used in this service agreement were determined, such thermal quantities shall be adjusted as required. (4) The sum of the Primary Point of Delivery Quantities shall be equal to or less than Shipper's MDQ. (5) Transporter's obligation to make deliveries at all Primary Points of Delivery included in the Canon City Group shall be limited in the aggregate to 1,408 Dth per Day. (6) Transporter's obligation to make deliveries at this Point of Delivery under this Agreement and all other Firm Service Agreements shall be limited in the aggregate to the following volumes, or the meter capacity, whichever is less. Canon City 11,855 Colorado State Penitentiary 591 Florence City Gate 2,265 Penrose City Gate 394 Penrose South 74 Portland City Gate 3,073 Pritchett City Gate 295 Fremont County Industrial Park 148 The Piggery 15 Engineer's Station 476+78 15 Penrose PBS-2 295 (7) Line pressure but not less than 100 p.s.i.g. EX-10 8 EXHIBIT 10.7(a) AMARILLO SUPPLY AGREEMENT This Agreement is made and entered into effective the 2nd day of January 1993 by and between Mesa Operating Limited Partnership, a Delaware limited partnership, ("SELLER") and Energas Company, a division of Atmos Energy Corporation, a Texas Corporation ("BUYER"). WITNESSETH: WHEREAS, SELLER and BUYER are the respective successors to that certain Agreement between Amarillo Oil Company and Amarillo Gas Company, dated June 27, 1949, ("Amarillo Supply Contract"); and WHEREAS, SELLER and BUYER desire to consolidate the Amarillo Supply Contract and all amendments thereto into a single document which reflects the current agreement between SELLER and BUYER; Now THEREFORE, in consideration of the premises and mutual covenants and agreements contained herein as well as other valuable consideration, the sufficiency and receipt of which are hereby acknowledged, SELLER and BUYER mutually covenant and agree as follows: I. Amarillo Supply Contract Superseded: Effective January 2, 1993, all provisions of the Amarillo Supply Contract, and all amendments thereto are terminated and are hereby superseded by the terms of this Agreement. II. Supply of Gas: (a) SELLER agrees and obligates itself to sell and deliver to BUYER, and BUYER agrees to purchase and take from SELLER and pay for, all volumes of gas made available by SELLER to BUYER and which are required by BUYER to supply its present and future domestic and commercial customers located in the City of Amarillo, Texas, and its environs. (b) In order that BUYER may be assured of an adequate and permanent supply of gas under the terms and provisions hereof with which to meet its present and future market requirements, as above defined, BUYER shall have first call upon the residue gas attributable to the gas now owned or controlled by SELLER under and by virtue of that certain agreement dated January 3, 1928, between the Amarillo Oil Company, predecessor in interest of the SELLER and Canadian River Gas Company, predecessor in interest to Colorado Interstate Gas Company as amended from time to time (the "B" Contract). BUYER's first call rights to receive "B" Contract residue gas in preference to SELLER's rights to sell such gas to customers other than Energas shall be subject to the "B" Contract, as amended by that certain Production Allocation Agreement dated January 1, 1991, and that certain instrument entitled Amendment to "B" Contract and Production Allocation Agreement dated January 1, 1993 (collectively, the PAA) between the SELLER and Colorado Interstate Gas Company and shall apply only to such volumes of residue gas as are required to serve BUYER's domestic and commercial customers in the City of Amarillo and its environs; provided, however, that SELLER shall not be obligated to deliver to BUYER on a daily basis volumes in excess of the available residue gas attributable to 100 MMcf per day of SELLER's production under the "B" Contract. (c) SELLER will make no sale, transfer, assignment, or other disposition of its "B" Contract gas rights as are required to serve BUYER's domestic and commercial customers in the City of - 2 - Amarillo and its environs, except subject to the first call rights described herein. (d) That in the event SELLER shall default in the performance of any of its obligations hereunder, BUYER shall be subrogated to and entitled to exercise and enforce all the rights, privileges, remedies of SELLER against any and all persons and corporations through or from which SELLER's "B" Contract gas is obtained. III. Delivery Points and Pressure: The gas purchased hereunder by BUYER shall be delivered by SELLER to BUYER at the outlet discharge header of SELLER's Fain Gas Plant and at such other points as may be mutually agreed upon between BUYER and SELLER. During periods when the volume of gas demand on BUYER's system is less than or equal to the maximum volume of gas SELLER is required to deliver to BUYER's system pursuant to Article II hereof, the deliveries at the outlet of SELLER's Fain Gas Plant as aforesaid shall be made at pressures not less than 190# per square inch gauge and not in excess of 400# per square inch gauge, as required from time to time by BUYER. Notwithstanding the foregoing, if during periods when the volume of gas