-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AeA3aPzWUeld9H0RDXuwuH60d+4lFDZX92nEw/D16FIi9yWPt7aDvgQb3HroqdSq kPLkWXnd4XySzZuoo66CoA== 0000950134-03-015731.txt : 20031121 0000950134-03-015731.hdr.sgml : 20031121 20031121154400 ACCESSION NUMBER: 0000950134-03-015731 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 27 CONFORMED PERIOD OF REPORT: 20030930 FILED AS OF DATE: 20031121 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: 031018150 BUSINESS ADDRESS: STREET 1: 1800 THREE LINCOLN CTR STREET 2: 5430 LBJ FREEWAY CITY: DALLAS STATE: TX ZIP: 75240 BUSINESS PHONE: 9729349227 MAIL ADDRESS: STREET 1: 1800 THREE LINCOLN CTR STREET 2: 5430 LBJ FREEWAY CITY: DALLAS STATE: TX ZIP: 75240 FORMER COMPANY: FORMER CONFORMED NAME: ENERGAS CO DATE OF NAME CHANGE: 19881024 10-K 1 d10753e10vk.txt FORM 10-K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-10042 ATMOS ENERGY CORPORATION (Exact name of registrant as specified in its charter) TEXAS AND VIRGINIA 75-1743247 (State or other jurisdiction of (IRS employer incorporation or organization) identification no.) THREE LINCOLN CENTRE, SUITE 1800 75240 5430 LBJ FREEWAY, DALLAS, TEXAS (Zip code) (Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (972) 934-9227 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common stock, No Par Value New York Stock Exchange
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. [ ] Indicate by check whether the recipient is an accelerated filer (as defined in Exchange Act Rule 12b-2. Yes [X] No [ ] The aggregate market value of the voting stock held by non-affiliates of the registrant was $1,191,025,336 as of October 31, 2003. On October 31, 2003 the registrant had 51,534,331 shares of common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 11, 2004 are incorporated by reference into Part III of this report. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- PART I The terms "we," "our," "us," "Atmos" and "Atmos Energy" refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise. The abbreviations "Mcf," "MMcf" and "Bcf" mean thousand cubic feet, million cubic feet and billion cubic feet. ITEM 1. BUSINESS OVERVIEW Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain natural gas non-utility businesses. We distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers through our six regulated utility divisions, which cover service areas located in the following 12 states: Colorado, Georgia, Illinois, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Tennessee, Texas and Virginia. In addition, we transport natural gas for others through our distribution system. Through our non-utility businesses, we provide natural gas management and marketing services to industrial customers, municipalities and other local gas distribution companies in 18 states. We also supplement natural gas used by our customers through natural gas storage fields that we own or hold an interest in and which are located in Kansas, Kentucky, Louisiana and Mississippi. We market natural gas to industrial and agricultural customers primarily in west Texas and to industrial customers in Louisiana. Finally, we construct electric power generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers. Our operations are divided into three segments: - the utility segment, which includes our related natural gas distribution and sales operations, - the natural gas marketing segment, which includes a variety of natural gas management services and - the other non-utility segment, which includes our storage services and our electric power plant construction and leasing services. Financial information relating to our operating segments is contained in Note 17 to the consolidated financial statements. STRATEGY Our overall strategy is to: - accelerate growth through profitable acquisitions; - improve the quality and consistency of earnings growth, while operating the natural gas utility and non-utility businesses exceptionally well and - enhance and strengthen a culture built on our core values. Over the last five years, we have accelerated our growth through several acquisitions including our acquisition of the remaining 55 percent interest in Woodward Marketing, L.L.C. that we did not already own in April 2001, the assets of Louisiana Gas Service Company (LGS) in July 2001 and Mississippi Valley Gas Company (MVG) in December 2002. We have experienced 20 consecutive years of increasing dividends and consistent earnings growth after giving effect to our mergers. We have achieved this record of growth while operating our utility operations efficiently by managing our operating and maintenance expense; leveraging our technology, such as our 24 hour call center, to achieve more efficient operations; focusing on regulatory rate proceedings to increase revenue as our costs increased; mitigating weather-related risks through weather-normalized rates in some jurisdictions and disposing of non-growth assets. Additionally, we have strengthened our non-utility business 1 by essentially eliminating speculative trading activities and actively pursing opportunities to increase the amount of storage available to us to help mitigate the effects of weather on our trading activities. Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We are strengthening our culture through continuous communication with our employees and enhanced training. UTILITY SEGMENT We operate our utility segment through six regulated natural gas utility divisions. Effective October 1, 2002, we united our gas distribution utility operations under the Atmos Energy brand. The following presents our six natural gas utility divisions and their former operating names: - Atmos Energy Colorado-Kansas Division (formerly Greeley Gas Company), - Atmos Energy Kentucky Division (formerly Western Kentucky Gas Company), - Atmos Energy Louisiana Division (formerly Atmos Energy Louisiana Gas Company), - Atmos Energy Mid-States Division (formerly United Cities Gas Company), - Atmos Energy Texas Division (formerly Energas Company) and - Mississippi Valley Gas Company Division (acquired in December 2002). Our natural gas utility distribution business is seasonal and dependent on weather conditions in our 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 gas sales during the winter months will vary with the temperatures during these months. The seasonal nature of our sales to residential and commercial customers is partially offset by our sales in the spring and summer months to our agricultural customers in Texas, Colorado and Kansas who use natural gas to operate irrigation equipment. In addition to weather, our revenues are affected by the cost of natural gas and economic conditions in the areas that we serve. Higher gas costs, which we are generally able to pass through to our customers under purchased gas adjustment clauses, may cause customers to conserve, or, in the case of industrial customers, to use alternative energy sources. The effects of weather that is above or below normal are partially offset through weather normalization adjustments (WNA) in certain service areas. WNA allows us to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. As of September 30, 2003, we have WNA in the following service areas for the following periods, which cover approximately 658,000 or 39 percent of our meters in service: Tennessee................................................... November -- April Georgia..................................................... October -- May Mississippi................................................. November -- May Kentucky.................................................... November -- April Kansas(1)................................................... October -- May Amarillo, Texas(1).......................................... October -- May
- --------------- (1) Effective for the 2003-2004 winter heating season We receive gas deliveries in our utility operations through 36 pipeline transportation companies, both interstate and intrastate, to satisfy our sales market requirements. The pipeline transportation agreements are firm and many of them have "pipeline no-notice" storage service which provides for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term necessary while still maintaining our right of first refusal. 2 We purchase our gas supply from various producers and marketers. Supply arrangements are contracted on a firm basis with various terms at market prices. The firm supply consists of both base load and swing supply quantities. Base load quantities are those that flow at a constant level throughout the month and swing supply quantities provide the flexibility to change daily quantities to match increases or decreases in requirements related to weather conditions. Except for local production purchases, we select suppliers through a competitive bidding process by requesting proposals from suppliers that have demonstrated that they can provide reliable service. We select these suppliers based on their ability to deliver gas supply to our designated firm pipeline receipt points at the lowest cost. Our major suppliers during fiscal 2003 were Anadarko Energy Services, BP Energy Company, Cinergy Marketing and Trading, Duke Energy Trading and Marketing, ONEOK Energy Marketing, Pioneer Natural Resources, Prior Energy Corporation, Tenaska Marketing and Woodward Marketing, L.L.C., one of our natural gas marketing subsidiaries. We do not anticipate problems with obtaining additional gas supply as needed for our customers. We also contract for storage service in underground storage facilities on many of the interstate pipelines serving us. Our distribution systems have experienced aggregate peak day deliveries of approximately 2.0 Bcf per day. To maintain our deliveries to high priority customers, we have the ability and have exercised our right, to curtail deliveries to certain customers under the terms of interruptible contracts, applicable state statutes or regulations. The following is a brief description of our six natural gas utility divisions. Additional information for each division is presented under the caption "Operating Statistics". Atmos Energy Colorado-Kansas Division. Our Colorado-Kansas Division operates in Colorado, Kansas and the southwestern corner of Missouri and is regulated by each respective state's public service commission with respect to accounting, rates and charges, operating matters and the issuance of securities. We operate under terms of non-exclusive franchises granted by the various cities. In May 2003, we received approval for WNA in Kansas which will be effective October through May of each year beginning with the 2003-2004 winter heating season. Colorado Interstate Gas Company, Williams Pipeline-Central, Public Service Company of Colorado and Northwest Pipeline are the principal transporters of the Colorado-Kansas Division's gas supply requirements. Additionally, the Colorado-Kansas Division purchases substantial volumes from producers that are connected directly to its distribution system. Atmos Energy Kentucky Division. Our Kentucky Division operates in Kentucky and is regulated by the Kentucky Public Service Commission, which regulates utility services, rates, issuance of securities and other matters. We operate in the various incorporated cities pursuant to non-exclusive franchises granted by these cities. Sales of natural gas for use as vehicle fuel in Kentucky are unregulated. We have been operating under a performance-based rate program since July 1998, which was extended for another four years in 2002. Under the performance-based program, we and our customers jointly share in any actual gas cost savings achieved when compared to pre-determined benchmarks. Our rates are also subject to WNA. The Kentucky Division's gas supply is delivered primarily by Williams Pipeline-Texas Gas, Tennessee Gas, Trunkline, Midwestern Pipeline and ANR. Atmos Energy Louisiana Division. Our Louisiana Division operates in Louisiana and includes the operations of the assets of Louisiana Gas Service Company acquired in July 2001 and our previously existing Trans La Division. Our Louisiana Division is regulated by the Louisiana Public Service Commission, which regulates utility services, rates and other matters. We operate most of our service areas pursuant to a non-exclusive franchise granted by the governing authority of each area. Direct sales of natural gas to industrial customers in Louisiana, who use gas for fuel or in manufacturing processes, and sales of natural gas for vehicle fuel are exempt from regulation. Louisiana Intrastate Gas Company, Acadian Pipeline, Gulf South and Williams Pipeline-Texas Gas pipelines provide most of the Louisiana Division's natural gas requirements. Atmos Energy Mid-States Division. Our Mid-States Division operates in Georgia, Illinois, Iowa, Missouri, Tennessee and Virginia. In each of these states, our rates, services and operations as a natural gas distribution company are subject to general regulation by each state's public service commission. We operate 3 in each community, where necessary, under a franchise granted by the municipality for a fixed term of years. In Tennessee and Georgia, we have WNA and a performance-based rate program, which provides incentives for us to find ways to lower costs and share the cost savings with our customers. Our Mid-States Division is served by 13 interstate pipelines; however, the majority of the volumes are transported through East Tennessee Pipeline, Southern Natural Gas, Tennessee Gas Pipeline and Columbia Gulf. Atmos Energy Texas Division. Our Texas Division operates in Texas in three primary service areas: the Amarillo service area, the Lubbock service area and the West Texas service area. The governing body of each municipality we serve 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. We operate pursuant to non-exclusive franchises granted by the municipalities we serve, which are subject to renewal from time to time. The Railroad Commission of Texas has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality. In August 2003, the Texas Division received approval from the City of Amarillo, Texas, for WNA for its Amarillo service area, which will be effective October through May of each year, beginning with the 2003-2004 winter heating season. Our Texas Division receives transportation service from ONEOK Pipeline. In addition, the Texas Division purchases a significant portion of its natural gas supply from Pioneer Natural Resources which is connected directly to our Amarillo, Texas distribution system. Mississippi Valley Gas Company Division. Our Mississippi Valley Gas Company Division, acquired in December 2002, operates in Mississippi and is regulated by the Mississippi Public Service Commission with respect to rates, services and operations. We operate under non-exclusive franchises granted by the municipalities we serve. Since the acquisition, we have been operating under a rate structure that allows us over a five year period to recover a portion of our integration costs associated with the acquisition, and operations and maintenance costs in excess of an agreed-upon benchmark. In addition, we are required to file for rate adjustments based on our expenses every six months. We also have WNA in Mississippi. This division's gas supply is delivered by Gulf South Pipeline Company, Tennessee Gas Pipeline Company, Southern Natural Gas Company, Texas Eastern Transmission, Texas Gas Transmission LLC, Trunkline Gas Co. LLC and Enbridge Marketing LP. NATURAL GAS MARKETING SEGMENT Our natural gas marketing and other non-utility segments, which are organized under Atmos Energy Holdings, Inc., have operations in 18 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, L.L.C and Trans Louisiana Industrial Gas Company, Inc were merged into Woodward Marketing, L.L.C., which was renamed Atmos Energy Marketing, LLC (AEM). We acquired a 45 percent interest in Woodward Marketing, L.L.C. in July 1997 as a result of the merger of Atmos and United Cities Gas Company, which had acquired that interest in May 1995. In April 2001, we acquired the remaining 55 percent interest that we did not own for 1,423,193 restricted shares of our common stock. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services primarily consist of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price management through the use of derivative products. In providing these services, AEM generates income from its utility, municipal and industrial customers through negotiated prices based on the volume of gas supplied to the customer. AEM also generates income by taking advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of 4 gas prices by utilizing storage and transportation capacity that it controls. Finally, AEM supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis. AEM's management of natural gas requirements involves the sale of natural gas and the management of storage and transportation supplies under contracts with customers generally having one to two year terms. At September 30, 2003, AEM had a total of 750 industrial customers and 206 municipal customers. AEM also sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. OTHER NON-UTILITY SEGMENT Our other non-utility segment consists primarily of the operations of Atmos Pipeline and Storage, L.L.C. and Atmos Power Systems, Inc., which are wholly-owned subsidiaries of Atmos Energy Holdings, Inc. Through Atmos Pipeline and Storage, LLC, we own or have an interest in underground storage fields in Kansas, Kentucky and Louisiana. We use these storage facilities to help meet customer requirements during peak demand periods and to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. We normally inject gas into pipeline storage systems and company owned storage facilities during the summer months and withdraw it in the winter months. Through Atmos Power Systems, Inc. we construct and operate electric peaking power generating plants and associated facilities and may enter into agreements to either lease or sell these plants. United Cities Propane Gas, Inc., a wholly-owned subsidiary of Atmos Energy Holdings, Inc., owns an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies. As of September 30, 2003, USP owned all of the general partnership interest and approximately 26 percent of the limited partnership interest in Heritage Propane Partners, L.P. a publicly traded marketer of propane through a nationwide retail distribution network. Through our ownership in USP, we own an approximate five percent indirect interest in Heritage Propane Partners, L.P. On November 7, 2003, we announced that we and our utility partners had entered into an agreement to sell our interest in USP, including the general partnership and limited partnerships in Heritage Propane Partners, L.P., for $130.0 million. We expect to receive approximately $24.7 million and to record a $4.4 million pretax book gain upon closing of the transaction which is conditioned upon regulatory and other approvals. 5 OPERATING STATISTICS The following tables present certain operating statistics for our utility, natural gas marketing and other non-utility segments for each of the five fiscal years from 1999 through 2003. Certain prior year amounts have been reclassified to conform to the current year presentation. UTILITY SALES AND STATISTICAL DATA
YEAR ENDED SEPTEMBER 30 -------------------------------------------------------------- 2003(1) 2002 2001(1) 2000 1999 ---------- ---------- ---------- ---------- ---------- METERS IN SERVICE, END OF YEAR Residential............................. 1,498,586 1,247,247 1,243,625 970,873 919,012 Commercial.............................. 151,008 122,156 122,274 104,019 98,268 Industrial.............................. 3,799 2,118 1,838 1,878 1,552 Agricultural............................ 9,514 10,576 11,182 12,381 12,777 Public authority and other.............. 9,891 7,244 7,404 7,448 6,386 ---------- ---------- ---------- ---------- ---------- Total meters.......................... 1,672,798 1,389,341 1,386,323 1,096,599 1,037,995 ========== ========== ========== ========== ========== HEATING DEGREE DAYS(2) Actual (weighted average)............... 3,473 3,368 4,124 2,096 3,374 Percent of normal....................... 101% 94% 115% 82% 85% UTILITY SALES VOLUMES -- MMCF(3) Gas Sales Volumes Residential............................. 97,953 77,386 79,000 63,285 67,128 Commercial.............................. 45,611 35,796 36,922 30,707 31,457 Industrial.............................. 23,738 14,499 19,243 18,546 19,934 Agricultural............................ 7,884 10,988 7,070 1,412 967 Public authority and other.............. 9,326 5,875 6,892 5,520 5,793 ---------- ---------- ---------- ---------- ---------- Total gas sales volumes............... 184,512 144,544 149,127 119,470 125,279 Utility transportation volumes............ 70,159 69,589 69,492 77,767 69,899 ---------- ---------- ---------- ---------- ---------- Total utility throughput.................. 254,671 214,133 218,619 197,237 195,178 ========== ========== ========== ========== ========== UTILITY OPERATING REVENUES (000'S)(3) Gas sales revenues Residential............................. $ 873,375 $ 535,981 $ 788,902 $ 405,552 $ 349,691 Commercial.............................. 367,961 221,728 342,945 176,712 144,836 Industrial.............................. 151,969 70,164 120,770 90,966 70,322 Agricultural............................ 48,625 37,951 28,753 6,178 2,872 Public authority and other.............. 65,921 31,731 58,539 27,198 22,330 ---------- ---------- ---------- ---------- ---------- Total utility gas sales revenues...... 1,507,851 897,555 1,339,909 706,606 590,051 Transportation revenues................... 30,461 28,786 28,750 28,726 26,933 Other gas revenues........................ 15,770 11,185 11,489 4,619 4,227 ---------- ---------- ---------- ---------- ---------- Total utility operating revenues...... $1,554,082 $ 937,526 $1,380,148 $ 739,951 $ 621,211 ========== ========== ========== ========== ========== Utility average sales price per Mcf....... $ 8.17 $ 6.21 $ 8.99 $ 5.91 $ 4.71 Utility average transportation revenue per Mcf..................................... $ 0.43 $ 0.41 $ 0.41 $ 0.37 $ 0.39 Utility average cost of gas per Mcf sold.................................... $ 5.76 $ 3.87 $ 6.82 $ 3.67 $ 2.74 Employees(5).............................. 2,313 1,766 1,819 1,488 1,471
See footnotes following these tables. 6 UTILITY SALES AND STATISTICAL DATA BY DIVISION (4)
YEAR ENDED SEPTEMBER 30, 2003 -------------------------------------------------------------------------------------- COLORADO- KANSAS KENTUCKY LOUISIANA MID-STATES TEXAS MISSISSIPPI TOTAL UTILITY --------- -------- --------- ---------- -------- ----------- ------------- METERS IN SERVICE Residential..................... 199,853 159,024 346,866 274,025 271,198 247,620 1,498,586 Commercial...................... 18,759 18,077 22,843 35,889 26,228 29,212 151,008 Industrial...................... 36 406 -- 729 933 1,695 3,799 Agricultural.................... 413 -- -- -- 9,101 -- 9,514 Public authority and other...... 1,584 1,661 930 750 2,208 2,758 9,891 -------- -------- -------- -------- -------- -------- ---------- Total......................... 220,645 179,168 370,639 311,393 309,668 281,285 1,672,798 ======== ======== ======== ======== ======== ======== ========== HEATING DEGREE DAYS(2) Actual.......................... 5,704 4,364 1,735 3,843 3,487 2,243 3,473 Percent of normal............... 101% 101% 106% 101% 97% 101% 101% SALES VOLUMES -- MMCF(3) Gas Sales Volumes Residential..................... 17,419 12,700 16,066 18,780 20,091 12,897 97,953 Commercial...................... 6,506 5,442 6,841 13,106 7,448 6,268 45,611 Industrial...................... 313 2,613 -- 8,332 4,149 8,331 23,738 Agricultural.................... 858 -- -- -- 7,026 -- 7,884 Public authority and other...... 1,233 1,559 867 277 2,342 3,048 9,326 -------- -------- -------- -------- -------- -------- ---------- Total......................... 26,329 22,314 23,774 40,495 41,056 30,544 184,512 Transportation Volumes............ 9,615 24,848 7,960 20,011 5,671 2,054 70,159 -------- -------- -------- -------- -------- -------- ---------- Total Throughput.................. 35,944 47,162 31,734 60,506 46,727 32,598 254,671 ======== ======== ======== ======== ======== ======== ========== OPERATING REVENUES (000'S)(3)..... $206,653 $177,613 $261,896 $374,725 $274,520 $258,675 $1,554,082 OTHER STATISTICS, AT YEAR END Miles of pipe................... 6,341 3,840 7,952 7,790 13,261 6,083 45,267 Employees(5).................... 275 237 450 453 341 557 2,313
See footnotes following these tables. 7
YEAR ENDED SEPTEMBER 30, 2002 ---------------------------------------------------------------------- COLORADO- MID- KANSAS KENTUCKY LOUISIANA STATES TEXAS TOTAL UTILITY --------- -------- --------- -------- -------- ------------- METERS IN SERVICE Residential.............................. 196,320 158,296 346,369 273,166 273,096 1,247,247 Commercial............................... 18,602 18,017 22,709 35,925 26,903 122,156 Industrial............................... 41 409 -- 729 939 2,118 Agricultural............................. 423 -- -- -- 10,153 10,576 Public authority and other............... 1,594 1,657 934 810 2,249 7,244 -------- -------- -------- -------- -------- ---------- Total.................................. 216,980 178,379 370,012 310,630 313,340 1,389,341 ======== ======== ======== ======== ======== ========== HEATING DEGREE DAYS(2) Actual................................... 5,373 4,346 1,543 3,644 3,259 3,368 Percent of normal........................ 95% 100% 90% 94% 92% 94% SALES VOLUMES -- MMCF(3) Gas Sales Volumes Residential.............................. 15,660 10,802 15,117 16,245 19,562 77,386 Commercial............................... 5,948 4,611 6,442 11,599 7,196 35,796 Industrial............................... 365 1,931 -- 8,658 3,545 14,499 Agricultural............................. 1,474 -- -- -- 9,514 10,988 Public authority and other............... 1,190 1,314 847 287 2,237 5,875 -------- -------- -------- -------- -------- ---------- Total.................................. 24,637 18,658 22,406 36,789 42,054 144,544 Transportation Volumes..................... 8,917 25,063 8,029 20,355 7,225 69,589 -------- -------- -------- -------- -------- ---------- Total Throughput........................... 33,554 43,721 30,435 57,144 49,279 214,133 ======== ======== ======== ======== ======== ========== OPERATING REVENUES (000'S)(3).............. $154,718 $138,772 $188,092 $257,305 $198,639 $ 937,526 OTHER STATISTICS, AT YEAR END Miles of pipe............................ 6,454 3,794 7,951 7,637 13,321 39,157 Employees(5)............................. 271 245 457 461 332 1,766