demand on BUYER's system is more than the maximum volume of gas SELLER is required to deliver to BUYER's system pursuant to Article II hereof, then SELLER's deliveries may be made at pressures less than 190# per square inch gauge. In the event BUYER desires a minimum delivery pressure in excess of 190# per square inch gauge then same shall be subject to negotiations between the parties, provided that BUYER shall give SELLER one - 3 - year's advance written notice requesting such future pressure. The deliveries made at points other than the outlet of SELLER's Fain Gas Plant shall be made at pressures suitable to BUYER but within the then existing limitations of SELLER's supply at such points. IV. Prices and Charges: (a) Prices: Except as provided in Section (c) of this Article IV, all gas delivered to BUYER by SELLER pursuant to this Agreement shall be priced as follows: A composite price per Mcf for gas delivered hereunder shall be determined by a formula comprised of a Fixed Price component which will be utilized for seventy percent (70%) of the composite price, and a Spot Price component which will be utilized for thirty percent (30%) of the composite price. Such formula price will be in effect for a period beginning January 2, 1993 and ending December 31, 1997. The pricing of gas to be delivered hereunder in periods subsequent to December 31, 1997 is described in Section (c) of this Article IV. The composite price per Mcf to be paid each month by BUYER shall be calculated as follows: Monthly Price = {FP x 0.7} + {(SP + $0.10) (0.3)} where: FP = Fixed Price component SP = Spot Price component The Fixed Price component shall be determined for each year by establishing a Fixed Price of $2.71 per Mcf for the initial year of 1993. The Fixed Price shall be redetermined for each subsequent year by escalating the prior year's Fixed Price by - 4 - five percent (5%) for calendar years 1994 and 1995, and seven and one-half percent (7.5%) for calendar years 1996 and 1997. The Fixed Price component of the formula price is thus calculated as follows: Year Fixed Price Component Per Mcf 1993 $2.71 = 1993 Fixed Price 1994 $2.71 x 1.05 = 1994 Fixed Price 1995 1994 Fixed Price x 1.05 = 1995 Fixed Price 1996 1995 Fixed Price x 1.075 = 1996 Fixed Price 1997 1996 Fixed Price x 1.075 = 1997 Fixed Price The Spot Price component shall be determined monthly and shall be comprised of the hereinafter described Spot Index Price, plus a fee of $0.10. The parties shall use the first issue of Natural Gas Week published each month to determine the Spot Index Price. The Spot Index Price shall be that price reported in the table titled "Gas Price Report" under the subheadings "Texas, West, Spot, Delivered to Pipeline" in the "Bid Week" column for the month of actual delivery. If such index ceases to be published or the parties mutually agree that the index ceases to reasonably reflect the spot price for gas, the parties shall attempt to agree on a substitute index giving due regard to the purpose and intent in selecting this original index. If the parties cannot mutually agree on a substitute index or cannot agree that the index in effect at the time has ceased to reasonably reflect the spot price for gas delivered hereunder, then in either of such events, the parties agree that they shall submit the issue of the alternate selection of an appropriate index to binding arbitration to be conducted by and under the - 5 - then existing rules of the American Arbitration Association ("AAA") within thirty (30) days of written notification from one party to the other; provided, however, that such arbitration shall not be conducted more often than once every two years in the event of disagreement as to whether a particular index reasonably reflects the spot price for gas. The question of selection of an index brought about by the cessation of publication of an index being used may be submitted to arbitration as often as is necessary. The selection of arbitrators will be conducted pursuant to the process described under Section (c) of Article IV below and the three arbitrators so chosen will be required to issue within thirty (30) days from the date of their selection their decision on the appropriate index to be utilized. The parties agree that until a new index has been established, the applicable Spot Price to be used on an interim basis each month will be the Spot Price for the same month of the prior year plus 5%. As soon as the new index is established, it will become retroactively effective as of the first day of the month following the month during which the thirty (30) day written notification was received by the second party and any required adjustment will be made within ninety (90) days. (b) Tax Surcharges: It is understood and agreed that the prices for gas provided for herein shall be increased or decreased, as the case may be, to reflect the full amount of any new or additional, or of any increase or decrease in present rates of severance, gross production, gross receipts, and excise taxes of any nature whatsoever or similar taxes which, after - 6 - January 1, 1993, may be imposed, levied or assessed by any governmental authority upon the gas sold hereunder, whether or not the same shall be paid or payable directly or indirectly by SELLER. Taxes being reimbursed by BUYER to SELLER as of December 31, 1992 will continue to be reimbursed by BUYER and shall be calculated in the same manner as such taxes were calculated on December 31, 1992. Applicable laws, rulings or orders increasing, decreasing or creating any such tax shall be binding and conclusive upon BUYER until such time as the invalidity thereof has been finally established by the decision of a court of competent jurisdiction. In no event, however, shall the provisions of this paragraph be applied or construed so as to decrease the prices for gas sold by virtue of this Agreement below the applicable prices then in effect pursuant to Sections (a) or (c) of this Article IV. In the event any tax included within this Section is legally determined to be invalid or unlawfully collected and a refund thereof is subsequently received by SELLER, then SELLER agrees to return to BUYER such portion of the refund as may have been applicable to purchases made by BUYER and paid by BUYER to SELLER, less SELLER's costs of recovering such refund. (c) Future price determinations: The price redetermi- nation procedure set forth hereinafter shall be employed for each two year period of the remaining term of the Amarillo Supply Agreement, following the formula pricing period (1993 - 1997) outlined in (a) above. On or before September 1, 1997, and on or before September 1 each two years thereafter, BUYER and SELLER shall meet to determine the price(s) or pricing formula to be in - 7 - effect during each subsequent two year period, commencing January 1, 1998. If the parties have not redetermined the price(s) or agreed upon a pricing formula by September 1, 1997, and each September 1 each two years thereafter, then the parties agree that they shall submit such pricing determination to binding arbitration to be conducted by, and under the then existing rules of the AAA within thirty (30) days of written notification from one party to the other. Within sixty (60) days of such submission, three arbitrators shall be chosen by the parties from panels supplied by the AAA. If the parties are unable to select three arbitrators during such period, the selection of the remaining arbitrator(s) shall be conducted pursuant to the rules of the AAA governing the selection of arbitrator(s) when the parties have failed to do so. The arbitrators so chosen shall be instructed to determine, within ninety (90) days from their selection, a reasonable price(s) or pricing formula based on the particular character- istics of the supply under the Amarillo Supply Agreement at the time of the price redetermination for the two year period beginning January 1, 1998, or any subsequent two year period, for which the parties are unable to agree upon a price(s) or pricing formula. Essential characteristics to be considered by the arbitrators include the following: 1) The annual volume normally purchased from SELLER by BUYER. 2) The daily volume made available from SELLER to BUYER during the various seasons of the year. - 8 - 3) The average daily volume utilized by BUYER during the course of a year. 4) The load factor and daily and seasonal swings of BUYER's Amarillo system demands. 5) The remaining term of the Amarillo Supply Agreement. The parties agree that until a new price(s) or pricing formula has been established, the applicable composite price for each month to be used on an interim basis will be the same as the applicable composite price established for the same month of the prior year plus 5%. As soon as the new price(s) or pricing formula is established, it will become retroactively effective as of the first day of the new pricing period and any required adjustment will be made within ninety (90) days. V. Quality: All of the gas sold hereunder shall be gasoline plant residue gas and shall have the following characteristics: (a) It shall contain not more than twenty-five one hundredths (0.25) grain of hydrogen sulphide per 100 cubic feet measured as herein provided; (b) The dew point at delivery pressure shall be at least ten degrees below the existing ground temperature at pipeline depth; (c) It shall be commercially free of dust, gums, and other solid matter; (d) The gas shall have a monthly weighted gross heating value of not less than nine hundred fifty (950) British Thermal Units per cubic foot. - 9 - VI. Meters and Measurement: (a) The volume of gas delivered hereunder shall be measured by orifice meters installed and maintained as prescribed in the Gas Measurement Committee Report No. 3, (ANSI/API-2530, Second Edition) of the American Gas Association and as revised from time to time. (AGA Report No. 3) (b) BUYER shall maintain and operate at or near the various points of delivery, suitable meters and auxiliary equipment to properly measure the volumes of gas being delivered. All such measuring equipment shall remain the sole property of BUYER but the SELLER shall have access to said metering equipment at all reasonable times. The reading, calibration, and adjusting of said meters shall be done by the employees or agents of BUYER and charts and records from such metering equipment