See footnotes following these tables. 8 NATURAL GAS MARKETING AND OTHER NON-UTILITY OPERATIONS SALES AND STATISTICAL DATA
YEAR ENDED SEPTEMBER 30 ------------------------------------------------------- 2003 2002 2001 2000 1999 ---------- ---------- -------- -------- ------- CUSTOMERS, END OF YEAR Industrial(7)....................... 750 641 531 -- -- Municipal(7)........................ 206 101 68 -- -- Propane(6).......................... -- -- -- -- 39,539 ---------- ---------- -------- -------- ------- Total............................ 956 742 599 -- 39,539 ========== ========== ======== ======== ======= NATURAL GAS MARKETING SALES VOLUMES -- MMCF(3)(7)................. 294,785 273,692 98,869 -- -- PROPANE -- GALLONS (000'S)(6)......... -- -- -- 19,329 22,291 OPERATING REVENUES (000'S)(3) Natural gas marketing............... $1,668,493 $1,031,874 $447,096 $ 929 $ -- Other non-utility................... 21,630 24,705 59,436 95,376 53,416 Propane revenues(6)................. -- -- -- 22,550 22,944 ---------- ---------- -------- -------- ------- Total operating revenues......... $1,690,123 $1,056,579 $506,532 $118,855 $76,360 ========== ========== ======== ======== ======= Equity in earnings of Woodward Marketing L.L.C.(7)................. -- -- $ 8,062 $ 7,307 $ 7,156 ========== ========== ======== ======== ======= Employees, at year end................ 88 83 62 28 164
- --------------- Notes to preceding tables: (1) The operational and statistical information includes the operations of LGS since the July 1, 2001 acquisition date and the operations of MVG since the December 3, 2002 acquisition date. (2) A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on 30-year average National Weather Service data for selected locations. Degree day information for 2003, 2002 and 2001 is adjusted for service areas included in the Mid-States Division and the Kentucky Division which have weather normalized operations. Degree day information for 2003 is also adjusted for service areas included in the Mississippi Valley Gas Company Division which has weather normalized operations as well. Degree day information for 2000 and 1999 has not been adjusted for service areas with weather normalized operations as that information was not available. (3) Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts. (4) These tables present data for our six natural gas utility divisions. Their operations include the regulated local distribution companies located in their respective service areas. The operations of LGS are included in our Louisiana Division since the July 1, 2001 acquisition date, and the operations of MVG are included in our Mississippi Valley Gas Company Division since the December 3, 2002 acquisition date. (5) The number of utility employees excludes 504, 489, 480, 369 and 427 Atmos shared services employees and 88, 83, 62, 28 and 164 other segment employees in 2003, 2002, 2001, 2000 and 1999. (6) Prior to August 2000, propane revenues and expenses were fully consolidated. Subsequent to August 2000, the results of our propane operations are shown on the equity basis. (7) Through March 31, 2001 substantially all of our natural gas marketing revenues and expenses are shown on the equity basis. Beginning April 1, 2001 natural gas marketing revenues and expenses are fully consolidated. 9 REGULATION Each of our utility divisions is regulated by various state or local public utility authorities. We are also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of our gas distribution facilities. Our distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time we receive inquiries regarding various environmental matters. We believe that our 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 would have a material adverse effect on us or our operations. All of our environmental claims have arisen out of manufactured gas plant sites in Tennessee, Iowa and Missouri and mercury contamination sites in Kansas. These claims are more fully described in Note 13 to the consolidated financial statements. RATEMAKING ACTIVITY OVERVIEW The method of determining regulated rates varies among the states in which our natural gas utility divisions operate. The regulators have the responsibility of ensuring that utilities under their jurisdiction operate in the best interests of customers while providing utility companies the opportunity to earn a reasonable return on investment. In a general rate case, the applicable regulatory authority, which is typically the state public utility commission, establishes rates which allow a utility company an opportunity to collect revenue from customers to recover the cost of providing utility service. Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas cost through purchased gas adjustment mechanisms. Purchased gas adjustment mechanisms provide gas utility companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of the utility's non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of expense, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility's other costs, (ii) represents a large component of the utility's cost of service and (iii) is generally outside the control of the gas utility. There is no margin generated through purchased gas adjustments, but they do provide a dollar-for-dollar offset to increases or decreases in utility gas costs. Although substantially all of our utility sales to our customers fluctuate with the cost of gas that we purchase, utility gross profit (which is defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas due to the purchased gas adjustment mechanism. Additionally, certain jurisdictions have introduced performance-based ratemaking adjustments to provide incentives to natural gas utilities to minimize purchased gas costs through improved storage management and use of financial hedges to lock in gas costs. Under the performance-based ratemaking adjustment, purchased gas costs savings are shared between the utility and the customer. 10 The following table summarizes certain information regarding our ratemaking jurisdictions:
RATE BASE ALLOWED DIVISION JURISDICTION (THOUSANDS)(1) RETURN ON EQUITY(1) - -------- ------------ -------------- ------------------- Colorado-Kansas......................... Colorado (2) 11.25% - 12.50% Kansas (2) (2) Kentucky................................ Kentucky (2) (2) Louisiana............................... Louisiana $246,617 10.50% - 11.50% Mid-States.............................. Georgia 38,451 11.50% Illinois 24,564 11.56% Iowa 5,000 11.00% Missouri (2) 12.15% Tennessee (2) (2) Virginia 25,000 11.00% Texas................................... Amarillo 36,844 12.00% West Texas (2) (2) Mississippi Valley Gas Company.......... Mississippi 175,206 10.20%
- --------------- (1) The rate base and authorized rate of return presented in this table are the rate base and rate of return from the last base rate case for each jurisdiction. These rate bases and rates of return are not indicative of current or future rate bases or rates of return. (2) A rate base or rate of return were not included in the respective state commission's final decision. RECENT RATEMAKING ACTIVITY Approximately 97 percent, 96 percent and 97 percent of our utility revenues in the fiscal years ended September 30, 2003, 2002 and 2001 were derived from sales at rates set by or subject to approval by local or state authorities. Net annual rate increases totaling $18.6 million and $6.4 million became effective in fiscal 2003 and fiscal 2001. There were no rate increases which became effective in fiscal 2002. 11 The following table and discussion summarizes the major rate requests that we have made and other ratemaking developments during the most recent five fiscal years and the action taken on such requests.
AMOUNT EFFECTIVE AMOUNT RECEIVED JURISDICTION DATE REQUESTED (REDUCED) - ------------ --------- --------- ---------- (IN THOUSANDS) Kansas........................................ (a) $ 7,400 (a) Colorado...................................... 05/04/01 4,200 $ 2,750 Kentucky...................................... 12/21/99 14,127 9,900 Louisiana: Trans La System............................. 11/01/02 --(b) 364(c) LGS System.................................. 11/01/02 --(b) 11,890(d) Tennessee..................................... 04/1/99 --(b) (e) Georgia....................................... 05/1/99 --(b) (e) Iowa.......................................... 03/05/01 --(b) (326) Illinois...................................... 10/23/00 3,100 1,367 Virginia...................................... 04/01/01 2,100 (534) Texas: West Texas System........................... 12/01/00 9,827 3,011 Amarillo System............................. 1/01/00 4,354 2,200 Amarillo System............................. 09/01/03 5,118 2,825 West Texas System........................... (f) 7,700 (f) Lubbock System.............................. (g) 3,000 (g) Mississippi................................... (h) (b) (h)
- --------------- (a) The Kansas Corporation Commission is scheduled to conduct a public hearing on this case in December 2003. (b) No requested amounts are presented because either (1) we file periodic requests for rate adjustments based upon our actual expenses in accordance with the respective state commission's rules or (2) the commission's ruling was not the result of a rate filing initiated by us. See further information in the following discussion. (c) In 2002, we submitted our 2001 rate stabilization filing and received tariff revisions which resulted in an increase in annual revenues of $0.5 million during the first 24-month period. Subsequent to the first 24-month period, adjusted rates will provide an increase in annual revenues of $0.4 million. (d) In 2002, we submitted our 2001 rate stabilization filing and received tariff revisions which resulted in an increase in annual revenues of $15.3 million during the first 24-month period. Subsequent to the first 24-month period, adjusted rates will provide an increase in annual revenues of $11.9 million. (e) Effective April 1, 1999, the Tennessee Regulatory Authority approved a performance-based ratemaking mechanism related to gas procurement and gas transportation activities. Effective May 1, 2002, the Georgia Public Service Commission renewed our performance-based ratemaking program. The impacts of these rulings are described in greater detail below. (f) This case was filed in September 2003 and is pending review by the affected cities. (g) This case was filed in October 2003 and is pending review by the City of Lubbock. (h) In October 2003, the Mississippi Public Service Commission issued a final ruling which denied our May 2003 request for a rate adjustment. We are currently considering our response to the Commission's ruling. 12 Atmos Energy Colorado-Kansas Division. In May 2003, the Colorado-Kansas Division filed a rate case with the Kansas Corporation Commission for approximately $7.4 million in additional annual revenues. The Kansas Corporation Commission is scheduled to conduct a public hearing on the case in December 2003. Additionally, in May 2003, we received approval for WNA in Kansas which will be effective October through May of each year beginning with the 2003-2004 winter heating season. In November 2000, the Colorado-Kansas Division filed a rate case with the Colorado Public Utilities Commission for approximately $4.2 million in additional annual revenues. In May 2001, we received an increase in annual revenues of approximately $2.8 million from the Colorado Public Utilities Commission. The new rates went into effect on May 4, 2001. Atmos Energy Kentucky Division. On March 25, 2002, the Kentucky Commission issued an Order approving a four year extension, effective April 1, 2002, of the Performance-based Ratemaking mechanism related to gas procurement and gas transportation activities filed by the Kentucky Division. The Performance-based Ratemaking mechanism is incorporated into the Kentucky Division's gas cost adjustment clause and provides for the sharing of purchased gas cost savings between our customers and us. We recognized other income of $1.3 million, $1.1 million and $0.2 million under the Kentucky Performance-based-ratemaking mechanism in fiscal years 2003, 2002 and 2001. In May 1999, the Kentucky Division requested from the Kentucky Public Service Commission a $14.1 million increase in revenues, a weather normalization adjustment and changes in rate design to shift a portion of revenues from commodity charges to fixed rates. In December 1999, the Kentucky Commission granted an increase in annual revenues of approximately $9.9 million. The new rates were effective for services rendered on or after December 21, 1999. In addition, the Kentucky Commission approved a five-year pilot program for weather normalization beginning in November 2000. Atmos Energy Louisiana Division. In October 2002, Atmos received written notification from the Executive Secretary of the Louisiana Public Service Commission that he was asserting that a monthly facilities fee of approximately $0.6 million charged since July 2001 to Atmos by Trans Louisiana Gas Pipeline, Inc., a wholly-owned subsidiary of Atmos, pursuant to a contract between the parties, was excessive. The Executive Secretary asserted that all monthly facilities fees in excess of approximately $0.1 million from July 2001 should be refunded to ratepayers with interest. In September 2003, an agreement was reached with the commission staff to allow Atmos to charge a facilities fee of approximately $0.5 million per month (subject to future escalation) beginning November 1, 2003 for a period of 14 years. No retroactive adjustments will be required under this agreement. On October 8, 2003, the commission unanimously voted in open session to approve the agreement. In January and February 2002, our Louisiana Division submitted its 2001 Rate Stabilization filings to the Louisiana Public Service Commission for the two gas systems we operate in Louisiana. The Louisiana Public Service Commission audited the filings and found our earnings to be deficient and that rate adjustments were appropriate. Approved tariff revisions, which became effective November 1, 2002, will result in $15.3 million in additional revenues per year for our LGS System and $0.5 million for our Trans La System during the first 24-month period. Subsequent to the first 24-month period, adjusted rates will provide total annual revenue increases of $11.9 million for our LGS System and $0.4 million for our Trans La System. As a result of the actions taken by the Louisiana Public Service Commission, we have decreased the overall weather impact to our revenues in Louisiana. In 2001, in connection with its review of our acquisition of Louisiana Gas Service, the Louisiana Public Service Commission approved a rate structure that requires us to share with the customers of Louisiana Gas Service cost savings that resulted from the acquisition. The shared cost savings will be the difference between operation and maintenance expense in any future year and the 1998 normalized expense for Louisiana Gas Service, indexed for inflation, annual changes in labor costs and customer growth. Beginning January 1, 2002, customers have been assured they will receive annual savings, which will be indexed for inflation, annual changes in labor costs and customer growth. The sharing mechanism will remain in place for 20 years subject to established modification procedures. 13 In June 1999, our Trans La operations were involved in a rate investigation before the Louisiana Public Service Commission, including the redesign of rates to mitigate the effects of warm winter weather. A decision was rendered by the Louisiana Commission in October 1999 that increased service charges associated with customer service calls and increased the monthly customer charges from $6 to $9, both effective November 1, 1999. While these changes are revenue neutral, they have mitigated the impact of warmer than normal winter weather on earnings. The decision also included a three-year rate stabilization clause which will allow the Trans La operations of our Louisiana Division's rates to be adjusted annually to allow us to earn a return on equity within certain ranges that will be monitored on an annual basis. Atmos Energy Mid-States Division. Effective April 1, 1999, the Tennessee Regulatory Authority approved the Mid-States Division's request to continue its Performance-based Ratemaking mechanism related to gas procurement and gas transportation activities. The Tennessee Regulatory Authority revised the mechanism from the original two-year experimental period, by increasing the cap for incentive gains and/or losses to $1.25 million per year. Under this agreement, the mechanism has no expiration date and can be amended or cancelled by either the Mid-States Division or the Tennessee Regulatory Authority according to the provisions of the agreement. Similar to Tennessee, the Georgia Public Service Commission renewed our Performance-based Ratemaking program for an additional three years effective May 1, 2002. The gas purchase and capacity release mechanisms of the Performance-based Ratemaking mechanism are designed to provide us incentives to find innovative methods to lower gas costs to our customers. We recognized other income of $0.5 million, $0.4 million and $1.0 million in fiscal years 2003, 2002 and 2001 attributable to the Georgia and Tennessee Performance-based Ratemaking mechanisms. In March 2001, the Mid-States Division and the Iowa Consumer Advocate Division of the Department of Justice reached an agreement for an annual rate reduction of $0.3 million relating to our Iowa operations. The rate reduction was effective in March 2001. Also in 2001, the Mid-States Division filed requests for accounting orders related to uncollectible delinquencies in three states. As a result, we were able to defer $1.5 million as a regulatory asset. In February 2000, the Mid-States Division filed a rate case in Illinois with the Illinois Commerce Commission requesting an increase in annual revenues of approximately $3.1 million. After review by the Illinois Commerce Commission, we received an increase in annual revenues of approximately $1.4 million. The new rates went into effect on October 23, 2000 and are collected primarily through an increase in monthly customer charges. In March 2000, the Mid-States Division filed a rate case in Virginia with the State Corporation Commission of the Commonwealth of Virginia requesting an increase in annual revenues of approximately $2.3 million. The State Corporation Commission of Virginia reviewed the filing to determine if it met the appropriate rules and regulations. In July 2000, we re-filed the case requesting an increase in revenues of approximately $2.1 million. The Commission accepted the revised filing. In April 2001, the Mid-States Division agreed to an annual rate reduction of $0.5 million effective beginning with the April 2001 billing cycle. Atmos Energy Texas Division. In June 2003, the Texas Division filed a rate case in Amarillo, Texas, requesting a $5.1 million increase in annual revenues. In August 2003, the City of Amarillo, Texas approved an annual increase of approximately $2.8 million, which was effective for bills rendered on or after September 1, 2003. The increase was primarily comprised of an increase in monthly customer charges. The agreement with Amarillo also provided for changes in the rate structure to recover the cost of uncollectible accounts, adjustments to base rates to compensate for declining gas use per customer and provided WNA, which will be effective October through May, beginning in fiscal 2004. In September 2003, the Texas Division filed a rate case in its West Texas System to request a $7.7 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. The filing is pending review by the affected cities. In October 2003, the Texas Division filed a rate case in Lubbock to request a $3.0 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. The filing is pending review by the City of Lubbock. 14 In August 1999, the Texas Division filed rate cases in its West Texas System cities and Amarillo, Texas, requesting rate increases of approximately $9.8 million and $4.4 million. The Texas Division received an increase in annual revenues of approximately $2.1 million in base rates plus an increase of $0.1 million in service charges in Amarillo, Texas, effective for bills rendered on or after January 1, 2000. The agreement with Amarillo also provided for changes in the rate structure to reduce the impact of warmer than normal weather and to improve the recovery of the actual cost of service calls. The Texas Division's request for its West Texas System cities was initially denied, and in March 2000 this decision was appealed to the Railroad Commission of Texas (Railroad Commission). Subsequently, 59 cities ratified a non-binding Settlement Agreement which capped the rate increase at $3.0 million and entitled the ratifying cities to accept a rate increase below $3.0 million in the event the Railroad Commission adopted a lesser increase for the non-ratifying cities. The remaining eight cities declined to participate in the settlement and a hearing with the Railroad Commission was held in August 2000. In December 2000, the Railroad Commission approved a settlement which increased annual revenues by approximately $3.0 million that covered all 67 cities served by the West Texas System effective December 1, 2000. In addition, the Railroad Commission approved a new rate design providing more protection from warmer than normal weather for our West Texas System. Mississippi Valley Gas Company Division. The Mississippi Public Service Commission requires that we file for rate adjustments based on our expenses every six months. Typically, rate adjustments are filed in May and November of each year and the rate becomes effective in June and December. In October 2003, the Mississippi Public Commission issued a final order which denied our May 2003 request for a rate adjustment. We are currently considering our response to the Commission's ruling. Additionally, we filed our second semi-annual filing on November 5, 2003. COMPETITION Our utility operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas. However, we do compete with other natural gas suppliers and suppliers of alternative fuels for sales to industrial and agricultural customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Competition for residential and commercial customers is increasing. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential, commercial and industrial markets. In addition, our Natural Gas Marketing segment competes with other natural gas brokers in obtaining natural gas supplies for customers. EMPLOYEES At September 30, 2003, we had 2,905 employees, consisting of 2,817 employees in our utility segment and 88 employees in our other segments. See "Operating Statistics -- Utility Sales and Statistical Data by Division" for the number of employees by division. OTHER INFORMATION We post our SEC filings on our website at www.atmosenergy.com. CORPORATE GOVERNANCE In accordance with relevant provisions of the Sarbanes-Oxley Act of 2002, related releases of the Securities and Exchange Commission as well as corporate governance listing standards of the New York Stock Exchange, the Board of Directors of the Company has recently adopted the Company's Corporate Governance Guidelines and revised the Company's Code of Conduct, which is now applicable to all directors, officers and employees of the Company. In addition, the Board of Directors has revised the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on the Corporate Governance page of the Company's website. 15 ITEM 2. PROPERTIES DISTRIBUTION, TRANSMISSION AND RELATED ASSETS Our utility segment owns an aggregate of 45,267 miles of underground distribution and transmission mains throughout our gas distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Our utility segment also holds franchises granted by the incorporated cities and towns that we serve. At September 30, 2003, we held 651 franchises having terms generally ranging from five to 25 years. We believe that each of our franchises will be renewed. STORAGE ASSETS Our utility and other non-utility segments own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes key information regarding our underground gas storage facilities:
MAXIMUM DAILY USABLE CAPACITY CUSHION GAS TOTAL CAPACITY DELIVERY CAPABILITY FACILITY LOCATION (MCF) (MCF)(1) (MCF) (MCF) - -------- -------- --------------- ----------- -------------- ------------------- Utility Segment St. Charles................... Hopkins County, Ky 3,560,600 3,470,000 7,030,600 44,600 Goodwin....................... Monroe County, Ms 1,550,000 300,000 1,850,000 20,000 Amory......................... Monroe County, Ms 1,460,000 1,000,000 2,460,000 25,000 Bon Harbor.................... Daviess County, Ky 778,600 1,300,000 2,078,600 24,000 Hickory....................... Daviess County, Ky 451,600 850,000 1,301,600 24,000 Columbus LNG Plant............ Muscogee County, Ga 450,000 50,000 500,000 30,000 Grandview..................... Daviess County, Ky 305,400 350,000 655,400 4,500 Kirkwood...................... Hopkins County, Ky 221,900 400,000 621,900 12,000 ---------- ---------- ---------- ------- Total Utility Segment....... 8,778,100 7,720,000 16,498,100 184,100 Other Non-Utility Segment Liberty North................. Montgomery County, Ks 2,800,000 2,000,000 4,800,000 40,000 East Diamond.................. Hopkins County, Ky 2,160,000 1,640,000 3,800,000 40,000 Barnsley...................... Hopkins County, Ky 1,278,900 1,600,000 2,878,900 30,000 Liberty South................. Montgomery County, Ks 439,000 300,000 739,000 5,000 Napoleonville(2).............. Assumption Parish, La 438,583 300,973 739,556 56,000 Buffalo....................... Wilson County, Ks 200,000 180,000 380,000 5,000 Fredonia...................... Wilson County, Ks 200,000 160,000 360,000 5,000 Crofton....................... Christian County, Ky 54,000 55,000 109,000 1,000 ---------- ---------- ---------- ------- Total Other Non-Utility Segment................... 7,570,483 6,235,973 13,806,456 182,000 ---------- ---------- ---------- ------- TOTAL......................... 16,348,583 13,955,973 30,304,556 366,100 ========== ========== ========== =======
- --------------- (1) Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. (2) We own 25 percent of this facility and Acadian Gas Pipeline System owns the remaining 75 percent of this facility. Acadian Gas Pipeline System operates this facility. 16 Additionally, we contract for storage service in underground storage facilities on many of the interstate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity.