shall remain the property of BUYER, but upon request of SELLER, BUYER will submit to SELLER the records and charts from said metering equipment together with calculations therefrom for SELLER'S inspection and verification subject to return by SELLER within a reasonable period of time. (c) SELLER may, at its option and at its sole cost and expense, install and operate check metering equipment, but the metering equipment of BUYER shall be used for determining the amounts of gas delivered under this Agreement. (d) The unit of measurement for all gas deliverable under this Agreement shall be one thousand (1,000) cubic feet of natural gas at a base temperature of sixty (60) degrees Fahrenheit and at a base pressure of 14.65 pounds absolute and the readings and registrations of all metering equipment shall be - 10 - computed into such units in accordance with AGA Report No. 3 referenced above. (e) For the purpose of measurement the average atmospheric pressure shall be assumed to be thirteen (13.0) pounds irrespective of the actual elevation of the delivery point above sea level or of variations in the barometric pressure from time to time. (f) For meters of the orifice type, corrections shall be made for the following factors: 1) Flowing temperature variation from 60 degrees Fahrenheit; 2) Deviation of the gas from Boyle's Law; 3) Calculations shall be based on specific gravities determined by chromatograph analysis of the flowing gas stream for the current month, based upon either a continuous composite sample at the tailgate of the Fain Plant or a proportional to flow composite sample at the tailgate of the Fain Plant. (g) All determinations of physical characteristics, and meter tests shall be made with standard apparatus and using generally accepted industry methods at such times and places as in accordance with good practice may be agreed upon from time to time between SELLER and BUYER. VII. Billing and Payment: SELLER shall render to BUYER, on or before the tenth (10th) day of each month a statement showing the volume of gas delivered to BUYER during the calendar month immediately preceding and the amount of payment or payments then due from BUYER to SELLER for such gas delivered. In the event an error is discovered in the amount billed in any - 11 - statement rendered by SELLER, such error shall be adjusted within thirty (30) days after a claim is made therefore, but in any event within twenty-four (24) months from the date of such statement. Failure to make a written request for a required adjustment within the twenty-four (24) month period shall be deemed a waiver of that adjustment by the party having such adjustment rights. Both SELLER and BUYER shall have the right to examine, at reasonable times, books, records and charts of the other to the extent necessary to verify the accuracy of any statement, charge or computation made under or pursuant to any of the provisions hereof. BUYER agrees to pay SELLER at its office in Amarillo, Texas, or at such other address designated in writing by SELLER, on or before the 20th day of each month for all gas delivered hereunder during the preceding month according to the gas measurements and computations and at the prices hereinbefore provided for and billed on said monthly statement. Should BUYER fail to pay any amount due SELLER when such amount is due and such failure to pay continues for sixty (60) days, then SELLER may suspend deliveries of gas, but the exercise of such right shall be in addition to any and all other remedies available to SELLER. VIII. Force Majeure: In the event of either party being rendered unable wholly or in part by force majeure to carry out its obligations under this Agreement other than to make payments of amounts due hereunder, it is agreed that on such party giving notice and full particulars of such force majeure in writing or by telegraph to the other party as soon as possible after the - 12 - occurrence of the cause relied on, then the obligations of the party giving such notice, so far as they are affected by such force majeure, shall be suspended during the continuance of any inability so caused but for no longer period, and such cause shall, so far as possible, be remedied with all reasonable dispatch. The term "force majeure" as employed herein shall mean acts of God, strikes, lockouts or other industrial disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraint of rulers and people, civil disturbances, explosions, breakage or accident to machinery or lines of pipe, the necessity for making repairs and/or alterations in machinery or lines of pipe, freezing of wells or lines of pipe, sudden partial or entire failure of natural gas wells, and any other cause, whether of the kind herein enumerated, or otherwise, not within the control of the party claiming suspension and which by the exercise of due diligence such party is unable to overcome. IX. Responsibility for Handling: As between the parties hereto, SELLER shall be in control and possession of the gas deliverable hereunder and responsible for any damage or injury caused thereby until the same shall have been delivered to BUYER, after which delivery BUYER shall be deemed to be in exclusive control