MAXIMUM MAXIMUM DAILY STORAGE WITHDRAWAL QUANTITY QUANTITY DIVISION/COMPANY CONTRACTOR (MMBTU) (MMBTU)(1) - ---------------- ---------- ---------- ---------- Utility Segment Colorado-Kansas Division....... Southern Star Central Pipeline 2,699,598 44,217 Tenaska Marketing Ventures 500,000 7,000 Public Service Company of Colorado 434,997 15,000 Colorado Interstate Gas Company 422,142 12,985 Kinder Morgan, Inc. 90,000 2,000 Centerpoint Energy Gas Transmission 28,500 950 Kentucky Division.............. Texas Gas Transmission 3,841,150 41,060 Tennessee Gas Pipeline Company 1,313,538 22,698 Louisiana Division............. Gulf South 1,941,280 97,064 Louisiana Intrastate Gas Company 600,000 60,000 Sonat 4,771 102 Tennessee Gas Pipeline Company 4,466 91 Mid-States Division............ Atmos Energy Marketing 2,173,543 19,634 Southern Natural Gas Company 1,423,374 28,741 Texas Eastern Transmission Company 1,253,969 19,636 Panhandle Eastern Pipeline 972,462 15,241 Tennessee Gas Pipeline Company 848,278 20,266 Gallagher Drilling Company(2) 640,000 5,000 ANR Pipeline Company 633,034 12,661 Dominion 609,008 8,136 Transco. 521,580 12,212 Virginia Gas 480,000 33,000 Egyptian Gas Storage Corp. 400,000 5,000 East Tennessee 339,900 36,547 Natural Gas Pipeline Company 312,750 5,580 Texas Gas Transmission 239,576 5,108 CMS Trunkline Gas Company 220,455 2,940 MRT Energy Marketing 137,493 2,395 Texas Division................. ONEOK Texas Gas Storage LLP 1,000,000 50,000
17
MAXIMUM MAXIMUM DAILY STORAGE WITHDRAWAL QUANTITY QUANTITY DIVISION/COMPANY CONTRACTOR (MMBTU) (MMBTU)(1) - ---------------- ---------- ---------- ---------- Mississippi Valley Gas Company Division..................... Gulf South 1,237,500 61,875 Southern Natural Gas 1,049,436 21,191 Texas Gas Transmission 1,023,039 45,139 Texas Eastern 518,220 8,637 Hattiesburg Gas Storage Company 400,000 40,000 Trunkline Gas Company 24,840 331 Tennessee Gas Pipeline Company 3,394 113 ---------- ------- Total Utility Segment.......... 28,342,293 762,550 Natural Gas Marketing Segment...................... Texas Gas Transmission 1,700,000 10,000 Atmos Energy Marketing, LLC.... Gulf South Pipeline Company(3) 1,250,000 100,000 TCO 1,197,000 25,000 East Tennessee 268,037 11,000 ---------- ------- Total Natural Gas Marketing Segment...................... 4,415,037 146,000 Other Non-utility Segment Trans Louisiana Gas Pipeline, Inc.......................... Bridgeline Gas Distribution LLC 300,000 30,000 ---------- ------- Total Other Non-Utility Segment...................... 300,000 30,000 ---------- ------- TOTAL CONTRACTED STORAGE CAPACITY..................... 33,057,330 938,550 ========== =======
- --------------- (1) Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season. (2) We contract for storage service in two underground storage facilities, Wiseman and Ellis, from this company. (3) Included in this amount is a contract signed in July 2003 for 1 Bcf in a salt dome storage facility located in Louisiana with a total capacity of 5 Bcf. This facility provides increased flexibility because it allows us to inject and withdraw gas on a daily and monthly basis. The contract commenced in November 2003 and will last for 5 winter heating seasons. OTHER FACILITIES Our utility segment owns and operates one propane peak shaving plant with a total capacity of approximately 180,000 gallons that can produce an equivalent of approximately 3,300 Mcf daily. OFFICES Our administrative offices are consolidated in Dallas, Texas under one lease. We also maintain field offices throughout our distribution system, the majority of which are located in leased facilities. Our non-utility operations are headquartered in Houston, Texas, with offices in Houston and other locations, primarily in leased facilities. 18 ITEM 3. LEGAL PROCEEDINGS See Note 13 to the consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of fiscal 2003. 19 EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth certain information as of September 30, 2003, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.
YEARS OF NAME AGE SERVICE OFFICE CURRENTLY HELD - ---- --- -------- --------------------- Robert W. Best................. 56 6 Chairman, President and Chief Executive Officer John P. Reddy.................. 50 5 Senior Vice President and Chief Financial Officer R. Earl Fischer................ 64 41 Senior Vice President, Utility Operations JD Woodward III................ 53 2 Senior Vice President, Non-Utility Operations Louis P. Gregory............... 48 3 Senior Vice President and General Counsel Wynn D. McGregor............... 50 15 Vice President, Human Resources
Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997. He previously served as Senior Vice President -- Regulated Businesses of Consolidated Natural Gas Company (January 1996-March 1997) and was responsible for its transmission and distribution companies. John P. Reddy was named Senior Vice President and Chief Financial Officer in September 2000. From April 2000 to September 2000, he was Senior Vice President, Chief Financial Officer and Treasurer. Mr. Reddy previously served the Company as Vice President, Corporate Development and Treasurer from December 1998 to March 2000. He joined the Company in August 1998 from Pacific Enterprises, a Los Angeles, California based utility holding company whose principal subsidiary was Southern California Gas Co. where he was Vice President of Planning and Advisory Services responsible for corporate development and merger and acquisition activities. Mr. Reddy was with Pacific Enterprises from 1980 to 1998 in various management and financial positions. R. Earl Fischer was named Senior Vice President, Utility Operations in May 2000. He previously served the Company as President of the Texas Division from January 1999 to April 2000 and as President of the Kentucky Division from February 1989 to December 1998. JD Woodward was named Senior Vice President, Non-Utility Operations in April 2001. Prior to joining the Company, Mr. Woodward was President of Woodward Marketing, L.L.C. from January 1995 to March 2001. Louis P. Gregory joined the Company as Senior Vice President and General Counsel in September 2000. Prior to joining the Company, he practiced law from April 1999 to August 2000 with the law firm of McManemin & Smith. Prior to that, he served as a consultant and independent contractor from August 1996 to December 1998 for Nomas Corp. (formerly known as Lomas Mortgage USA, Inc.) and Siena Holdings, Inc. (formerly known as Lomas Financial Corporation). Wynn D. McGregor was named Vice President, Human Resources in January 1994. He previously served the Company as Director of Human Resources from February 1991 to December 1993 and as Manager, Compensation and Employment from December 1987 to January 1991. 20 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our 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 our common stock for fiscal 2003 and 2002 are listed below. The high and low prices listed are the closing NYSE quotes for shares of our common stock:
2003 2002 --------------------------- --------------------------- DIVIDENDS DIVIDENDS HIGH LOW PAID HIGH LOW PAID ------ ------ --------- ------ ------ --------- QUARTER ENDED: December 31.................. $23.63 $20.70 $ .30 $22.10 $19.46 $.295 March 31..................... 24.20 20.95 .30 24.20 20.26 .295 June 30...................... 25.45 21.43 .30 24.46 21.25 .295 September 30................. 25.07 23.20 .30 22.75 18.37 .295 ----- ----- $1.20 $1.18 ===== =====
Dividend payments are subject to restriction under the terms of our First Mortgage Bond agreements. See Note 6 to the consolidated financial statements. The number of record holders of our common stock on September 30, 2003 was 28,510. The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2003.
NUMBER OF SECURITIES NUMBER OF WEIGHTED- REMAINING AVAILABLE SECURITIES TO BE AVERAGE EXERCISE FOR FUTURE ISSUANCE ISSUED UPON PRICE OF UNDER EQUITY EXERCISE OF OUTSTANDING COMPENSATION PLANS OUTSTANDING OPTIONS, (EXCLUDING OPTIONS, WARRANTS WARRANTS AND SECURITIES REFLECTED AND RIGHTS RIGHTS IN COLUMN(A)) ----------------- ---------------- -------------------- (A) (B) (C) EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS: Long-Term Incentive Plan........... 1,827,310 $21.91 1,923,464 Long-Term Stock Plan for the Mid- States Division................. 6,300 $15.62 168,550 --------- ------ --------- TOTAL EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS....... 1,833,610 $21.89 2,092,014 EQUITY COMPENSATION PLANS NOT APPROVED BY SECURITY HOLDERS....... -- -- -- --------- ------ --------- Total................................ 1,833,610 $21.89 2,092,014 ========= ====== =========
21 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein.
YEAR ENDED SEPTEMBER 30 -------------------------------------------------------------- 2003(1) 2002 2001(2) 2000(3) 1999 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS) RESULTS OF OPERATIONS Operating revenues......................... $2,799,916 $1,650,964 $1,725,481 $ 850,152 $ 690,196 Gross profit............................... 534,976 431,140 375,208 325,706 299,794 Operating expenses......................... 347,136 275,809 244,927 240,390 245,555 Operating income........................... 187,840 155,331 130,281 85,316 54,239 Other income (expense)..................... 2,191 (1,321) 6,188 14,744 10,123 Interest charges........................... 63,660 59,174 47,011 43,823 37,063 Income before income taxes and cumulative effect of accounting change.............. 126,371 94,836 89,458 56,237 27,299 Cumulative effect of accounting change, net income tax benefit....................... (7,773) -- -- -- -- Income tax expense......................... 46,910 35,180 33,368 20,319 9,555 Net income................................. 71,688 59,656 56,090 35,918 17,744 Weighted average diluted shares outstanding.............................. 46,496 41,250 38,247 31,594 30,819 Diluted net income per share............... $ 1.54 $ 1.45 $ 1.47 $ 1.14 $ .58 Cash flows from operations................. 49,541 297,395 82,995 54,196 84,698 Cash dividends paid per share.............. $ 1.20 $ 1.18 $ 1.16 $ 1.14 $ 1.10 Total utility throughput (MMcf)............ 247,965 208,541 217,774 197,564 195,587 Total natural gas marketing sales volumes (MMcf)................................... 225,961 204,027 55,469 -- -- FINANCIAL CONDITION Net property, plant and equipment.......... $1,515,989 $1,300,320 $1,335,398 $ 982,346 $ 965,782 Working capital............................ 22,282 (133,116) (86,778) (181,890) (151,622) Total assets............................... 2,518,508 1,981,385 2,036,180 1,348,758 1,230,537 Short-term debt, inclusive of current maturities of long-term debt............. 127,940 167,771 221,942 267,613 186,152 Total capitalization Shareholders' equity..................... 857,517 573,235 583,864 392,466 377,663 Long-term debt (excluding current maturities)............................ 863,918 670,463 692,399 363,198 377,483 ---------- ---------- ---------- ---------- ---------- 1,721,435 1,243,698 1,276,263 755,664 755,146 Capital expenditures....................... 159,439 132,252 113,109 75,557 110,353 FINANCIAL RATIOS Capitalization ratio(4).................... 46.4% 40.6% 39.0% 38.4% 40.1% Return on average shareholders' equity(5)................................ 9.9% 9.9% 10.4% 9.3% 4.7%
- --------------- (1) Financial results for fiscal 2003 include the results of MVG from December 3, 2002, the date of acquisition. (2) Financial results for fiscal 2001 include the results of Louisiana Gas Service Company from July 1, 2001 and Woodward Marketing L.L.C. from April 1, 2001, the date of each acquisition, and the equity earnings from our 45 percent investment in Woodward Marketing L.L.C. for the period October 1, 2001 through March 31, 2002. (3) Financial results for 2000 include a $5.8 million pre-tax gain on the contribution of our propane assets to U.S. Propane, L.P. (4) The capitalization ratio is calculated by dividing shareholders' equity by the sum of total capitalization, current maturities of long-term debt and short-term debt. (5) The return on average shareholders' equity is calculated by dividing current year net income by the average of shareholders' equity for the previous five quarters. 22 The following table presents a condensed income statement by segment for the year ended September 30, 2003.
FOR THE YEAR ENDED SEPTEMBER 30, 2003 -------------------------------------------------------------------- NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED ---------- ----------- ----------- ------------ ------------ (IN THOUSANDS) Operating revenues from external parties......................... $1,552,857 $1,234,447 $12,612 $ -- $2,799,916 Intersegment revenues............. 1,225 434,046 9,018 (444,289) -- ---------- ---------- ------- --------- ---------- 1,554,082 1,668,493 21,630 (444,289) 2,799,916 Purchased gas cost................ 1,062,679 1,644,328 1,540 (443,607) 2,264,940 ---------- ---------- ------- --------- ---------- Gross profit................. 491,403 24,165 20,090 (682) 534,976 Depreciation and amortization..... 83,849 1,261 1,891 -- 87,001 Other operating expenses.......... 246,420 9,335 5,062 (682) 260,135 ---------- ---------- ------- --------- ---------- Operating income.................. 161,134 13,569 13,137 -- 187,840 Miscellaneous income (expense).... (218) 1,855 5,004 (4,450) 2,191 Interest charges.................. 63,226 2,864 2,020 (4,450) 63,660 ---------- ---------- ------- --------- ---------- Income before income taxes and cumulative effect of accounting change.......................... 97,690 12,560 16,121 -- 126,371 Income tax expense................ 35,553 5,757 5,600 -- 46,910 ---------- ---------- ------- --------- ---------- Income before cumulative effect of accounting change............... 62,137 6,803 10,521 -- 79,461 Cumulative effect of accounting change, net of income tax benefit......................... -- (7,773) -- -- (7,773) ---------- ---------- ------- --------- ---------- Net income (loss).......... $ 62,137 $ (970) $10,521 $ -- $ 71,688 ========== ========== ======= ========= ==========
23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION This section provides management's discussion of the financial condition, cash flows and results of operations of Atmos Energy Corporation with specific information on results of operations and liquidity and capital resources. It includes management's interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with the Company's consolidated financial statements and notes thereto. CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 The statements contained in this Annual Report on Form 10-K may contain "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of the Company's documents or oral presentations, the words "anticipate," "expect," "estimate," "plans," "believes," "objective," "forecast," "goal" or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to the Company's strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions such as warmer than normal weather in the Company's utility service territories or colder than normal weather which could adversely affect our natural gas marketing activities; regulatory trends and decisions, including deregulation initiatives and the impact of rate proceedings before various state regulatory commissions; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; national, regional and local economic conditions, limited access to financial markets; inflation and increased gas costs, including their effect on commodity prices for natural gas; increased competition; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise. FACTORS THAT MAY AFFECT OUR FUTURE PERFORMANCE Our performance in the future will primarily depend on the results of our utility and natural gas marketing operations. Several factors exist that could influence Atmos' future financial performance, some of which are described below. They should be considered in connection with evaluating forward-looking statements contained in this report or otherwise made by or on behalf of us since these factors could cause actual results and conditions to differ materially from those projected in these forward-looking statements. OUR OPERATIONS ARE WEATHER SENSITIVE. Weather is one of the most significant factors influencing our performance. Our natural gas utility sales volumes and related revenues are correlated with heating requirements that result from cold winter weather. Our agricultural sales volumes are associated with the rainfall levels during the growing season in our west Texas irrigation market. However, weather normalized rates in effect in several of our jurisdictions should mitigate the adverse effects of warmer than normal weather on our utility operating results. Finally, sustained cold weather could adversely affect our natural gas marketing operations as we may be required to purchase gas at spot rates in a rising market to obtain sufficient volumes to fulfill some customer contracts. 24 OUR OPERATIONS ARE SUBJECT TO REGULATION WHICH CAN DIRECTLY IMPACT OUR OPERATIONS. Our natural gas utility business is subject to various regulated returns on its rate base in each of the 12 states in which we operate. We monitor the allowed rates of return, our effectiveness in earning such rates and initiate rate proceedings or operating changes as needed. In addition, in the normal course of the regulatory environment, assets are placed in service and historical test periods are established before rate cases can be filed. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we must temporarily suffer the negative financial effects of having placed assets in service without the benefit of rate relief, which is commonly referred to as "regulatory lag". In addition, our debt and equity financing programs are also subject to approval by regulatory bodies in certain states, which could limit our ability to take advantage of favorable short-term market conditions. Our business could also be affected by deregulation initiatives, including the development of unbundling initiatives in the natural gas industry. Unbundling is the separation of the provision and pricing of local distribution gas services into discrete components. It typically focuses on the separation of the distribution and gas supply components and the resulting opening of the regulated components of sales services to alternative unregulated suppliers of those services. Because of our enhanced technology and distribution system infrastructures, we believe that we are now positively positioned as unbundling evolves. Consequently, we expect there would be no significant adverse effect on our business should unbundling or further deregulation of the natural gas distribution service business occur. Finally, contractual limitations could adversely affect our ability to withdraw gas from storage, which could cause us to purchase gas at spot prices in a rising market to obtain sufficient volumes to fulfill customer contracts. We seek to minimize this risk by increasing our storage capacity and enhancing the flexibility of our natural gas marketing contracts. OUR OPERATIONS ARE EXPOSED TO MARKET RISKS THAT ARE BEYOND OUR CONTROL, WHICH COULD RESULT IN FINANCIAL LOSSES. Our risk management operations are subject to market risks beyond our control including market liquidity, commodity price volatility and counterparty creditworthiness. Market liquidity is affected by the number of trading partners in the market. As a result of the recent severe downturn in the natural gas marketing industry, the number of trading partners has been reduced, which could adversely impact the market liquidity for this industry and adversely affect our natural gas marketing operations. Further, although we maintain a risk management control policy, we may not be able to completely offset the price risk associated with volatile gas prices or the risk in our gas trading activities which could lead to financial losses. Physical trading also introduces price risk on any net open positions at the end of each trading day, as well as a risk of loss resulting from intra-day fluctuations of gas prices and the potential for daily price movements between the time natural gas is purchased or sold for future delivery and the time the related purchase or sale is hedged. Although we manage our business to maintain no open positions, at times, limited net open positions related to our physical storage may occur on a short term basis. Net open positions may result in an adverse impact on our financial condition or results of operations if market prices react in an unfavorable manner. Our utility segment uses a combination of storage and financial hedges to protect against volatility in gas prices and to help moderate the effects of higher customer accounts receivable caused by potentially higher gas prices. Our natural gas marketing segment manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of a variety of financial derivatives. We could realize financial losses on these activities as a result of volatility in the market value of the underlying commodities or if a counterparty fails to perform under a contract. Finally, the use of financial instruments to conduct our hedging and market risk activities subjects us to counterparty risk. Adverse changes in the creditworthiness of our counterparties could limit the level of 25 trading activities with these parties and increase the risk that these parties may not perform under a contract. We believe this risk is mitigated due to the large number of counterparties used in our risk management activities. NATIONAL, REGIONAL AND LOCAL ECONOMIC CONDITIONS HAVE A DIRECT IMPACT ON OUR OPERATIONS. Our operations will always be affected by the conditions and overall strength of the national, regional and local economies, including interest rates, changes in the capital markets and increases in the costs of our primary commodity, natural gas. These factors impact the amount of residential, industrial and commercial growth in our service territories. Additionally, these factors could adversely impact our customer collections. Further, AEM's operations are concentrated in the natural gas industry, and its customers and suppliers may be subject to economic risks affecting that industry. During 2003, AEM's credit risk increased due to higher natural gas prices as compared with the prior year. However, we believe this risk is mitigated because a larger percentage of our natural gas marketing business in the current year is with municipal customers (who typically are more creditworthy) as compared with the prior year. THE EXECUTION OF OUR BUSINESS PLAN COULD BE AFFECTED BY AN INABILITY TO ACCESS FINANCIAL MARKETS. We rely upon access to both short term and longer term capital markets as a source of liquidity to satisfy our liquidity requirements. Although we believe we will maintain sufficient access to these financial markets, adverse changes in the economy, the overall health of the industries in which we operate and changes to our credit ratings could limit access to these markets and restrict the execution of our business plan. INFLATION AND INCREASED GAS COSTS COULD ADVERSELY IMPACT OUR CUSTOMER BASE AND CUSTOMER COLLECTIONS AND INCREASE OUR LEVEL OF INDEBTEDNESS. Inflation has caused increases in certain operating expenses, and has required assets to be replaced at higher costs. We have a process in place to continually review the adequacy of our utility gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates and intend to continue to do so. The ability to control expenses is an important factor that will influence future results. The rapid increases in the price of purchased gas, which has occurred in some prior years, causes us to experience a significant increase in short-term debt because we must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our utility collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal accounts receivable. This situation also results in higher short-term debt levels and increased bad debt expense. Should the price of purchased gas increase significantly in the upcoming heating season, we would expect increases in our short-term debt, accounts receivable and bad debt expense during fiscal 2004. Finally, higher costs of natural gas in recent years have already caused many of our utility customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation methods. OUR OPERATIONS ARE SUBJECT TO INCREASED COMPETITION. We are facing increased competition from other energy suppliers as well as electric companies and from energy marketing and trading companies. In the case of industrial customers, such as manufacturing plants, and agricultural customers, adverse economic conditions, including higher gas costs, could cause these customers to use alternative sources of energy such as electricity or to bypass our systems in favor of special competitive contracts with lower per-unit costs. 26 HIGHLIGHTS - On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), a privately held utility, for approximately $150.0 million, which consisted of approximately $74.7 million in cash and 3,386,287 unregistered shares of our common stock. In addition, we paid approximately $70.9 million to repay outstanding debt of MVG. Our Mississippi Valley Gas Company Division provides natural gas distribution service to approximately 261,500 residential, industrial and other customers located primarily in the northern and central regions of Mississippi. - In January 2003, as a result of the adoption of EITF 02-03 which precludes mark-to-market accounting for our natural gas marketing segment inventory and energy trading contracts that are not derivatives, we recorded a one-time noncash charge for a cumulative effect adjustment of $12.9 million ($7.8 million, net of income tax benefit) on the consolidated statements of income. - On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013. The net proceeds were used to repay debt under a short-term acquisition credit facility used to partially finance the MVG acquisition, to repay $54.0 million in unsecured senior notes held by institutional lenders, short-term debt under our commercial paper program and to provide funds for general corporate purposes. - On June 23, 2003, we completed a public offering of 4,000,000 shares of our common stock, and we sold an additional 100,000 shares of our common stock in July 2003 when our underwriters exercised their overallotment option (collectively referred to as the 2003 Offering). The 2003 Offering was priced at $25.31 per share and generated net proceeds of approximately $99.2 million. The proceeds were used to partially fund our pension plan, to repay short-term debt and to fund general corporate purposes including the purchase of natural gas for storage. - In June 2003, we contributed to the Atmos Energy Corporation Master Retirement Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. The cash contribution was financed through a combination of cash on hand and a portion of the net proceeds received from the 2003 Offering. As a result of this contribution and improved investment returns on the assets used to fund the pension plan, the $39.4 million minimum pension liability recognized during fiscal 2002 was eliminated in fiscal 2003. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Our critical accounting policies are reviewed by the Audit Committee on a quarterly basis. Actual results may differ from estimates. Regulation -- Our utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in their financial statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. As a result, certain 27 costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized because they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our utility operations may be affected by decisions of the regulatory authorities or the issuance of new regulations. Revenue recognition -- Sales of natural gas to our utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for utility segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. Energy trading contracts resulting in the delivery of a commodity where we are the principal in the transaction are recorded as natural gas marketing sales or purchases at the time of physical delivery. Realized gains and losses from the settlement of financial instruments that do not result in physical delivery related to our natural gas marketing energy trading contracts and unrealized gains and losses from changes in the market value of open contracts are included as a component of natural gas marketing revenues. Allowance for Doubtful Accounts -- For the majority of our receivables, we establish an allowance for doubtful accounts based on an aging of those receivable balances. We apply percentages to each aging category based on our collections experience. On certain other receivables where we are aware of a specific customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Derivatives and Hedging Activities -- We use a combination of storage and financial hedges to protect us and our natural gas utility customers against unusually large winter period gas price increases. Further, AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Our financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Changes in the valuation of assets and liabilities arising from risk management activities primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. Market prices and models used to value these transactions reflect our best estimates considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under present market conditions. Changes in market prices and other assumptions used in these models directly affect our estimate of the fair value of these transactions. However, because the costs of financial instruments used in our utility segment will ultimately be recovered through our rates, current period changes in the assets and liabilities from these risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial instruments. The changes in the assets and liabilities from risk management activities are recognized in purchased gas cost in the income statement when the related costs are recovered through our rates. In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the obligation, to buy or sell energy commodities at a fixed price. AEM links these financial derivatives to physical delivery of natural gas 28 and typically balances its derivative positions at the end of each trading day. However, at any point in time, AEM may not have completely offset its risk on these activities. AEM's physical trading activities involve utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day. Impairment Assessments -- We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. We currently have no indefinite-lived intangible assets. We annually evaluate our goodwill balances for impairment during our second fiscal quarter or as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. Our reporting units and our operating segments are the same as each operating unit represents a component of our business. Goodwill is allocated to the reporting units responsible for the acquisition that gave rise to the goodwill. The discounted cash flow calculations used to assess goodwill impairment are dependent on several subjective factors including the timing of future cash flows, future growth rates, and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit's goodwill exceeds its fair value. We periodically evaluate whether events or circumstances have occurred that indicate that our intangible assets subject to amortization and other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of these assets by determining whether the carrying value will be recovered through expected future cash flows. These cash flow projections consider various factors such as the timing of the future cash flows and the discount rate and are based upon the best information available at the time the estimate is made. Changes in these factors could materially affect the cash flow projections and result in the recognition of an impairment charge. An impairment charge is recognized as the difference between the carrying amount and the fair value if the sum of the undiscounted cash flows is less than the carrying value of the related asset. Pension and Other Postretirement Plans -- Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. The assumed return on plan assets is based on management's expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities generally is based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. RESULTS OF OPERATIONS The primary factors that impact our results of utility operations are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas sales to residential, commercial and public authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Accordingly, our second fiscal quarter historically has been our most critical earnings quarter with an average of 68 percent of our net income having been earned in the second quarter during the three most recently completed fiscal years. Utility sales to industrial customers are much less weather sensitive. Utility sales to agricultural customers, who typically use natural gas to power irrigation pumps during the period from March through September, are primarily affected by rainfall amounts and the price of natural gas. Changes in the cost of gas impact revenue but do not directly affect our gross profit from utility operations because the fluctuations in gas prices are passed through to the customer. 29 Our natural gas marketing segment generates income from its industrial, utility and municipal customers through negotiated prices based on the volume of gas supplied to the customer. It also generates income by utilizing storage and transportation capacity that it controls to take advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices. The following table presents our financial highlights for the three fiscal years ended September 30, 2003:
FOR THE YEAR ENDED SEPTEMBER 30 --------------------------------------- 2003 2002 2001 ----------- ----------- ----------- (IN THOUSANDS, UNLESS OTHERWISE NOTED) Operating revenues............................... $2,799,916 $1,650,964 $1,725,481 Gross profit..................................... 534,976 431,140 375,208 Operating expenses............................... 347,136 275,809 244,927 Operating income................................. 187,840 155,531 130,281 Other income (expense)........................... 2,191 (1,321) 6,188 Interest charges................................. 63,660 59,174 47,011 Income before income taxes and cumulative effect of accounting change........................... 126,371 94,836 89,458 Cumulative effect of accounting change, net of income tax benefit............................. (7,773) -- -- Income tax expense............................... 46,910 35,180 33,368 Net income....................................... $ 71,688 $ 59,656 $ 56,090 Utility sales volumes -- MMcf.................... 184,512 145,488 156,544 Utility transportation volumes -- MMcf........... 63,453 63,053 61,230 ---------- ---------- ---------- Total utility throughput -- MMcf............... 247,965 208,541 217,774 ========== ========== ========== Natural gas marketing sales volumes -- MMcf...... 225,961 204,027 55,469 ========== ========== ========== Heating Degree Days Actual (weighted average)...................... 3,473 3,368 4,124 Percent of normal.............................. 101% 94% 115% Consolidated utility average sales price per Mcf............................................ $ 8.13 $ 6.11 $ 8.55 Consolidated utility average transportation revenue per Mcf................................ $ 0.47 $ 0.58 $ 0.47 Consolidated utility average cost of gas per Mcf sold........................................... $ 5.71 $ 3.78 $ 6.47
30 The following table reconciles the gross profit and throughput information from a segment basis, before intercompany eliminations, to a consolidated basis:
FOR THE YEAR ENDED SEPTEMBER 30 --------------------------------------- 2003 2002 2001 ----------- ----------- ----------- (IN THOUSANDS, UNLESS OTHERWISE NOTED) Utility segment gross profit......................... $491,403 $377,635 $362,785 Intersegment activity................................ 7,729 8,746 2,679 -------- -------- -------- Utility segment contribution to consolidated gross profit............................................. $499,132 $386,381 $365,464 ======== ======== ======== Natural gas marketing segment gross profit........... $ 24,165 $ 37,556 $ 1,592 Intersegment activity................................ 607 834 587 -------- -------- -------- Natural gas marketing segment contribution to consolidated gross profit.......................... $ 24,772 $ 38,390 $ 2,179 ======== ======== ======== Other non-utility segment gross profit............... $ 20,090 $ 16,683 $ 10,831 Intersegment activity................................ (9,018) (10,314) (3,266) -------- -------- -------- Other non-utility segment contribution to consolidated gross profit.......................... $ 11,072 $ 6,369 $ 7,565 ======== ======== ======== Utility segment throughput -- MMcf................... 254,671 214,133 218,619 Intersegment activity -- MMcf........................ (6,706) (5,592) (845) -------- -------- -------- Consolidated utility segment throughput -- MMcf...... 247,965 208,541 217,774 ======== ======== ======== Natural gas marketing segment throughput -- MMcf..... 294,785 273,692 98,869 Intersegment activity -- MMcf........................ (68,824) (69,665) (43,400) -------- -------- -------- Consolidated natural gas marketing segment throughput -- MMcf................................. 225,961 204,027 55,469 ======== ======== ========
YEAR ENDED SEPTEMBER 30, 2003 COMPARED WITH YEAR ENDED SEPTEMBER 30, 2002 GROSS PROFIT Utility segment Gross profit for our utility segment primarily consists of gas service margins generated by our six utility operating divisions from the sale of natural gas to approximately 1.7 million residential, commercial, industrial, agricultural and other customers in the 12 states that comprise our utility service areas. Utility gross profit increased to $499.1 million for the year ended September 30, 2003 from $386.4 million for the year ended September 30, 2002. Total throughput for our utility business was 248.0 billion cubic feet (Bcf) during the current year compared to 208.5 Bcf in the prior year. The increase in utility gross profit and total throughput was primarily attributable to the impact of the MVG acquisition in December 2002, which increased utility gross profit and total throughput by $73.2 million and 32.6 Bcf. The increase in utility gross profit was also attributable to a $13.3 million increase in our base charges primarily in Louisiana as a result of our annual rate stabilization clause filing which became effective in November 2002. These increases were partially offset by a $3.9 million decrease in revenues from the impact of WNA as a result of weather in our WNA service areas being 1 percent colder than normal for the year ended September 30, 2003. The average cost of gas per Mcf sold increased 51 percent to $5.71 for 2003 from $3.78 for 2002, resulting in a 33 percent increase in average sales price. However, changes in the cost of gas do not directly affect utility gross profit because the fluctuations in gas prices are passed through to the customer. 31 Natural gas marketing segment Gross profit for our natural gas marketing segment consists primarily of the difference between revenue arising from the sale of physical natural gas to our natural gas marketing customers less the cost to purchase natural gas and unrealized gains and losses from changes in the market value of open contracts. Our natural gas marketing gross profit was $24.8 million for the year ended September 30, 2003 compared to gross profit of $38.4 million for the year ended September 30, 2002. Natural gas marketing sales volumes were 226.0 Bcf during the current year compared to 204.0 Bcf for the prior year. Our natural gas marketing gross profit included an unrealized gain on open contracts of $6.3 million compared with an unrealized loss on open contracts of $10.5 million last year. Natural gas marketing gross profit for the year ended September 30, 2003 decreased as we purchased gas during a period of rising prices to meet our contractual requirements with our customers due to several factors. We anticipated a decline in natural gas prices during the period December 2002 through March 2003; therefore, we elected to keep gas in storage and to buy flowing gas to meet our customer needs during that period. We were also unable to withdraw planned volumes from storage to meet our non-utility customer needs due to contractual and regulatory limitations relating to our storage facilities. Additionally, we experienced situations of open short positions and were not sufficiently hedged on other transactions, which contributed to the decrease in our natural gas marketing gross profit. Finally, we recognized smaller gains from inventory sales in the current year as compared with the prior year. Since the 2002-2003 winter heating season, we have taken steps to minimize any future negative impact of the events that caused the lower-than-expected earnings from our natural gas marketing segment during the year. In July 2003, we entered into a contract for one Bcf of capacity in a salt dome storage facility that will help us to manage our price risk related to customer demand volatility. This facility provides increased flexibility to satisfy changing customer demands because it allows us to inject and withdraw gas on a daily and monthly basis. The contract commenced in November 2003 and will remain in effect for the next five heating seasons. Annual lease payments will be approximately $2.0 million. Additionally, we are amending our contracts with third parties, where possible, to transfer usage risk to our customers and to provide higher margins. Finally, we are reviewing our internal processes to improve the effectiveness of our overall risk management and financial reporting processes. Other Non-utility segment Our other non-utility segment gross profit primarily consists of margins generated by our third party storage services and our leasing operations. Our other non-utility segment contributed $11.1 million in gross profit during the current year compared with $6.4 million for the prior year. The increase in our non-utility gross profit was primarily attributable to increased asset management activities in the current year and an increase in leasing income attributable to the commencement in 2003 of a new lease for a distributed electric generation plant. OTHER CONSOLIDATED ACTIVITY Operating expenses -- Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased 26 percent to $347.1 million for the year ended September 30, 2003 from $275.8 million for the year ended September 30, 2002. Operation and maintenance expense increased primarily due to the addition of $36.0 million related to the MVG acquisition in December 2002 and a $13.3 million increase in the provision for doubtful accounts as a result of higher revenues and gas prices. This increase was partially offset by a $3.2 million reduction in labor costs attributable to lower incentive payment accruals as compared with the prior year. Taxes other than income taxes increased $18.8 million primarily due to additional franchise, payroll and property taxes associated with the MVG assets acquired in December 2002. Note that franchise and state gross receipts taxes are paid by our customers; thus, these amounts are offset in revenues through customer billings and have no effect on net income. 32 Other income (expense) -- Other income for the year ended September 30, 2003 was $2.2 million, compared with an expense of $1.3 million for the year ended September 30, 2002. The $3.5 million change was primarily attributable to a $3.9 million gain associated with a sales-type lease of a distributed electric generation plant which was recognized in the first quarter of 2003 and improved earnings from our indirect investment in Heritage Propane L.P., partially offset by a $0.6 million charge associated with the cancellation of our weather insurance policy during the third quarter of fiscal 2003. Interest charges -- Interest charges increased eight percent for the year ended September 30, 2003 to $63.7 million from $59.2 million for the year ended September 30, 2002. The increase was primarily attributable to a higher average outstanding debt balance resulting from the financing obtained to fund the acquisition of MVG. Cumulative effect of change in accounting principle -- On January 1, 2003, we recorded a cumulative effect of a change in accounting principle to reflect a change in the way we account for our storage and transportation contracts. Previously we accounted for those contracts under EITF 98-10, Accounting for Energy Trading and Risk Management Activities, which required us to record estimated future gains on our storage and transportation contracts at the time we entered into the contracts and to mark those contracts to market value each month. Effective January 1, 2003, we no longer mark those contracts to market. As a result, we expensed $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle. YEAR ENDED SEPTEMBER 30, 2002 COMPARED WITH YEAR ENDED SEPTEMBER 30, 2001 GROSS PROFIT Utility segment Gross profit for our utility segment increased six percent to $386.4 million for the year ended September 30, 2002 from $365.5 million for the year ended September 30, 2001. Total throughput for 2002, excluding Louisiana Gas Service Company's throughput, was 191.4 Bcf compared with 217.8 Bcf for 2001. The increase in utility gross profit was due primarily to the gross profit earned from additional throughput of 17.1 Bcf from the Louisiana Gas Service operations acquired in July 2001. This increase was offset by the effect of warmer weather, which resulted in a 12 percent decrease in gas sales volumes excluding Louisiana Gas Service's gas sales volumes. During 2002, temperatures were 18 percent warmer than the prior year and were six percent warmer than the 30-year normal, adjusted for service areas with weather normalized operations. The average cost of gas per Mcf sold decreased 42 percent to $3.78 for 2002 from $6.47 for 2001, resulting in a 29 percent decrease in average sales price. However, changes in the cost of gas do not directly affect gross profit because the fluctuations in gas prices are passed through to the customer. Natural gas marketing segment Gross profit for our natural gas marketing segment was $38.4 million for the year ended September 30, 2002 compared to gross profit of $2.2 million for the year ended September 30, 2001. Natural gas marketing sales volumes were 204.0 Bcf during the current year compared to 55.5 Bcf for the prior year. The increase for 2002 compared to 2001 was primarily due to gains on inventory sales and favorable pricing under natural gas sales contracts as well as our full consolidation of Woodward Marketing L.L.C. beginning April 2001 when we completed our acquisition of the remaining 55 percent interest in Woodward Marketing, L.L.C. that we did not already own. Since the acquisition, the revenues and expenses of Woodward Marketing L.L.C. have been shown on a consolidated basis. Other Non-utility segment Our other non-utility segment contributed $6.4 million in gross profit during the current year compared with $7.6 million for the prior year. 33 OTHER CONSOLIDATED ACTIVITY Operating Expenses -- Operating expenses increased to $275.8 million for the year ended September 30, 2002 from $244.9 million for the year ended September 30, 2001. Operation and maintenance expense increased primarily due to the addition of $21.5 million relating to the Louisiana Gas Service acquisition in July 2001 and an increase of $10.7 million in pension costs. In addition, operation and maintenance expense increased $9.2 million due to the full consolidation of Woodward Marketing's operations beginning April 1, 2001. A decrease in the provision for doubtful accounts of $26.2 million partially offset this increase. The decrease in the provision for doubtful accounts was attributable to the lower gas commodity prices during 2002 as well as our effective recovery of customer receivable balances. Depreciation and amortization increased $13.8 million due to the addition of the assets from the Louisiana Gas Service acquisition in July 2001. Taxes other than income decreased as a result of decreased city franchise taxes and state gross receipts taxes, which are revenue based. However, these taxes are paid by our customers; thus, these amounts are offset in revenues through customer billings and have no effect on net income. The decrease in taxes other than income was partially offset by increases in property and payroll taxes related to the Louisiana Gas Service acquisition in July 2001. Miscellaneous expense -- Miscellaneous expense decreased $0.6 million to $1.3 million in 2002 compared to $1.9 million in 2001. This decrease was primarily due to an increase in net recoveries related to our performance based-ratemaking mechanisms, the recognition of $0.5 million related to a large industrial contract we received during 2002 and a reduction in the amortization expense recognized related to weather insurance purchased for the 2001-2002 heating season. In addition, we had an increase of $3.0 million in interest income in May 2001 due primarily to interest income earned on the proceeds from our $350.0 million debt offering in 2001. We invested these proceeds in short-term investments until the completion of the Louisiana Gas Service acquisition in July 2001. No such interest income was recognized in 2002. Interest expense -- Interest expense increased $12.2 million to $59.2 million for 2002 compared to $47.0 million for 2001. This increase was due primarily to the interest expense on the $350.0 million debt offering in May 2001. LIQUIDITY AND CAPITAL RESOURCES Our working capital and liquidity for capital expenditures and other cash needs are provided from internally generated funds, borrowings under our credit facilities and commercial paper program and funds raised from the public debt and equity capital markets. We believe that these sources of funds will provide the necessary working capital and liquidity for capital expenditures and other cash needs for fiscal 2004. CAPITALIZATION The following presents our capitalization as of September 30, 2003 and 2002:
SEPTEMBER 30 --------------------------------------- 2003 2002 ------------------ ------------------ (IN THOUSANDS, EXCEPT PERCENTAGES) Short-term debt............................... $ 118,595 6.4% $ 145,791 10.3% Long-term debt................................ 873,263 47.2% 692,443 49.1% Shareholders' equity.......................... 857,517 46.4% 573,235 40.6% ---------- ----- ---------- ----- Total capitalization, including short-term debt........................................ $1,849,375 100.0% $1,411,469 100.0% ========== ===== ========== =====