and possession thereof and responsible for any such injury or damage. X. Termination for Default: If either party shall fail to perform the covenants or obligations imposed upon it under and by - 13 - virtue of this Agreement, then and in such event the other party may, at its option, terminate this Agreement by proceeding as follows: The party not in default shall cause written notice to be served on the party in default, stating specifically the cause for terminating this Agreement and declaring it to be the intention of the party giving the notice to terminate the same; thereupon the party in default shall have thirty (30) days after the service of the aforesaid notice in which to remedy or remove the cause or causes stated in the notice for terminating this Agreement and if, within said period of thirty (30) days, the party in default does so remove and remedy said cause or causes and fully indemnifies the party not in default for any and all consequences of such breach, then such notice shall be withdrawn and this Agreement shall continue in full force and effect. In case the party in default does not so remedy and remove the cause or causes and/or does not indemnify the party giving the notice for any and all consequences of such breach within said period of thirty (30) days, and if the party giving the notice does not withdraw the notice, then this Agreement shall become null and void from and after the expiration of said period. Any cancellation of this Agreement pursuant to the provisions of this article shall be without prejudice to any right of the party not in default to collect any amounts then due to it and without waiver of any other remedy to which the party not in default may be entitled for violation of this Agreement. XI. Successors and Assigns: This Agreement shall inure to the benefit of and be binding upon the successors and assigns of - 14 - the parties hereto, and is intended solely for the benefit of BUYER and SELLER and their respective successors and assigns and not for the benefit of any third parties. Whenever the name of any corporation or partnership is used herein it shall include the successors and assigns of such corporation or partnership, but neither party hereto may assign this Agreement without the written consent of the other being first had and obtained, which written consent shall not be unreasonably withheld. XII. Term: This Agreement shall be in force and effect from and after January 2, 1993, and shall continue in force and effect for so long as SELLER has merchantable quantities of gas available hereunder for sale to BUYER. XIII. Miscellaneous: (a) This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, excluding any conflicts of law, rule, or other principle which might refer such construction to the laws of another state. All terms and conditions of this Agreement were prepared jointly by the SELLER and BUYER and not by any party to the exclusion of the other. (b) This Agreement may not be modified or amended except by the written agreement of the parties hereto. (c) No waiver by either party hereto of any default of the other party or breach of any provision of the other party under this Agreement shall operate as, or be deemed to be, a waiver of any other or subsequent default or breach, whether of a like or different nature. (d) Each provision and term of this Agreement is intended to be several. If any term or provision hereof is held to be - 15 - illegal or invalid by a court of competent jurisdiction, such illegality or invalidity shall not affect in any way the validity or legality of the remaining terms or provisions. IN WITNESS WHEREOF, the parties hereto have executed this Amarillo Supply Agreement effective as of the date first above written. MESA OPERATING LIMITED PARTNERSHIP By Pickens Operating Co., General Partner By /s/ s. Leonard Hruzek, Jr. ----------------------------- S. Leonard Hruzek, Jr., Vice President Date September 2, 1993 ----------------------------- ENERGAS COMPANY, a division of Atmos Energy Corporation By /s/ Toby A. Priolo ----------------------------- Toby A. Priolo, Vice President Date August 27, 1993 ----------------------------- - 16 - EX-23 9 Exhibit 23 CONSENT OF INDEPENDENT AUDITOR We consent to the incorporation by reference in the Registration Statements (Form S-8 No. 33-68852, Form S-8 No. 2-89113, Form S-3 No. 33-58220, and Form S-3 No. 33-70212) of Atmos Energy Corporation and in the related Prospectuses of our report dated November 9, 1994, with respect to the consolidated financial statements and schedules of Atmos Energy Corporation included in this Annual Report (Form 10-K) for the year ended September 30, 1994. ERNST & YOUNG LLP Dallas, Texas December 15, 1994 1 EX-27 10
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF ATMOS ENERGY CORPORATION FOR THE YEAR ENDED SEPTEMBER 30, 1994 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR SEP-30-1994 SEP-30-1994 PER-BOOK 327,407 0 53,298 35,973 0 416,678 77 102,456 47,023 149,556 0 0 138,303 0 18,100 0 4,000 0 5,741 553 100,425 416,678 499,808 8,102 465,240 473,342 26,466 503 26,969 12,290 14,679 0 14,679 12,732 1,916 41,224 .97 .97
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