Total debt as a percentage of total capitalization, including short-term debt, was 53.6 percent and 59.4 percent at September 30, 2003 and 2002. The improvement in the debt to capitalization ratio was primarily attributable to the issuance of common stock in connection with our 2003 Offering and the MVG acquisition as well as the elimination of the minimum pension liability as of September 30, 2003 due to increased funding of our pension plan and improved investment returns on the assets used to fund the pension plan. Our long-term plan is to maintain the debt to capitalization ratio within a target range of 50-52 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan, access to the debt and equity capital markets and limiting annual maintenance and capital expenditures. 34 CASH FLOWS Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors. CASH FLOWS FROM OPERATING ACTIVITIES For the year ended September 30, 2003, we generated operating cash flow of $49.5 million compared with $297.4 million in fiscal 2002 and $83.0 million in fiscal 2001. The significant factors impacting our operating cash flow for the last three fiscal years are summarized below. Year ended September 30, 2003 Fiscal 2003 operating cash flow was adversely impacted by a $60.0 million increase in accounts receivable due to higher revenues and the timing of customer account collections. The increase in revenues is attributable to a 19 percent increase in consolidated utility throughput as a result of the impact of our MVG acquisition and a 33 percent increase in average utility sales price per Mcf primarily due to an increase in natural gas costs. Operating cash flow was also adversely impacted by a significant increase in natural gas prices. These increases resulted in a $64.9 million increase in gas stored underground and a $24.2 million increase in deferred gas costs. Finally, operating cash flow reflects the impact of the funding of our pension plan in June 2003, which included a $48.6 million cash payment. This funding is discussed under the caption Pension and Postretirement Benefits Obligations below. Year ended September 30, 2002 In fiscal 2002, operating cash flow was favorably impacted by a $56.5 million reduction in cash held on deposit in margin accounts. This account represents deposits recorded to collateralize certain of our financial derivatives purchased in support of our natural gas marketing activities and will fluctuate based upon the timing of our derivative activities. Operating cash flow was also favorably impacted by a $52.3 million increase in accounts payable and accrued liabilities and a $34.2 million increase in other current liabilities primarily attributable to the timing of payments as compared with the prior year. Finally, operating cash flow was favorably impacted by a $32.9 million decrease in deferred gas costs reflecting the favorable timing between the billing of gas costs to our customers and the purchase of natural gas. These favorable impacts were partially offset by a $12.2 million increase in accounts receivable. This increase was attributable to revenue increases resulting from the inclusion of the LGS and Woodward Marketing operations for a full year and the timing of customer account collections. Year ended September 30, 2001 In fiscal 2001, operating cash flow was favorably impacted by a $65.0 million decrease in accounts receivable attributable to improved customer collections during fiscal 2001 and a $15.4 million decrease in deferred gas costs reflecting the favorable timing between the billing of gas costs to our customers and the purchase of natural gas. These favorable impacts were partially offset by the $62.2 million deposit of cash into margin accounts to collateralize certain of our financial derivatives and a $94.8 million decrease in accounts payable and accrued liabilities attributable to the timing of payments as compared with the prior year. CASH FLOWS FROM INVESTING ACTIVITIES During the last three years, a substantial portion of our cash resources was used to fund acquisitions, our ongoing construction program to provide natural gas services to our customer base and technology improvements. 35 For the year ended September 30, 2003, we invested $233.4 million compared with $158.2 million for the year ended September 30, 2002 and $468.1 million for the year ended September 30, 2001. Capital expenditures were $159.4 million during the year ended September 30, 2003 compared to $132.3 million for the year ended September 30, 2002 and $113.1 million for the year ended September 30, 2001. Capital projects for fiscal years 2003, 2002 and 2001 include expenditures for additional mains, services, meters and equipment to grow our customer base. Additionally, capital expenditures for 2003 include approximately $14.0 million for Mississippi Valley Gas Company Division capital expenditures. Fiscal 2002 and 2001 cash flows from investing activities also included $8.5 million and $5.4 million for the acquisition of assets to be leased to third parties. Finally, fiscal 2001 cash flows from investing activities included cash receipts of $6.6 million related to the sale of certain utility assets. Capital expenditures for 2004 are expected to approximate $175.0 million. These expenditures include additional mains, services, meters and equipment. PAYMENTS FOR ACQUISITIONS Our cash flows used for investing activities for fiscal 2003 included $74.7 million for the cash portion of the Mississippi Valley Gas Company acquisition completed in December 2002. Cash flows used for investing activities for fiscal 2002 included $15.7 million for the acquisition of Kentucky-based market area storage and associated pipeline facility assets, certain natural gas purchase and sales contracts and the outstanding common stock of Southern Resources, Inc. Cash flows used for investing activities for fiscal 2001 included $363.4 million for the acquisition of the assets of Louisiana Gas Service Company. In addition, we received $8.6 million in cash during fiscal 2001 in connection with the acquisition of the remaining 55 percent interest in Woodward Marketing that we did not already own. CASH FLOWS FROM FINANCING ACTIVITIES For the year ended September 30, 2003 our financing activities provided $151.6 million of cash. Fiscal 2002 cash flows from financing activities represented a use of cash of $106.4 million and, in fiscal 2001, our financing activities provided $393.0 million of cash. Our significant financing activities for the three years ended September 30, 2003 are summarized as follows: - During fiscal 2003, we received $147.0 million from a short-term acquisition credit facility which was used primarily to fund the $74.7 million cash portion of the purchase price for MVG in December 2002 and to repay $70.9 million of MVG's outstanding debt. - On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013. The net proceeds of $249.3 million were used to refinance the short-term acquisition credit facility of $147.0 million, to repay $54.0 million in unsecured senior notes held by institutional lenders, and short-term debt under our commercial paper program and to provide funds for general corporate purposes. In fiscal 2001, we issued $350.0 million of 7.375% Senior Notes due in 2011 and received net proceeds of $347.1 million. The net proceeds were used to finance the acquisition of the assets of Louisiana Gas Service Company. - In June and July 2003, we sold a total of 4,100,000 shares of our common stock in a public offering. The offering was priced at $25.31 per share and generated net proceeds of $99.2 million. The net proceeds were used to finance a portion of our pension plan contribution, repay short-term debt and to provide for general corporate purposes. In fiscal 2001, we issued 6,741,500 shares, which provided net proceeds of $142.0 million. The net proceeds were used to repay commercial paper and to provide funds for general corporate purposes. - During fiscal 2003, 2002 and 2001, total short-term debt decreased by $27.2 million, $55.5 million and $48.8 million. - We repaid $73.2 million of long-term debt during fiscal 2003, which includes the $54.0 million repayment of unsecured senior notes with the proceeds received from our January 2003 debt offering. Fiscal 2002 and 2001 payments were $20.7 million and $17.7 million. 36 - During fiscal 2003, we paid $55.3 million in cash dividends compared with dividend payments of $48.6 million and $44.1 million for fiscal 2002 and 2001. The increase in dividends paid over the preceding two years reflects increases in the quarterly dividend rate and the number of shares outstanding. During the year ended September 30, 2003, we issued 9,799,853 shares of common stock. Of these shares, 3,386,287 shares were issued in December 2002 for the stock portion of the MVG acquisition, 4,100,000 shares were issued in connection with our 2003 Offering and 1,169,700 shares were issued in connection with our stock contribution to our pension plan in June 2003. The following table shows the number of shares issued for the years ended September 30, 2003, 2002 and 2001:
FOR THE YEAR ENDED SEPTEMBER 30 ------------------------------- 2003 2002 2001 --------- ------- --------- Shares issued: Direct stock purchase plan......................... 585,743 505,202 411,159 Retirement savings plan............................ 360,725 326,335 225,945 Long-term incentive plan........................... 181,429 50,465 17,172 Long-term stock plan for Mid-States Division....... 13,000 -- 15,300 Outside directors stock-for-fee plan............... 2,969 2,429 2,152 Non-employee directors equity incentive compensation plan............................... -- -- 2,740 Acquisition of Woodward Marketing L.L.C. .......... -- -- 1,423,193 December 2000 Equity Offering...................... -- -- 6,741,500 Acquisition of MVG................................. 3,386,287 -- -- Pension account plan funding....................... 1,169,700 -- -- 2003 Offering...................................... 4,100,000 -- -- --------- ------- --------- Total shares issued............................. 9,799,853 884,431 8,839,161 ========= ======= =========
SHELF REGISTRATION In December 2001, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $600.0 million in new common stock and/or debt. The registration statement was declared effective by the SEC on January 30, 2002. As discussed above, on January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes. Additionally, as noted above, we sold 4,100,000 shares of our common stock in connection with our 2003 Offering under the registration statement. After the debt offering and these common stock sales, approximately $246.0 million remains available under the shelf registration statement. CREDIT FACILITIES We maintain both committed and uncommitted credit facilities. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder months. Our working capital needs can vary significantly due to changes in the price of natural gas charged by suppliers and the increased gas supplies required to meet customers' needs during periods of cold weather. COMMITTED CREDIT FACILITIES We have two short-term committed credit facilities totaling $368.0 million. The first short-term unsecured credit facility is for $350.0 million, bears interest at the Eurodollar rate plus 0.625 percent and 37 serves as a backup liquidity facility for our commercial paper program. This facility was renewed in July 2003 with a $50.0 million increase in the amount of the facility under substantially the same terms as those of the prior facility. This facility will expire in July 2004. At September 30, 2003, $118.6 million of commercial paper was outstanding, and Atmos Energy Corporation letters of credit reduced the amount available by an additional $2.4 million. We have a second unsecured facility in place for $18.0 million that bears interest at the Fed Funds rate plus 0.5 percent. At September 30, 2003, there were no borrowings under this credit facility. These credit facilities are negotiated at least annually and are used for working capital purposes. On October 7, 2002, we entered into a $150.0 million short-term unsecured committed credit facility. This credit facility was used to provide initial funding for the cash portion of the MVG acquisition and to repay MVG's existing debt. A total of $147.0 million was borrowed under this credit facility during the first quarter. This amount was refinanced in January 2003 with a portion of the proceeds of our $250.0 million debt offering, as discussed above. The availability of funds under our credit facilities is subject to conditions specified therein, which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our $350.0 million credit facility to maintain a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2003, our total debt to total capitalization ratio, as defined, was 55 percent. UNCOMMITTED CREDIT FACILITIES Our Woodward Marketing subsidiary has a $210.0 million uncommitted demand working capital credit facility that bears interest at LIBOR plus 2.5 percent. Atmos Energy Holdings, Inc. (AEH) and Atmos Energy Marketing, LLC, our wholly-owned subsidiaries, are guarantors of all amounts outstanding under this facility. Effective October 1, 2003 with the reorganization of our natural gas marketing segment, AEM became the borrower under the credit facility and AEH became the sole guarantor of the facility. At September 30, 2003, no amount was outstanding under this credit facility, although Woodward Marketing, L.L.C. letters of credit totaling $76.9 million reduced the amount available. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to Woodward Marketing under this credit facility at September 30, 2003 was $28.3 million. This credit facility expires on March 31, 2004 and is expected to be renewed at that time. We also have an unsecured short-term uncommitted credit line for $20.0 million. There were no borrowings under this uncommitted credit facility at September 30, 2003. This uncommitted line is renewed or renegotiated at least annually with varying terms and we pay no fee for the availability of the line. Borrowings under this line are made on a when and as-available basis at the discretion of the bank. This facility is also used for working capital purposes. In October 2003, we increased the amount of this credit line to $25.0 million. In addition, Woodward Marketing has a $100.0 million intercompany credit facility with AEH for its non-utility business which bore interest at LIBOR plus 1.25 percent through July 2003 when the interest rate was increased to LIBOR plus 2.75 percent. Any outstanding amounts under this facility are subordinated to Woodward Marketing's $210.0 million uncommitted demand credit facility described above. At September 30, 2003, $70.0 million was outstanding under this facility. CREDIT RATING Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risk associated with our utility and non-utility businesses and the regulatory structures that govern our rates in the states where we operate. 38 Our debt is rated by three rating agencies: Standard & Poor's Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings, Inc. (Fitch). Our current debt ratings are as follows:
S&P MOODY'S FITCH --- ------- ----- Long-term debt.............................................. A- A3 A- Commercial paper............................................ A-2 P-2 F-2
Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant. On January 10, 2003, S&P changed the outlook on our long-term debt rating from "stable" to "negative." In its press release explaining this action, S&P cited, among other factors, their concern that we have not made significant progress in reducing our debt to total capitalization ratio. Since S&P changed its outlook, we have issued equity and substantially reduced our leverage. Moody's and Fitch each continue to maintain a "stable" outlook for our ratings. We have no trigger events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity based on our credit rating or other trigger events. DEBT COVENANTS In addition to the limit on our total debt to capitalization ratio imposed by our committed credit facilities described above, our First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1988 may not exceed the sum of accumulated net income for periods after December 31, 1988 plus $15.0 million. At September 30, 2003, approximately $84.1 million of retained earnings was unrestricted. We are in compliance with all of our debt covenants as of September 30, 2003. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS The following tables provide information about contractual obligations and commercial commitments at September 30, 2003.
PAYMENTS DUE BY PERIOD ------------------------------------------------------- LESS THAN AFTER TOTAL 1 YEAR 1-3 YEARS 4-5 YEARS 5 YEARS -------- --------- --------- --------- -------- (IN THOUSANDS) CONTRACTUAL OBLIGATIONS Long-Term Debt.................... $873,263 $ 9,345 $11,078 $12,506 $840,334 Capital Lease Obligations......... 5,125 876 1,276 795 2,178 Operating Leases.................. 58,925 10,331 18,821 12,956 16,817 -------- -------- ------- ------- -------- Total Contractual Obligations... $937,313 $ 20,552 $31,175 $26,257 $859,329 ======== ======== ======= ======= ======== OTHER COMMERCIAL COMMITMENTS Lines of Credit................... $118,595 $118,595 $ -- $ -- $ -- ======== ======== ======= ======= ========
AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward Nymex strip or fixed price contracts. At September 30, 2003, AEM was committed to purchase 83.1 Bcf within one year and 24.8 Bcf between 1 to 3 years under indexed contracts. AEM was committed to purchase 2.2 Bcf within one year under fixed price contracts with prices ranging from $3.13 to $6.70. AEM's fixed price contracts are marked to market as derivatives. See further discussion of the fixed price contracts under "Risk Management and Trading Activities." 39 Our utility segment maintains supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract. PENSION AND POSTRETIREMENT BENEFITS OBLIGATIONS In June 2003, we contributed to the Atmos Energy Corporation Master Retirement Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. Of the total cash contributed, $26.1 million represented a 2002 contribution, which was deducted on our 2002 tax return. The cash contribution was financed through a combination of cash on hand and a portion of the net proceeds received from the sale of 4,100,000 shares of our common stock in our 2003 Offering. As a result of this contribution and improved investment returns during fiscal 2003, the underfunded status of the plan improved by approximately $8.6 million, and the $39.4 million reduction to equity recorded in the prior year was eliminated as of September 30, 2003. We recorded the $39.4 million reduction in equity at September 30, 2002 as a result of negative investment returns from plan assets during fiscal 2002, lump sum distributions to participants and a decrease in interest rates. Refer to Note 9 to the consolidated financial statements for further information regarding our pension plans. For the fiscal year ended September 30, 2003, our pension cost was $2.7 million compared with pension income of $3.5 million and $8.3 million for the fiscal years ended September 30, 2002 and 2001. Pension income and expense is recorded as a component of operation and maintenance expense. We incurred pension cost during fiscal 2003 compared with income in fiscal 2002 due to an increase in the service cost and interest cost attributable to an increase in the projected benefit obligation. The increase in the projected benefit obligation resulted primarily from an increase in the number of plan participants due to the MVG acquisition and an increase attributable to a 125 basis point decrease in the discount rate used in the fiscal 2003 actuarial calculations reflecting the decline in market interest rates. The decrease in pension income between fiscal 2001 and 2002 was attributable to increases in service cost and interest costs due to increases in the projected benefit obligations coupled with a decrease in the expected return on assets due to poor investment performance. The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the Plan are subject to change, depending upon the actuarial value of plan assets and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts are impacted by actual investment returns, changes in interest rates and changes in the demographic composition of the participants in the plan. The actuarial assumptions used to determine the pension liability for our pension plan are as follows:
2003 2002 2001 ---- ---- ----- Discount rate............................................... 6.00% 7.25% 7.50% Rate of compensation increase............................... 4.00% 4.00% 4.00% Expected return on plan assets.............................. 9.00% 9.25% 10.00%
The assumed return on plan assets is based on management's expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities generally is based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid. These rates have declined since fiscal 2001 due to a decline in interest rates and poor market performance of the underlying plan assets. The rate of compensation increase is established based upon our internal budgets. At this time, we anticipate that additional voluntary contributions ranging from $0 -- $15 million during fiscal 2004 may be necessary to keep the plan 100% funded on an accumulated benefit obligation basis. 40 RISK MANAGEMENT AND TRADING ACTIVITIES We conduct our risk management activities through both our utility and natural gas marketing segments. The following table shows our risk management assets and liabilities by segment at September 30, 2003.
NATURAL GAS UTILITY MARKETING TOTAL ------- ----------- -------- (IN THOUSANDS) Assets from risk management activities, current...... $ 202 $ 22,057 $ 22,259 Assets from risk management activities, noncurrent... -- 1,699 1,699 Liabilities from risk management activities, current............................................ (7,941) (12,849) (20,790) Liabilities from risk management activities, noncurrent......................................... -- (763) (763) ------- -------- -------- Net assets (liabilities)............................. $(7,739) $ 10,144 $ 2,405 ======= ======== ========
UTILITY HEDGING ACTIVITIES Our utility segment's hedging activities are designed to protect us and our customers against unusually large winter period gas price increases and include the use of financial hedges and fixed forward contracts. For the 2002-2003 heating season, we covered approximately 51 percent of our anticipated flowing gas requirements through a combination of storage, financial hedges and fixed forward contracts at a weighted average cost of less than $4.00 per Mcf. This provided a measure of protection to us and our customers against the natural gas price volatility experienced during the 2002-2003 heating season. For the 2003-2004 heating season, we expect to hedge between 50 percent and 55 percent of our anticipated flowing gas requirements through a combination of storage and financial hedges at a weighted average cost of approximately $5.25 per Mcf. In June 2001, we purchased a three year weather insurance policy with an option to cancel the third year of coverage. The insurance was designed for our Texas and Louisiana operations to protect against weather that was at least seven percent warmer than normal for the entire heating season of October through March beginning with the 2001-2002 heating season. The cost of the three year policy was $13.2 million, which was prepaid and amortized over the appropriate heating seasons based on degree days. Because weather was not at least seven percent warmer than normal, no income was recognized under this insurance policy during the years ended September 30, 2003 and 2002. Amortization expense of $5.0 million and $4.4 million was recognized during the fiscal years ended September 30, 2003 and 2002. Included in the amortization expense for the fiscal year ended September 30, 2003 was a third quarter charge of $0.6 million, net of cash received, related to the cancellation of the third year of coverage on our weather insurance policy primarily as a result of rate relief in Louisiana, WNA in certain areas of Texas and prospects for WNA in other areas of Texas. NON-UTILITY HEDGING ACTIVITIES Our natural gas marketing segment hedging activities are conducted through AEM and are designed to manage margins on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over- the-counter and exchange-traded options and swap contracts with counterparties. On October 25, 2002, the Emerging Issues Task Force (EITF) issued EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Prior to the issuance of EITF 02-03, we accounted for all energy trading contracts under the mark-to-market method in accordance with EITF 98-10. With the adoption of EITF 02-03, our inventory, storage, transportation and index-priced physical forward contracts are no longer marked to market. Our index-priced physical forward contracts are now considered normal purchases and sales under SFAS 133. Accordingly, the carrying value of these contracts was frozen as of January 1, 2003 and will be recognized in earnings concurrent with delivery under the contracts. We recognized a charge for the 41 cumulative effect of accounting change of $7.8 million, net of income tax benefit, upon the adoption of EITF 02-03 in the second quarter of fiscal 2003. Fixed price contracts generally continue to be marked to market. In conjunction with the adoption of EITF 02-03, energy trading contracts resulting in delivery of a commodity where we are the principal in the transaction are included as natural gas marketing sales or purchases at the time of delivery. The following table shows the components of the change in fair value of our utility and natural gas marketing derivative contract activities for the year ended September 30, 2003 (in thousands).
NATURAL GAS UTILITY MARKETING ------- ----------- Fair value of contracts at September 30, 2002............... $ 4,424 $ 6,651 Contracts realized/settled................................ (4,638) (1,363) Fair value of new contracts............................... (7,525) 6,176 Other changes in value.................................... -- 7,479 Cumulative effect of accounting change.................... -- (8,799) ------- ------- Fair value of contracts at September 30, 2003............... $(7,739) $10,144 ======= =======
The fair value of our utility and natural gas marketing derivative contracts at September 30, 2003, is segregated below, by time period and fair value source.
FAIR VALUE OF CONTRACTS AT SEPTEMBER 30, 2003 ------------------------------------------------- MATURITY IN YEARS ------------------------------------ GREATER TOTAL FAIR SOURCE OF FAIR VALUE LESS THAN 1 1-3 4-5 THAN 5 VALUE - -------------------- ----------- ------ --- ------- ---------- (IN THOUSANDS) Prices actively quoted................... $(4,420) $ 107 $-- $-- $(4,313) Prices provided by other external sources................................ 6,793 1,346 88 -- 8,227 Prices based on models and other valuation methods...................... (904) (605) -- -- (1,509) ------- ------ --- -- ------- Total Fair Value......................... $ 1,469 $ 848 $88 $-- $ 2,405 ======= ====== === == =======
Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day. These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings. Compliance with this risk management policy is monitored on a daily basis. In addition, the risk management policy limits Woodward Marketing's Gas Daily Daily and NYMEX positions with price risk, including inventory, (open positions) to a total volume of 5.0 Bcf. We manage our business to maintain no open positions. However, at times, limited net open positions related to our physical storage may occur on a short term basis. Woodward Marketing monitors its open trading positions daily to ensure they are within the limits set by the risk management policy. At September 30, 2003, Woodward's net open positions in its trading operations totaled 0.1 Bcf. RECENT ACCOUNTING DEVELOPMENTS In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both 42 liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer's shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation, must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for most previously existing financial instruments. In November 2003, the FASB voted to defer indefinitely the effective date for certain mandatorily redeemable non-controlling interests (MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the effective date was deferred to November 5, 2003. The adoption of SFAS 150 did not impact our financial position, results of operations or net cash flows as we currently do not use any of the financial instruments subject to this statement. In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies the accounting and reporting for derivative instruments, including hedges. This statement amends SFAS 133 for decisions made by the Derivatives Implementation Group and by the FASB in connection with other projects dealing with financial instruments, and clarifies other implementation issues. SFAS 149 is effective for the Company on a prospective basis for contracts entered into or modified after June 30, 2003. The adoption of this statement did not have a material impact on our financial position, results of operations or net cash flows. In January 2003, the FASB issued FASB Interpretation (FIN) 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation will not have a material impact on our financial position, results of operations or net cash flows because Atmos currently is not a primary beneficiary of a VIE. In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based Compensation. SFAS 148 provides three transition options for companies that account for stock-based compensation under the intrinsic method to convert to the fair value method. SFAS 148 also modified the disclosure requirements for stock-based compensation to increase the prominence and character of the pro forma disclosures for entities using the intrinsic value method. Although we have elected to continue using the intrinsic value method, we adopted the disclosure requirements prescribed by SFAS 148. In November 2002, the FASB issued FIN 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 clarifies the requirements of SFAS 5 Accounting For Obligations, relating to a guarantor's accounting for, and disclosure of the issuance of certain types of guarantees. The adoption of FIN 45 did not impact our financial position, results of operations or net cash flows as we currently do not have any guarantees that meet the recognition and disclosure criteria outlined in this pronouncement. In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Effective October 1, 2002, we adopted SFAS 143, which had no material impact on our financial position or results of operations based on the perpetual nature of our franchise agreements and on our experience in the businesses in which we operate. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The risk inherent in our market risk-sensitive instruments is the potential loss arising from adverse changes in natural gas commodity prices and interest rates as discussed below. The sensitivity analysis does 43 not, however, consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions we may take to mitigate exposure to such changes. Actual results may differ. GAS PRICES UTILITY SEGMENT We purchase natural gas for our utility operations. Substantially all of the cost of gas purchased for utility operations is recovered from our customers through purchased gas adjustment mechanisms. The utility segment has limited market risk in gas prices related to gas purchases in the open market at spot prices for sale to non-regulated energy services customers at fixed prices. As a result, our earnings could be affected by changes in the price and availability of such gas. To protect against volatility in gas prices, we hedge our gas costs by purchasing futures contracts and by purchasing gas in advance of the winter heating season and placing it in storage. Our utility segment does not use such financial instruments for trading purposes and we are not a party to any leveraged derivatives. Market risk is estimated as a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on projected fiscal 2004 non-regulated gas sales at fixed prices based upon the September 30, 2003 three month market strip, such an increase would result in an increase to cost of gas of approximately $5.7 million in fiscal 2004. NATURAL GAS MARKETING SEGMENT The principal business of AEM, including the activities of Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the southeastern and midwestern United States. AEM also supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis. In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. AEM links these gas futures to physical delivery of natural gas and typically balances its futures positions at the end of each trading day. However, at any point in time, AEM may not have completely offset its risk on these activities. Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day. These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings. Compliance with this risk management policy is monitored on a daily basis. In addition, the risk management policy limits Woodward Marketing's Gas Daily Daily and NYMEX positions with price risk, including inventory, (open positions) to a total volume of 5.0 Bcf. We manage our business to maintain no open positions. However, at times, limited net open positions related to our physical storage may occur on a short term basis. Woodward Marketing monitors its open trading positions daily to ensure they are within the limits set by the risk management policy. At September 30, 2003, Woodward's net open positions in its trading operations totaled 0.1 Bcf. 44 Counterparty risk is the risk of loss from nonperformance by financial counterparties to a contract. Financial instruments, which subject AEM to counterparty risk, consist primarily of financial instruments arising from trading and risk management activities and overnight repurchase agreements that are not insured. Exchange traded future and option contracts are generally guaranteed by the exchanges. Because AEM's operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Therefore, an economic downturn in the industry could have an adverse affect on the creditworthiness of AEM's customers. AEM manages credit risk to attempt to minimize its exposure to uncollectible receivables. In compliance with AEM's existing credit policy, prospective and existing customers are reviewed for creditworthiness and customers not meeting minimum standards, at the discretion of management, provide security deposits and are subject to various requisite secured payment terms. During 2003, AEM's credit risk has increased due to higher natural gas prices as compared with the prior year. However, this risk is somewhat mitigated because a larger percentage of our business in the current year is with municipal customers, who are typically rated investment grade, as compared with the prior year. INTEREST RATES Our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper and our other short-term borrowings. If market interest rates for short-term borrowings in fiscal 2003 had averaged one percent more, our interest expense would have increased by approximately $1.3 million. Market risk for fixed-rate long-term obligations is estimated as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates and amounts to approximately $72.3 million based on discounted cash flow analyses. As of September 30, 2003, we were not engaged in other activities which would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates or market commodity prices. 45 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
PAGE ---- Report of independent auditors.............................. 47 Financial statements and supplementary data: Consolidated balance sheets at September 30, 2003 and 2002................................................... 48 Consolidated statements of income for the years ended September 30, 2003, 2002 and 2001...................... 49 Consolidated statements of shareholders' equity for the years ended September 30, 2003, 2002 and 2001.......... 50 Consolidated statements of cash flows for the years ended September 30, 2003, 2002 and 2001...................... 51 Notes to consolidated financial statements................ 52 Selected Quarterly Financial Data (unaudited)............. 95 Financial statement schedule for the years ended September 30, 2003, 2002 and 2001 II. Valuation and Qualifying Accounts..................... 101
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. 46 REPORT OF INDEPENDENT AUDITORS Board of Directors Atmos Energy Corporation We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation as of September 30, 2003 and 2002, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Atmos Energy Corporation at September 30, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2003, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. As discussed in Note 4 to the consolidated financial statements, in fiscal 2002 the Company adopted Statement of Financial Accounting Standards No. 141, Business Combinations and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. ERNST & YOUNG LLP Dallas, Texas November 10, 2003 47 ATMOS ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30 ----------------------- 2003 2002 ---------- ---------- (IN THOUSANDS, EXCEPT SHARE DATA) ASSETS Property, plant and equipment............................... $2,463,992 $2,103,428 Construction in progress.................................... 16,147 24,399 ---------- ---------- 2,480,139 2,127,827 Less accumulated depreciation and amortization.............. 964,150 827,507 ---------- ---------- Net property, plant and equipment......................... 1,515,989 1,300,320 Current assets Cash and cash equivalents................................. 15,683 47,991 Cash held on deposit in margin account.................... 17,903 10,192 Accounts receivable, less allowance for doubtful accounts of $13,051 in 2003 and $10,509 in 2002................. 216,783 136,227 Gas stored underground.................................... 168,765 91,783 Other current assets...................................... 38,863 44,962 ---------- ---------- Total current assets................................... 457,997 331,155 Goodwill and intangible assets.............................. 273,499 190,380 Deferred charges and other assets........................... 271,023 159,530 ---------- ---------- $2,518,508 $1,981,385 ========== ========== CAPITALIZATION AND LIABILITIES Shareholders' equity Common stock, no par value (stated at $.005 per share); 100,000,000 shares authorized; issued and outstanding: 2003 -- 51,475,785 shares, 2002 -- 41,675,932 shares... $ 257 $ 208 Additional paid-in capital................................ 736,180 508,265 Retained earnings......................................... 122,539 106,142 Accumulated other comprehensive loss...................... (1,459) (41,380) ---------- ---------- Shareholders' equity................................... 857,517 573,235 Long-term debt.............................................. 863,918 670,463 ---------- ---------- Total capitalization................................... 1,721,435 1,243,698 Commitments and Contingencies (Note 13) Current liabilities Accounts payable and accrued liabilities.................. 179,852 136,773 Other current liabilities................................. 127,923 159,727 Short-term debt........................................... 118,595 145,791 Current maturities of long-term debt...................... 9,345 21,980 ---------- ---------- Total current liabilities.............................. 435,715 464,271 Deferred income taxes....................................... 223,350 134,540 Deferred credits and other liabilities...................... 138,008 138,876 ---------- ---------- $2,518,508 $1,981,385 ========== ==========
See accompanying notes to consolidated financial statements 48 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED SEPTEMBER 30 --------------------------------------- 2003 2002 2001 ----------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Operating revenues Utility segment........................................ $1,554,082 $ 937,526 $1,380,148 Natural gas marketing segment.......................... 1,668,493 1,031,874 447,096 Other non-utility segment.............................. 21,630 24,705 59,436 Intersegment eliminations.............................. (444,289) (343,141) (161,199) ---------- ---------- ---------- 2,799,916 1,650,964 1,725,481 Purchased gas cost Utility segment........................................ 1,062,679 559,891 1,017,363 Natural gas marketing segment.......................... 1,644,328 994,318 445,504 Other non-utility segment.............................. 1,540 8,022 48,605 Intersegment eliminations.............................. (443,607) (342,407) (161,199) ---------- ---------- ---------- 2,264,940 1,219,824 1,350,273 ---------- ---------- ---------- Gross profit........................................... 534,976 431,140 375,208 Operating expenses Operation and maintenance.............................. 205,090 158,119 139,608 Depreciation and amortization.......................... 87,001 81,469 67,664 Taxes, other than income............................... 55,045 36,221 37,655 ---------- ---------- ---------- Total operating expenses............................ 347,136 275,809 244,927 ---------- ---------- ---------- Operating income......................................... 187,840 155,331 130,281 Other income (expense) Equity in earnings of Woodward Marketing, L.L.C. ...... -- -- 8,062 Miscellaneous income (expense)......................... 2,191 (1,321) (1,874) ---------- ---------- ---------- Total other income (expense)........................ 2,191 (1,321) 6,188 Interest charges......................................... 63,660 59,174 47,011 ---------- ---------- ---------- Income before income taxes and cumulative effect of accounting change...................................... 126,371 94,836 89,458 Income tax expense....................................... 46,910 35,180 33,368 ---------- ---------- ---------- Income before cumulative effect of accounting change..... 79,461 59,656 56,090 Cumulative effect of accounting change, net of income tax benefit................................................ (7,773) -- -- ---------- ---------- ---------- Net income.......................................... $ 71,688 $ 59,656 $ 56,090 ========== ========== ========== Per share data Basic income per share: Income before cumulative effect of accounting change............................................ $ 1.72 $ 1.45 $ 1.47 Cumulative effect of accounting change, net of income tax benefit................................ (.17) -- -- ---------- ---------- ---------- Net income.......................................... $ 1.55 $ 1.45 $ 1.47 ========== ========== ========== Diluted income per share: Income before cumulative effect of accounting change............................................ $ 1.71 $ 1.45 $ 1.47 Cumulative effect of accounting change, net of income tax benefit................................ (.17) -- -- ---------- ---------- ---------- Net income.......................................... $ 1.54 $ 1.45 $ 1.47 ========== ========== ========== Weighted average shares outstanding: Basic.................................................. 46,319 41,171 38,156 ========== ========== ========== Diluted................................................ 46,496 41,250 38,247 ========== ========== ==========
See accompanying notes to consolidated financial statements 49 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ACCUMULATED COMMON STOCK OTHER ------------------- ADDITIONAL COMPREHENSIVE NUMBER OF STATED PAID-IN INCOME RETAINED SHARES VALUE CAPITAL (LOSS) EARNINGS TOTAL ---------- ------ ---------- ------------- -------- -------- (IN THOUSANDS, EXCEPT SHARE DATA) BALANCE, SEPTEMBER 30, 2000.......... 31,952,340 $160 $306,887 $ 2,265 $ 83,154 $392,466 COMPREHENSIVE INCOME: Net income......................... -- -- -- -- 56,090 56,090 Unrealized holding losses on investments, net................. -- -- -- (3,685) -- (3,685) -------- TOTAL COMPREHENSIVE INCOME....... 52,405 CASH DIVIDENDS ($1.16 PER SHARE)..... -- -- -- -- (44,112) (44,112) COMMON STOCK ISSUED: Public offering.................... 6,741,500 34 142,009 -- -- 142,043 Acquisition of Woodward Marketing, L.L.C............................ 1,423,193 7 26,650 -- -- 26,657 Direct stock purchase plan......... 411,159 2 8,682 -- -- 8,684 Retirement savings plan............ 225,945 1 5,098 -- -- 5,099 Long-term incentive plan........... 17,172 -- 272 -- -- 272 United Cities long-term stock plan............................. 15,300 -- 240 -- -- 240 Non-employee directors equity incentive compensation plan...... 2,740 -- 60 -- -- 60 Outside directors stock-for-fee plan............................. 2,152 -- 50 -- -- 50 ---------- ---- -------- -------- -------- -------- BALANCE, SEPTEMBER 30, 2001.......... 40,791,501 204 489,948 (1,420) 95,132 583,864 COMPREHENSIVE INCOME: Net income......................... -- -- -- -- 59,656 59,656 Minimum pension liability, net..... -- -- -- (39,432) -- (39,432) Unrealized holding losses on investments, net................. -- -- -- (528) -- (528) -------- TOTAL COMPREHENSIVE INCOME....... 19,696 CASH DIVIDENDS ($1.18 PER SHARE)..... -- -- -- -- (48,646) (48,646) COMMON STOCK ISSUED: Direct stock purchase plan......... 505,202 2 10,546 -- -- 10,548 Retirement savings plan............ 326,335 2 7,137 -- -- 7,139 Long-term incentive plan........... 50,465 -- 579 -- -- 579 Outside directors stock-for-fee plan............................. 2,429 -- 55 -- -- 55 ---------- ---- -------- -------- -------- -------- BALANCE, SEPTEMBER 30, 2002.......... 41,675,932 208 508,265 (41,380) 106,142 573,235 COMPREHENSIVE INCOME: Net income......................... -- -- -- -- 71,688 71,688 Minimum pension liability, net..... -- -- -- 39,432 -- 39,432 Unrealized holding gains on investments, net................. -- -- -- 489 -- 489 -------- TOTAL COMPREHENSIVE INCOME....... 111,609 CASH DIVIDENDS ($1.20 PER SHARE)..... -- -- -- -- (55,291) (55,291) COMMON STOCK ISSUED: Public offering.................... 4,100,000 20 99,102 -- -- 99,122 Acquisition of Mississippi Valley Gas Company...................... 3,386,287 17 74,633 -- -- 74,650 Contribution to Atmos Pension Account Plan..................... 1,169,700 6 28,757 -- -- 28,763 Direct stock purchase plan......... 585,743 3 13,209 -- -- 13,212 Retirement savings plan............ 360,725 2 8,277 -- -- 8,279 Long-term incentive plan........... 181,429 1 3,664 -- -- 3,665 Long-term stock plan for Mid-States Division......................... 13,000 -- 206 -- -- 206 Outside directors stock-for-fee plan............................. 2,969 -- 67 -- -- 67 ---------- ---- -------- -------- -------- -------- BALANCE, SEPTEMBER 30, 2003.......... 51,475,785 $257 $736,180 $ (1,459) $122,539 $857,517 ========== ==== ======== ======== ======== ========
See accompanying notes to consolidated financial statements 50 ATMOS ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED SEPTEMBER 30 --------------------------------- 2003 2002 2001 --------- --------- --------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES Net income.............................................. $ 71,688 $ 59,656 $ 56,090 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of accounting change, net of income tax benefit........................................ 7,773 -- -- Depreciation and amortization: Charged to depreciation and amortization........... 87,001 81,469 67,664 Charged to other accounts.......................... 2,193 2,452 2,806 Deferred income taxes................................ 53,867 14,509 18,501 Other................................................ (5,885) (3,371) (979) Changes in assets and liabilities: (Increase) decrease in cash held on deposit in margin account............................................ (7,711) 56,474 (62,181) (Increase) decrease in accounts receivable........... (60,026) (12,181) 65,032 Increase in gas stored underground................... (64,875) (2,228) (3,376) (Increase) decrease in other current assets.......... (15,747) 28,146 23,049 (Increase) decrease in deferred charges and other assets............................................. 21,258 (33,515) (12,143) Increase (decrease) in accounts payable and accrued liabilities........................................ 19,417 52,302 (94,769) Increase (decrease) in other current liabilities..... (40,636) 34,195 15,888 Increase (decrease) in deferred credits and other liabilities........................................ (18,866) 19,487 7,413 --------- --------- --------- Net cash provided by operating activities.......... 49,451 297,395 82,995 CASH FLOWS USED IN INVESTING ACTIVITIES Capital expenditures.................................... (159,439) (132,252) (113,109) Acquisitions, net of cash received...................... (74,650) (15,747) (354,755) Retirements of property, plant and equipment, net....... 704 (1,725) (1,460) Assets for leasing activities........................... -- (8,511) (5,377) Proceeds from sale of assets, net....................... -- -- 6,625 --------- --------- --------- Net cash used in investing activities.............. (233,385) (158,235) (468,076) CASH FLOWS FROM FINANCING ACTIVITIES Net decrease in short-term debt......................... (27,196) (55,456) (48,800) Net proceeds from issuance of long-term debt............ 253,267 -- 347,099 Proceeds from Bridge loan............................... 147,000 -- -- Repayment of Bridge loan................................ (147,000) -- -- Repayment of long-term debt............................. (73,165) (20,651) (17,670) Repayment of Mississippi Valley Gas debt................ (70,938) -- -- Cash dividends paid..................................... (55,291) (48,646) (44,112) Issuance of common stock................................ 25,720 18,321 14,405 Net proceeds from equity offering....................... 99,229 -- 142,043 --------- --------- --------- Net cash provided (used) by financing activities... 151,626 (106,432) 392,965 --------- --------- --------- Net increase (decrease) in cash and cash equivalents...... (32,308) 32,728 7,884 Cash and cash equivalents at beginning of year............ 47,991 15,263 7,379 --------- --------- --------- Cash and cash equivalents at end of year.................. $ 15,683 $ 47,991 $ 15,263 ========= ========= =========
See accompanying notes to consolidated financial statements 51 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF BUSINESS Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain non-utility businesses. Through our natural gas utility business, we distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers through our six regulated natural gas utility divisions, which cover the following service areas:
DIVISION SERVICE AREA - -------- ------------ Atmos Energy Colorado-Kansas Division Colorado, Kansas, Missouri Atmos Energy Kentucky Division Kentucky Atmos Energy Louisiana Division Louisiana Atmos Energy Mid-States Division Georgia, Illinois, Iowa, Missouri, Tennessee, Virginia Atmos Energy Texas Division Texas Mississippi Valley Gas Company Division(1) Mississippi
- --------------- (1) Acquired in December 2002. See Note 3. In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the utility divisions operate. Our shared services unit is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas and Metairie, Louisiana. Our non-utility businesses are organized under Atmos Energy Holdings, Inc. and have operations in 18 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, LLC and Trans Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing, L.L.C, which was renamed Atmos Energy Marketing, LLC (AEM). AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services primarily consist of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative products. Our other non-utility businesses consist primarily of the operations of Atmos Pipeline and Storage, L.L.C. and Atmos Power Systems, Inc., which are wholly-owned subsidiaries of Atmos Energy Holdings, Inc. Through Atmos Pipeline and Storage, L.L.C, we own or have an interest in underground storage fields in Kansas, Kentucky and Louisiana. Additionally, Atmos Pipeline and Storage, L.L.C. contracts for storage service in underground storage facilities on many of the interstate pipelines serving us. Through Atmos Power Systems, Inc. we construct and operate electric peaking power generating plants and associated facilities and may enter into agreements to either lease or sell these plants. Finally, United Cities Propane Gas, Inc., a wholly-owned subsidiary of Atmos Energy Holdings, Inc., owns an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies. As of September 30, 2003, USP owned all of the general partnership interest and approximately 26 percent of the limited partnership interest in Heritage Propane Partners, L.P. a publicly traded marketer of propane through a nationwide retail distribution network. Through 52 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) our ownership in USP, we own an approximate five percent indirect interest in Heritage Propane Partners, L.P. On November 7, 2003, we announced that we and our utility partners had entered into an agreement to sell our interest in USP, including the general partnership and limited partnerships in Heritage Propane Partners, L.P., for $130.0 million. We expect to receive approximately $24.7 million and to record a $4.4 million pretax book gain upon closing of the transaction which is conditioned upon regulatory and other approvals. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated. Additionally, effective April 1, 2001, we consolidated the assets, liabilities and results of operations of Woodward Marketing, L.L.C. Prior to that time, we owned a 45 percent interest in Woodward Marketing, L.L.C. and accounted for that investment under the equity method of accounting for investments. Finally, we account for our investment in USP under the equity method of accounting for investments. BASIS OF COMPARISON Certain prior year amounts have been reclassified to conform with the current year presentation. USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, risk management and trading activities and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results could differ from those estimates. REGULATION Our utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be 53 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of September 30, 2003 and 2002 included the following:
SEPTEMBER 30 ----------------- 2003 2002 ------- ------- (IN THOUSANDS) REGULATORY ASSETS: Merger and integration costs, net......................... $23,380 $27,066 Deferred MVG operating expenses........................... 4,645 -- Environmental costs....................................... 4,057 3,754 Other..................................................... 2,509 4,878 ------- ------- $34,591 $35,698 ======= ======= REGULATORY LIABILITIES: Deferred income taxes, net................................ $ 1,883 $ 1,826
Merger and integration costs, net are amortized on a straight line basis over estimated useful lives ranging from 7 to 20 years. During the fiscal years ended September 30, 2003, 2002 and 2001, we recognized $8.2 million, $6.3 million and $5.8 million in amortization expense related to these costs. These costs will be substantially amortized in December 2005. At September 30, 2003, we had rate cases pending in our Kansas and West Texas jurisdictions. Additionally, we filed a rate case in our Lubbock, Texas system in October 2003. Finally, we are considering our response to an October 2003 ruling in our Mississippi jurisdiction which denied our request for a rate increase. REVENUE RECOGNITION Sales of natural gas to our utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for utility segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. Energy trading contracts resulting in the delivery of a commodity where we are the principal in the transaction are recorded as natural gas marketing sales or purchases at the time of physical delivery. Realized gains and losses from the settlement of financial instruments that do not result in physical delivery related to our natural gas marketing energy trading contracts and unrealized gains and losses from changes in the market value of open contracts are included as a component of natural gas marketing revenues. For the years ended September 30, 2003, 2002 and 2001, we included unrealized gains (losses) on open contracts of $6.3 million, ($10.5) million and $4.5 million as a component of natural gas marketing revenues. CASH AND CASH EQUIVALENTS We consider all highly liquid investments with an initial or remaining maturity of three months or less to be cash equivalents. ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS Accounts receivable consist of natural gas sales to residential, commercial, industrial, municipal, agricultural and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on an aging of those receivable balances. We apply percentages to each aging category based 54 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) on our collections experience. On certain other receivables where we are aware of a specific customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. GAS STORED UNDERGROUND Gas stored underground is valued using the average cost method for all our utility divisions, except for the Mid-States Division, where it is valued on the first-in first-out method. Gas stored underground and owned by Atmos Pipeline and Storage, L.L.C. is valued on the last-in first-out method. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost. UTILITY PROPERTY, PLANT AND EQUIPMENT Utility property, plant and equipment is stated at original cost net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes when the completed projects are placed in service. Interest expense of $0.8 million, $1.3 million and $1.2 million was capitalized in 2003, 2002 and 2001. Major renewals and betterments are capitalized while the costs of maintenance and repairs are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the utility plant in service account included in the rate base and depreciation begins. Utility property, plant and equipment is depreciated at various rates on a straight-line basis over the estimated useful lives of the assets. The composite rates are as follows: 2003....................... 3.8% 2002....................... 3.8% 2001....................... 3.7%
At the time property, plant and equipment is retired, the cost, plus removal expenses less salvage, is charged to accumulated depreciation. NON-UTILITY PROPERTY, PLANT AND EQUIPMENT Non-utility property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from 8 to 38 years. ASSET RETIREMENT OBLIGATION SFAS 143, Accounting for Asset Retirement Obligations which was effective for us October 1, 2002 requires that we record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense. As of September 30, 2003, we have no material asset retirement obligations. 55 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) IMPAIRMENT OF LONG-LIVED ASSETS We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded. To date, no impairment has been recognized. GOODWILL AND INTANGIBLE ASSETS We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit's goodwill exceeds its fair value. Intangible assets are amortized over their useful lives ranging from 3 to 10 years. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded. To date, no impairment has been recognized. MARKETABLE SECURITIES As of September 30, 2003 and 2002, all of our marketable securities are classified as available-for-sale securities based upon the criteria of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities. In accordance with that standard, these securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund's volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value. DERIVATIVES AND HEDGING ACTIVITIES Our derivative and hedging activities are tailored to the segment to which they relate. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent, based upon the anticipated settlement date of the underlying derivative. These assets and liabilities are recorded as components of other current assets, deferred charges and other assets, other current liabilities or deferred credits and other liabilities depending on the expiration or maturity date of the instrument. Utility Segment We use a combination of storage and financial hedges to protect us and our customers against unusually large winter period gas price increases. Our financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However, because these costs will ultimately be recovered through our rates, current period changes in the assets and liabilities from risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71 and recognized in purchased gas cost in the income statement when the related costs are 56 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) recovered through our rates. Accordingly, there is no earnings impact as a result of the use of these financial instruments. Natural Gas Marketing Segment The principal business of AEM is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the southeastern and midwestern United States. AEM also supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis. In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of financial derivatives, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. AEM links these financial derivatives to physical delivery of natural gas and typically balances its derivative positions at the end of each trading day. However, at any point in time, AEM may not have completely offset its risk on these activities. Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day. These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings. Compliance with this risk management policy is monitored on a daily basis. In addition, the risk management policy limits Woodward Marketing's Gas Daily Daily and NYMEX positions with price risk, including inventory, (open positions) to a total volume of 5.0 Bcf. We manage our business to maintain no open positions. However, at times, limited net open positions related to our physical storage may occur on a short term basis. Woodward Marketing's open trading positions are monitored daily but are not required to be closed if they remain within the limits set by the bank loan agreement. Those futures contracts that are designated as fair value hedges in accordance with SFAS 133 are recorded at fair value on the balance sheet with an offsetting adjustment to the underlying item being hedged. Those financial contracts that are not designated as hedges are recorded on the balance sheet at fair value with current period changes in these contracts recorded as net gains or losses in our natural gas marketing revenue on the consolidated statement of income. Generally, any price risk related to fixed price forward contracts that are marked to market through earnings is mitigated by offsetting futures contracts that are also marked to market through earnings. Any mark-to-market gains or losses on affiliate contracts are eliminated in consolidation. Changes in the valuation of assets and liabilities arising from risk management activities primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. Market prices and models used to value these transactions reflect our best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly 57 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) liquidation of our positions over a reasonable period of time under present market conditions. Changes in market prices directly affect our estimate of the fair value of these transactions. PENSION AND OTHER POSTRETIREMENT PLANS Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographical data. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The assumed return on plan assets is based on management's expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities generally is based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid. INCOME TAXES Income taxes are provided based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized. STOCK-BASED COMPENSATION PLANS We have two stock-based compensation plans that provide for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to officers, key employees and non-employee directors: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock. These plans are more fully described in Note 8. As permitted by SFAS 123, Accounting for Stock-Based Compensation we account for these plans under the intrinsic value method described in Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. Under this method, no compensation cost for stock options is recognized for stock option awards granted at or above fair market value. Awards of restricted stock are generally valued at the market price of the Company's common stock on the date of grant. The unearned compensation is amortized to operation and maintenance expense over the vesting period of the restricted stock. 58 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Had compensation expense for our stock options been recognized based on the fair value on the grant date under the methodology prescribed by SFAS 123, our net income and earnings per share for the years ended September 30, 2003, 2002 and 2001 would have been impacted as shown in the following table:
YEAR ENDED SEPTEMBER 30 --------------------------------------- 2003 2002 2001 ----------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income -- as reported................................. $71,688 $59,656 $56,090 Restricted stock compensation expense included in income, net of tax.............................................. 370 487 708 Total stock-based employee compensation expense determined under fair value based method for all awards, net of taxes................................................... (1,362) (974) (1,095) ------- ------- ------- Net income -- pro forma................................... $70,696 $59,169 $55,703 ======= ======= ======= Earnings per share: Basic earnings per share -- as reported................. $ 1.55 $ 1.45 $ 1.47 ======= ======= ======= Basic earnings per share -- pro forma................... $ 1.53 $ 1.44 $ 1.46 ======= ======= ======= Diluted earnings per share -- as reported............... $ 1.54 $ 1.45 $ 1.47 ======= ======= ======= Diluted earnings per share -- pro forma................. $ 1.52 $ 1.43 $ 1.46 ======= ======= =======
ACCOUNTING PRONOUNCEMENTS IMPLEMENTED In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Effective October 1, 2002, we adopted SFAS 143, which had no material impact to our financial position or results of operations based on the perpetual nature of our franchise agreements and on our experience in the businesses in which we operate. As more fully described in Note 5, on October 25, 2002, the Emerging Issues Task Force (EITF) issued EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Prior to the issuance of EITF 02-03, we accounted for all energy trading contracts under the mark-to-market method in accordance with EITF 98-10. Upon the adoption of EITF 02-03, our inventory, storage, transportation and index-priced physical forward contracts are no longer marked to market. Our index-priced physical forward contracts are now considered normal purchases and sales under SFAS 133. Accordingly, the carrying value of these contracts was frozen as of January 1, 2003 and will be recognized in earnings concurrent with delivery under the contracts. We recognized a charge for the cumulative effect of accounting change of $7.8 million, net of income tax benefit, upon the adoption of EITF 02-03 in the second quarter of fiscal 2003. Fixed price contracts generally continue to be marked to market. In conjunction with the adoption of EITF 02-03, energy trading contracts resulting in delivery of a commodity where we are the principal in the transaction are included as natural gas marketing sales or purchases. All prior periods have been reclassified to conform with this new presentation. In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based Compensation. SFAS 148 provides three transition options for companies that account for stock-based compensation under the intrinsic method to convert to the fair value method. SFAS 148 also modified the disclosure requirements for stock-based compensation to increase the prominence and character of the pro forma disclosures for entities using 59 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the intrinsic value method. Although we have elected to continue using the intrinsic value method, we adopted the disclosure requirements prescribed by SFAS 148. In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies the accounting and reporting for derivative instruments, including hedges. This statement amends SFAS 133 for decisions made by the Derivatives Implementation Group and by the FASB in connection with other projects dealing with financial instruments, and clarifies other implementation issues. SFAS 149 is effective for the Company on a prospective basis for contracts entered into or modified after June 30, 2003. The adoption of this statement did not have a material impact on our financial position, results of operations or net cash flows. In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer's shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for most previously existing financial instruments. In November 2003, the FASB voted to defer indefinitely the effective date for certain mandatorily redeemable non-controlling interests (MRNI) associated with finite-lived subsidiaries. For all other MRNIs, the effective date was deferred to November 5, 2003. The adoption of SFAS 150 did not impact our financial position, results of operations or net cash flows as we currently do not use any of the financial instruments subject to this statement. In November 2002, the FASB issued FASB Interpretation (FIN) 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 clarifies the requirements of SFAS 5, Accounting For Obligations, relating to a guarantor's accounting for, and disclosure of the issuance of certain types of guarantees. The adoption of FIN 45 did not impact our financial position, results of operations or net cash flows as we currently do not have any guarantees that meet the recognition and disclosure criteria outlined in this pronouncement. In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation will not have a material impact on our financial position, results of operations or net cash flows because Atmos currently is not a primary beneficiary of a VIE. 3. ACQUISITIONS ACQUISITION OF MISSISSIPPI VALLEY GAS COMPANY On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), Mississippi's largest natural gas utility, which enabled us to expand our service area into Mississippi. MVG served approximately 261,500 residential, commercial, industrial and other customers located primarily in the 60 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) northern and central regions of Mississippi. We paid approximately $74.7 million in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. We also repaid approximately $70.9 million of MVG's outstanding debt. The results of operations of MVG have been consolidated with our results of operations from the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed, in thousands: Net property, plant and equipment........................... $156,516 Current assets.............................................. 42,576 Rights-of-way............................................... 11,746 Goodwill.................................................... 81,550 Deferred charges and other assets........................... 9,642 -------- Total assets acquired..................................... 302,030 Current liabilities......................................... (47,750) Noncurrent liabilities...................................... (81,753) Other acquisition related costs............................. (23,227) -------- Purchase price............................................ $149,300 ========
The value assigned to goodwill was based on our belief that the acquisition of MVG will enable us to leverage our existing technology in order to add value to Atmos. This goodwill is not deductible for tax purposes. Other acquisition-related costs consist of $13.1 million of make-whole premiums related to the repayment of MVG's debt and other costs including termination benefits. The table below reflects the unaudited pro forma results of the Company and MVG for the years ended September 30, 2003 and 2002 as if the acquisition had taken place at the beginning of fiscal 2002.
SEPTEMBER 30 ----------------------- 2003 2002 ---------- ---------- (UNAUDITED) (IN THOUSANDS) Operating revenue........................................... $2,835,673 $1,870,090 Income before cumulative effect of accounting change........ 76,293 69,295 Net income.................................................. 68,520 69,295 Income before cumulative effect of accounting change per diluted share............................................. $ 1.62 $ 1.55 Net income per diluted share................................ $ 1.46 $ 1.55
ACQUISITION OF REMAINING EQUITY INTEREST IN WOODWARD MARKETING, L.L.C. In April 2001, we acquired from Woodward Marketing, Inc. the 55 percent interest in Woodward Marketing, L.L.C. that we did not already own in exchange for 1,423,193 restricted shares of our common stock with a value of $26.7 million. The consideration is subject to a potential upward adjustment, based on our share price, of up to 232,547 shares plus an amount of shares to compensate for dividends paid after the completion of the acquisition. The adjustment period expires on March 31, 2006. ACQUISITION OF NATURAL GAS OPERATIONS IN LOUISIANA Effective July 1, 2001, we acquired the assets of Louisiana Gas Service Company and LGS Natural Gas Company (collectively referred to as LGS) for $363.4 million. The acquired assets provide natural gas 61 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) distribution service through approximately 279,000 residential and commercial meters in southeastern and northern Louisiana. The service territory includes the suburban areas of metropolitan New Orleans (excluding Orleans Parish), the north shore of Lake Pontchartrain and the Monroe/West Monroe metropolitan area. The non-utility operations include a natural gas marketing company and an intrastate pipeline company which provides gas transportation service to industrial customers in Louisiana and to the acquired assets. The acquisition increased the size of our operations in Louisiana and allowed us to achieve certain synergies and cost savings by combining the acquired operations with our existing Louisiana operations. The acquisition was financed through the issuance of $350.0 million of unsecured 7.375% Senior Notes due in 2011. 4. GOODWILL AND INTANGIBLE ASSETS Goodwill and intangible assets are comprised of the following as of September 30, 2003 and 2002.
SEPTEMBER 30 ------------------- 2003 2002 -------- -------- (IN THOUSANDS) Goodwill.................................................... $268,469 $185,015 Intangible assets........................................... 5,030 5,365 -------- -------- Total....................................................... $273,499 $190,380 ======== ========
The following presents our goodwill balance allocated by segment and changes in our balance for the year ended September 30, 2003:
NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY SEGMENT SEGMENT SEGMENT TOTAL -------- ----------- ----------- -------- (IN THOUSANDS) Balance as of September 30, 2002......... $150,287 $21,288 $13,440 $185,015 Acquisition of MVG (See Note 3).......... 81,550 -- -- 81,550 Deferred tax adjustments and reclassifications...................... 1,904 1,312 (1,312) 1,904 -------- ------- ------- -------- Balance as of September 30, 2003......... $233,741 $22,600 $12,128 $268,469 ======== ======= ======= ========
Effective October 1, 2001, we adopted the provisions of SFAS 142, Goodwill and Other Intangible Assets. Goodwill applicable to the utility segment primarily arose from our July 1, 2001 acquisition of the assets of LGS and our December 3, 2002 acquisition of MVG. This goodwill is not subject to amortization under SFAS 142. Goodwill applicable to the Natural Gas Marketing Segment was amortized over 20 years prior to the adoption of SFAS 142. The proforma effect of adopting SFAS 142 would be to increase net income by $0.3 million for fiscal 2001. SFAS 142 requires that we evaluate our goodwill balances for impairment on an annual basis or when impairment indicators arise. We performed our annual evaluation during the quarter ended March 31, 2003 which resulted in no impairment. No indicators have arisen since that time that would indicate that our goodwill balance is impaired. 62 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Information regarding our intangible assets is included in the following table. As of September 30, 2003 and 2002, we had no indefinite-lived intangible assets:
SEPTEMBER 30, 2003 SEPTEMBER 30, 2002 -------------------------------- -------------------------------- USEFUL GROSS GROSS LIFE CARRYING ACCUMULATED CARRYING ACCUMULATED (YEARS) AMOUNT AMORTIZATION NET AMOUNT AMORTIZATION NET ------- -------- ------------ ------ -------- ------------ ------ (IN THOUSANDS) Customer contracts............... 10 $6,521 $(1,574) $4,947 $6,521 $(1,323) $5,198 Noncompete agreements............ 3 250 (167) 83 250 (83) 167 ------ ------- ------ ------ ------- ------ $6,771 $(1,741) $5,030 $6,771 $(1,406) $5,365 ====== ======= ====== ====== ======= ======
The following table presents actual amortization expense recognized during 2003 and an estimate of future amortization expense based upon our intangible assets at September 30, 2003. AMORTIZATION EXPENSE (IN THOUSANDS): Actual for the fiscal year ending September 30, 2003........ $335 Estimated for the fiscal year ending: September 30, 2004........................................ 870 September 30, 2005........................................ 652 September 30, 2006........................................ 585 September 30, 2007........................................ 585 September 30, 2008........................................ 585
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We conduct our risk management activities through both our utility and natural gas marketing segments. The following table shows our risk management assets and liabilities by segment at September 30, 2003 and 2002:
NATURAL GAS UTILITY MARKETING TOTAL ------- ----------- ------- (IN THOUSANDS) SEPTEMBER 30, 2003: Assets from risk management activities, current....... $ 202 $22,057 $22,259 Assets from risk management activities, noncurrent.... -- 1,699 1,699 Liabilities from risk management activities, current............................................. (7,941) (12,849) (20,790) Liabilities from risk management activities, noncurrent.......................................... -- (763) (763) ------- ------- ------- Net assets (liabilities).............................. $(7,739) $10,144 $ 2,405 ======= ======= ======= SEPTEMBER 30, 2002: Assets from risk management activities, current....... $ 4,424 $23,560 $27,984 Assets from risk management activities, noncurrent.... -- 5,241 5,241 Liabilities from risk management activities, current............................................. -- (18,487) (18,487) Liabilities from risk management activities, noncurrent.......................................... -- (3,663) (3,663) ------- ------- ------- Net assets............................................ $ 4,424 $ 6,651 $11,075 ======= ======= =======
63 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table shows the components of the change in fair value of our utility and natural gas marketing derivative contract activities for the year ended September 30, 2003 (in thousands).
NATURAL GAS UTILITY MARKETING ------- ----------- Fair value of contracts at September 30, 2002............... $ 4,424 $ 6,651 Contracts realized/settled................................ (4,638) (1,363) Fair value of new contracts............................... (7,525) 6,176 Other changes in value.................................... -- 7,479 Cumulative effect of accounting change.................... -- (8,799) ------- ------- Fair value of contracts at September 30, 2003............... $(7,739) $10,144 ======= =======
UTILITY HEDGING ACTIVITIES For the 2002-2003 heating season, we covered approximately 51 percent of our anticipated flowing gas requirements through a combination of storage, financial hedges and fixed forward contracts at a weighted average cost of less than $4.00 per Mcf. This provided a measure of protection to us and our customers against the natural gas price volatility experienced during the 2002-2003 winter heating season. NON-UTILITY HEDGING ACTIVITIES Our non-utility hedging activities are conducted through AEM. AEM manages margins and limits risk exposure on natural gas inventory, fixed-price physical forwards, and purchases and sales of Gas Daily Daily natural gas through the use of financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. We manage our business to maintain no open positions. However, at times, limited net open positions related to our physical storage may occur on a short term basis. At the close of business on September 30, 2003 and 2002, AEM had a net open position (including inventory) of 0.1 Bcf and 1.9 Bcf. As of September 2003 and 2002, contracts representing 99 and 97 percent of the fair value of these contracts are scheduled to mature within three years. Financial instruments, which subject AEM to counterparty risk, consist primarily of financial instruments arising from trading and risk management activities that are not insured. Counterparty risk is the risk of loss from nonperformance by financial counterparties to a contract. Exchange-traded future and option contracts are generally guaranteed by the exchanges. Adoption of EITF 02-03 On October 25, 2002, the EITF issued EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Prior to the issuance of EITF 02-03, we accounted for all energy trading contracts under the mark-to-market method in accordance with EITF 98-10. Prior to December 31, 2002, we had recorded $12.9 million ($7.8 million, net of tax) of unrealized income related to our storage and transportation contracts and certain full requirements contracts in accordance with EITF 98-10. On January 1, 2003, we reversed this unrealized income, which was reported as a non-cash cumulative effect of a change in accounting principle in accordance with APB 20, Accounting Changes. 64 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Additionally, beginning January 1, 2003, all energy trading contracts are being accounted for pursuant to the provisions of SFAS 133. As a result, many of our index-priced physical forward contracts qualify for the normal purchases and sales exception under SFAS 133 and are not marked to market for changes in value subsequent to December 31, 2002. The carrying value of these contracts as of January 1, 2003 was frozen and will be recognized in earnings concurrent with delivery under the contracts. Fixed price contracts generally continue to be marked to market. In conjunction with the adoption of EITF 02-03, energy trading contracts resulting in delivery of a commodity where we are the principal in the transaction are included as natural gas marketing sales or purchases. All prior year periods have been reclassified to conform with this new presentation. Finally, effective January 1, 2003, we designated a portion of our futures contracts as fair value hedges of the natural gas marketing segment's gas inventory. Accordingly, the inventory was adjusted to cost as of January 1, 2003 as part of the cumulative effect adjustment, and subsequent changes in fair value will be recognized as an adjustment to the carrying value of the hedged inventory. WEATHER INSURANCE In June 2001, we purchased a three year weather insurance policy with an option to cancel the third year of coverage. The insurance was designed for our Texas and Louisiana operations to protect against weather that was at least seven percent warmer than normal for the entire heating season of October through March beginning with the 2001-2002 heating season. The cost of the three year policy was $13.2 million, which was prepaid and was amortized over the appropriate heating seasons based on degree days. Amortization expense of $5.0 million and $4.4 million was recognized during the fiscal years ended September 30, 2003 and 2002. Included in the amortization expense for fiscal 2003 was a third quarter charge of $0.6 million, net of cash received, related to the cancellation of the third year of coverage on our weather insurance policy primarily as a result of rate relief in Louisiana and prospects for weather normalization adjustments in Texas. Because weather was not at least seven percent warmer than normal, no income was recognized under this insurance policy during fiscal 2003 and 2002. 65 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 6. DEBT LONG-TERM DEBT Long-term debt at September 30, 2003 and 2002 consisted of the following:
2003 2002 -------- -------- (IN THOUSANDS) Unsecured 11.2% Senior Notes, due 2002, payable in annual installments of $2,000.................................... $ -- $ 2,000 Unsecured 9.76% Senior Notes, due 2004, payable in annual installments of $3,000.................................... -- 9,000 Unsecured 9.57% Senior Notes, due 2006, payable in annual installments of $2,000.................................... -- 8,000 Unsecured 7.95% Senior Notes, due 2006, payable in annual installments of $1,000.................................... -- 4,000 Unsecured 8.07% Senior Notes, due 2006, payable in annual installments of $4,000 beginning 2002..................... -- 20,000 Unsecured 10% Notes, due 2011............................... 2,303 2,303 Unsecured 7.375% Senior Notes, due 2011..................... 350,000 350,000 Unsecured 5.125% Senior Notes, due 2013..................... 250,000 -- Unsecured 8.26% Senior Notes, due 2014, payable in annual installments of $1,818 beginning 2004..................... -- 20,000 Medium term notes Series A, 1995-2, 6.27%, due 2010......................... 10,000 10,000 Series A, 1995-1, 6.67%, due 2025......................... 10,000 10,000 Unsecured 6.75% Debentures, due 2028........................ 150,000 150,000 First Mortgage Bonds Series J, 9.40% due 2021.................................. 17,000 17,000 Series P, 10.43% due 2017................................. 13,750 16,250 Series Q, 9.75% due 2020.................................. 17,000 18,000 Series R, 11.32% due 2004................................. 2,160 4,300 Series T, 9.32% due 2021.................................. 18,000 18,000 Series U, 8.77% due 2022.................................. 20,000 20,000 Series V, 7.50% due 2007.................................. 6,733 10,000 Rental property, propane and other term notes due in installments through 2013................................. 6,317 3,590 -------- -------- Total long-term debt................................... 873,263 692,443 Less current maturities..................................... (9,345) (21,980) -------- -------- $863,918 $670,463 ======== ========
Most of the First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1988 may not exceed the sum of accumulated net income for periods after December 31, 1988 plus $15.0 million. At 66 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) September 30, 2003, approximately $84.1 million of retained earnings was unrestricted. We are in compliance with all of our debt covenants as of September 30, 2003. In December 2001, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $600.0 million in new common stock and/or debt. The registration statement was declared effective by the SEC on January 30, 2002. On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes. Additionally, as further discussed in Note 7, we sold 4,100,000 shares of our common stock in connection with our 2003 Offering under the registration statement. After the debt offering and these common stock sales, approximately $246.0 million remains available under the shelf registration statement. As of September 30, 2003, all of the Colorado-Kansas Division utility plant assets with a net book value of approximately $194.5 million were subject to a lien under the 9.4 percent Series J First Mortgage Bonds assumed by us in the acquisition of Greeley Gas Company. Also, substantially all of the Mid-States Division utility plant assets, totaling $345.1 million, were subject to a lien under the Indenture of Mortgage of the Series P through V First Mortgage Bonds. Based on the borrowing rates currently available to us for debt with similar terms and remaining average maturities, the fair value of long-term debt at September 30, 2003 and 2002 is estimated, using discounted cash flow analysis, to be $1,003.9 million and $775.5 million. Maturities of long-term debt at September 30, 2003 were as follows (in thousands): 2004............................................. $ 9,345 2005............................................. 4,990 2006............................................. 6,088 2007............................................. 6,374 2008............................................. 6,132 Thereafter....................................... 840,334 -------- $873,263 ========
SHORT-TERM DEBT At September 30, 2003, short-term debt consisted of $118.6 million of commercial paper. At September 30, 2002, short-term debt was composed of $132.7 million of commercial paper and $13.1 million outstanding under bank credit facilities. The weighted average interest rate on short-term borrowings outstanding was 1.7 percent and 2.3 percent at September 30, 2003 and 2002. CREDIT FACILITIES We maintain both committed and uncommitted credit facilities. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder months. Our working capital needs can vary significantly due to changes in the price of natural gas charged by suppliers and the increased gas supplies required to meet customers' needs during periods of cold weather. 67 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Committed Credit Facilities We have two short-term committed credit facilities totaling $368.0 million. The first short-term unsecured credit facility is for $350.0 million, bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our commercial paper program. This facility was renewed in July 2003 with a $50.0 million increase in the amount of the facility under substantially the same terms as those of the prior facility. This facility will expire in July 2004. At September 30, 2003, $118.6 million of commercial paper was outstanding, and Atmos Energy Corporation letters of credit reduced the amount available by an additional $2.4 million. We have a second unsecured facility in place for $18.0 million that bears interest at the Fed Funds rate plus 0.5 percent. At September 30, 2003, there were no borrowings under this credit facility. These credit facilities are negotiated at least annually and are used for working capital purposes. On October 7, 2002, we entered into a $150.0 million short-term unsecured committed credit facility. This credit facility was used to provide initial funding for the cash portion of the MVG acquisition and to repay MVG's existing debt. A total of $147.0 million was borrowed under this credit facility during the first quarter. This amount was refinanced in January 2003 with a portion of the proceeds of our $250.0 million debt offering, as discussed above. The availability of funds under our credit facilities is subject to conditions specified therein, which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our $350.0 million credit facility to maintain a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2003, our total debt to total capitalization ratio, as defined, was 55 percent. Uncommitted Credit Facilities Our Woodward Marketing subsidiary has a $210.0 million uncommitted demand working capital credit facility that bears interest at LIBOR plus 2.5 percent. Atmos Energy Holdings, Inc. (AEH) and AEM, our wholly-owned subsidiaries, are guarantors of all amounts outstanding under this facility. Effective October 1, 2003 with the reorganization of our natural gas marketing segment, AEM became the borrower under the credit facility and AEH became the sole guarantor of the facility. At September 30, 2003, no amount was outstanding under this credit facility, although Woodward Marketing, L.L.C. letters of credit totaling $76.9 million reduced the amount available. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to Woodward Marketing under this credit facility at September 30, 2003 was $28.3 million. This credit facility expires on March 31, 2004 and is expected to be renewed at that time. We also have an unsecured short-term uncommitted credit line for $20.0 million. There were no borrowings under this uncommitted credit facility at September 30, 2003. This uncommitted line is renewed or renegotiated at least annually with varying terms and we pay no fee for the availability of the line. Borrowings under this line are made on a when and as-available basis at the discretion of the bank. This facility is also used for working capital purposes. In October 2003, we increased the amount of this credit line to $25.0 million. In addition, Woodward Marketing has a $100.0 million intercompany credit facility with AEH for its non-utility business which bore interest at LIBOR plus 1.25 percent through July 2003 when the interest rate was increased to LIBOR plus 2.75%. Any outstanding amounts under this facility are subordinated to Woodward Marketing's $210.0 million uncommitted demand credit facility described above. At September 30, 2003, $70.0 million was outstanding under this facility. 68 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 7. SHAREHOLDERS' EQUITY On June 23, 2003, we completed a public offering of 4,000,000 shares of our common stock, and we sold an additional 100,000 shares of our common stock in July 2003 when our underwriters exercised their overallotment option (collectively referred to as the 2003 Offering). The 2003 Offering was priced at $25.31 per share and generated net proceeds of approximately $99.2 million. The proceeds were used to partially fund our pension plan, to repay short-term debt and to fund general corporate purposes including the purchase of natural gas for storage. We have a Rights Agreement under which each right (Right) will entitle the holder thereof, until May 10, 2008 or the date of redemption of the Rights, to buy 1/10 of one share of Common Stock of Atmos at the exercise price of $8.00, subject to adjustment. At no time will the Rights have any voting rights. The exercise price payable and the number of shares of Common Stock or other securities or property issuable upon exercise of the Rights are subject to adjustment from time to time to prevent dilution. At the date upon which the Rights become separate from our Common Stock (the Distribution Date), we will issue one right with each share of Common Stock that becomes outstanding so that all shares of Common Stock will have attached Rights. After the Distribution Date, we may issue Rights when we issue Common Stock if the Board deems such issuance to be necessary or appropriate. The Rights will separate from the Common Stock and a Distribution Date will occur upon the occurrence of certain events specified in the Rights Agreement, including but not limited to, the acquisition by certain persons of at least 15 percent of the beneficial ownership of our Common Stock. The Rights have certain anti-takeover effects and may cause substantial dilution to a person or entity that attempts to acquire the Company on terms not approved by the Board of Directors except pursuant to an offer conditioned upon a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by the Board of Directors because, prior to the time that the Rights become exercisable or transferable, the Rights may be redeemed by us at $.01 per Right. 8. STOCK AND OTHER COMPENSATION PLANS STOCK-BASED COMPENSATION PLANS We have two stock-based compensation plans that provide for the granting of stock options and restricted stock to officers, key employees and non-employee directors: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock. 1998 Long-Term Incentive Plan On August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by the shareholders of Atmos. The Long-Term Incentive Plan is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. We are authorized to grant awards for up to a maximum of 4,000,000 shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2003, non-qualified stock options, bonus stock and restricted stock have been issued under this plan, and 1,923,464 shares were available for issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years. 69 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A summary of activity for grants of stock options under the 1998 Long-Term Incentive Plan follows:
2003 2002 2001 -------------------- -------------------- -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE NUMBER OF EXERCISE NUMBER OF EXERCISE NUMBER OF EXERCISE OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE --------- -------- --------- -------- --------- -------- Outstanding at beginning of year......................... 1,557,606 $21.87 1,009,330 $21.43 658,500 $19.76 Granted...................... 411,860 21.37 607,877 22.35 439,500 23.45 Exercised.................... (92,989) 17.79 (19,102) 16.69 (17,172) 15.82 Forfeited.................... (49,167) 23.89 (40,499) 20.53 (71,498) 19.86 --------- ------ --------- ------ --------- ------ Outstanding at end of year..... 1,827,310 $21.91 1,557,606 $21.87 1,009,330 $21.43 ========= ====== ========= ====== ========= ====== Exercisable at end of year..... 868,199 $21.69 532,729 $21.81 285,448 $21.37 ========= ====== ========= ====== ========= ======
Information about outstanding and exercisable options under the Long-Term Incentive Plan, as of September 30, 2003, follows:
OPTIONS OUTSTANDING ---------------------------------- WEIGHTED OPTIONS EXERCISABLE AVERAGE -------------------- REMAINING WEIGHTED WEIGHTED CONTRACTUAL AVERAGE AVERAGE NUMBER OF LIFE EXERCISE NUMBER OF EXERCISE RANGE OF EXERCISE PRICES OPTIONS (IN YEARS) PRICE OPTIONS PRICE - ------------------------ --------- ----------- -------- --------- -------- $14.68 to $17.49................. 183,898 6.4 $15.62 183,898 $15.62 $17.50 to $20.24................. 24,000 6.9 $19.74 24,000 $19.74 $20.25 to $22.99................. 1,017,912 8.7 $21.93 206,834 $22.29 $23.00 to $25.66................. 601,500 6.8 $23.88 453,467 $23.99 --------- ------- $14.68 to $25.66................. 1,827,310 7.8 $21.91 868,199 $21.69 ========= =======
The stock options had a weighted average fair value per share on the date of grant of $3.32 in 2003, $3.55 in 2002 and $3.97 in 2001. We used the Black-Scholes pricing model to estimate the fair value of each option granted with the following weighted average assumptions for 2003, 2002 and 2001:
YEAR ENDED SEPTEMBER 30 ------------------ 2003 2002 2001 ---- ---- ---- Expected Life (years)....................................... 7 7 5 Interest rate............................................... 4.0% 3.9% 4.7% Volatility.................................................. 23.3% 24.2% 25.5% Dividend yield.............................................. 4.8% 4.8% 4.9%
Long-Term Stock Plan for the Mid-States Division Prior to the merger with Atmos, certain United Cities Gas Company officers and key employees participated in the United Cities Long-Term Stock Plan implemented in 1989. At the time of the merger on July 31, 1997, Atmos adopted this plan by registering a total of 250,000 shares of Atmos stock to be issued under the Long-Term Stock Plan for the Mid-States Division. Under this plan, incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock or any combination thereof may be granted to officers and key employees of the Mid-States Division. Options granted under the plan become exercisable at a rate of 20 percent per year and expire 10 years after the date of grant. No awards have been 70 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) granted under this plan since 1996. During 2003, 13,000 options were exercised under the plan. At September 30, 2003, there were 6,300 options outstanding, all of which were fully vested. Because of the limited activities of this plan, the pro forma effects of applying SFAS 123 would have less than a $0.01 per diluted share effect on earnings per share. RESTRICTED STOCK PLANS As noted above, the 1998 Long-Term Incentive Plan provides for discretionary awards of restricted stock to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. Additionally, from October 1, 1987 through February 2002, we maintained a Restricted Stock Grant Plan for our management and key employees, which provided awards of common stock that were subject to certain restrictions. This plan was administered by the non-employee members of the Board of Directors, who made final determinations regarding participation in the Plan, awards under the Plan and restrictions on the restricted stock awarded. The following summarizes information regarding the restricted stock plans:
YEAR ENDED SEPTEMBER 30 ---------------------------- 2003 2002 2001 -------- ------- ------- Shares granted during the year......................... 82,933 22,204 -- Weighted average intrinsic value....................... $ 21.34 $ 21.30 -- Compensation expense recognized, net of tax (in thousands)........................................... $ 370 $ 487 $ 708 Unexpired shares with unmet restrictions at September 30................................................... 101,486 54,079 79,575
OTHER PLANS Direct Stock Purchase Plan We maintain a Direct Stock Purchase Plan which allows participants to have all or part of their dividends reinvested at a three percent discount from market prices. Direct Stock Purchase Plan participants may purchase additional shares of Atmos common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000. Outside Directors Stock-For-Fee Plan In November 1994, the Board adopted the Outside Directors Stock-for-Fee Plan which was approved by the shareholders of Atmos in February 1995 and was amended and restated in November 1997. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash. Equity Incentive and Deferred Compensation Plan for Non-Employee Directors In November 1998, the Board of Directors adopted the Equity Incentive and Deferred Compensation Plan for Non-Employee Directors which was approved by the shareholders of Atmos in February 1999. This plan amended the Atmos Energy Corporation Deferred Compensation Plan for Outside Directors adopted by the Company on May 10, 1990 and replaced the pension payable under the Company's Retirement Plan for Non-Employee Directors. The plan provides non-employee directors of Atmos with the opportunity to defer receipt of compensation for services rendered to the Company, invest deferred compensation into either a cash account or a stock account and to receive an annual grant of share units for each year of service on the Board. Variable Pay Plan The Variable Pay Plan was created to give each employee an opportunity to share in the success of Atmos based on the achievement of key performance measures considered critical to achieving business objectives for 71 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) a given year. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded. 9. RETIREMENT AND POST-RETIREMENT EMPLOYEE BENEFIT PLANS We have both funded and unfunded noncontributory defined benefit plans that together cover substantially all of our employees. We also maintain a post-retirement plan that provides health care benefits to retired employees. Finally, we sponsor a defined contribution plan which covers substantially all employees. These plans are discussed in further detail below. DEFINED BENEFIT PLANS Employee Pension Plans As of September 30, 2003, we maintain two defined benefit plans: the Atmos Energy Corporation Pension Account Plan and the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. Both plans are held within the Atmos Energy Corporation Master Retirement Trust. The Atmos Energy Corporation Pension Account Plan (the Plan) was established effective January 1, 1999 and covers substantially all employees of Atmos. Opening account balances were established for participants as of January 1, 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant's account at the end of each year according to a formula based on the participant's age, service and total pay (excluding incentive pay). The Plan also provides for an additional annual allocation based upon a participant's age as of January 1, 1999 for those participants who were participants in the prior pension plans. The Plan will credit this additional allocation each year through December 31, 2008. In addition, at the end of each year, a participant's account will be credited with interest on the employee's prior year account balance. A special grandfather benefit also applies through December 31, 2008, for participants who were at least age 50 as of January 1, 1999, and who were participants in one of the prior plans on December 31, 1998. Participants fully vest in their account balances after five years of service and may choose to receive their account balances as a lump sum or an annuity. MVG maintained a defined benefit plan that covered substantially all full-time employees. On June 30, 2003, all retirees and the active non-union employees became eligible to participate in the Plan. Active union employees will remain in MVG's plan, which was renamed the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees on July 1, 2003. Under this plan, benefits are based upon years of benefit service and average final earnings. Participants vest in the plan after five years and will receive their benefit in an annuity. Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. However, additional voluntary contributions are made from time to time as considered necessary. 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. 72 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Plan's assets consist primarily of investments in common stocks, interest bearing securities and interests in commingled pension trust funds. The following table presents the Plan's funded status for 2003 and 2002.
2003 2002 -------- -------- (IN THOUSANDS) CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year................... $226,197 $210,878 Service cost.............................................. 6,693 5,247 Interest cost............................................. 19,044 15,544 Actuarial loss............................................ 47,410 12,732 MVG acquisition........................................... 52,210 -- Plan amendments........................................... (1,771) -- Benefits paid............................................. (19,439) (18,204) -------- -------- Benefit obligation at end of year......................... 330,344 226,197 CHANGE IN PLAN ASSETS: Fair value of plan assets at beginning of year............ 209,941 246,327 Actual return on plan assets.............................. 8,513 (18,182) MVG acquisition........................................... 46,326 -- Employer contributions.................................... 77,362 -- Benefits paid............................................. (19,439) (18,204) -------- -------- Fair value of plan assets at end of year.................. 322,703 209,941 -------- -------- RECONCILIATION: Funded status............................................. (7,641) (16,256) Unrecognized prior service cost........................... (7,995) (7,112) Unrecognized net loss..................................... 132,332 71,233 -------- -------- Net amount recognized..................................... $116,696 $ 47,865 ======== ========
The actuarial assumptions used to determine the pension liability for the Plan are as follows:
2003 2002 2001 ----- ----- ------ Discount rate............................................... 6.00% 7.25% 7.50% Rate of compensation increase............................... 4.00% 4.00% 4.00% Expected return on plan assets.............................. 9.00% 9.25% 10.00%
In June 2003, we contributed to the Atmos Energy Corporation Master Retirement Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. Of the total cash contributed, $26.1 million represented a 2002 contribution, which was deducted on our 2002 tax return. The cash contribution was financed through a combination of cash on hand and a portion of the net proceeds received from the sale of 4,100,000 shares of our common stock in our 2003 Offering. As a result of this contribution and improved investment returns during fiscal 2003, the under funded status of the plan improved by approximately $8.6 million, and the $39.4 million reduction to equity recorded in the prior year was eliminated as of September 30, 2003. The Plan was underfunded at September 30, 2002 primarily due to negative investment returns from plan assets during fiscal 2002, lump sum distributions to participants and a decrease in interest rates. As a result, we 73 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) recorded a minimum pension liability of $63.6 million before applicable income taxes as of September 30, 2002, which decreased shareholders' equity by $39.4 million. Net periodic pension cost for the Plan for 2003, 2002 and 2001 is recorded as a component of operating expense and included the following components:
YEAR ENDED SEPTEMBER 30 ------------------------------ 2003 2002 2001 -------- -------- -------- (IN THOUSANDS) Components of net periodic pension cost: Service cost....................................... $ 6,693 $ 5,247 $ 3,557 Interest cost...................................... 19,044 15,544 16,408 Expected return on assets.......................... (23,950) (23,298) (27,093) Amortization of transition asset................... -- (72) (290) Amortization of prior service cost................. (883) (883) (883) Recognized actuarial gain.......................... 1,756 -- -- -------- -------- -------- Net periodic pension cost....................... $ 2,660 $ (3,462) $ (8,301) ======== ======== ========
Supplemental Executive Benefits Plans We have a nonqualified Supplemental Executive Benefits Plan which provides additional pension, disability and death benefits to the officers and certain other employees of Atmos. The Supplemental Plan was amended and restated in August 1998. In addition, in August 1998, we adopted the Performance-Based Supplemental Executive Benefits Plan which covers all employees who become officers or division presidents after August 12, 1998 or any other employees selected by our Board of Directors in its discretion. 74 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table presents the funded status of the supplemental plans for 2003 and 2002:
2003 2002 -------- -------- (IN THOUSANDS) CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year................... $ 59,152 $ 52,845 Service cost.............................................. 1,548 1,028 Interest cost............................................. 4,294 3,938 Actuarial loss............................................ 9,900 4,227 Benefits paid............................................. (3,235) (2,886) -------- -------- Benefit obligation at end of year......................... 71,659 59,152 CHANGE IN PLAN ASSETS: Fair value of plan assets at beginning of year............ -- -- Employer contribution..................................... 3,235 2,886 Benefits paid............................................. (3,235) (2,886) -------- -------- Fair value of plan assets at end of year.................. -- -- -------- -------- RECONCILIATION: Funded status............................................. (71,659) (59,152) Unrecognized transition obligation........................ 100 196 Unrecognized prior service cost........................... 4,750 5,772 Unrecognized net loss..................................... 24,349 15,221 -------- -------- Accrued pension cost...................................... $(42,460) $(37,963) ======== ========
The net liability for the supplemental plans is recorded as a component of deferred credits and other liabilities. The actuarial assumptions used to determine the pension liability for the supplemental plans are as follows:
2003 2002 2001 ---- ---- ---- Discount rate............................................... 6.00% 7.25% 7.50% Rate of compensation increase............................... 4.00% 4.00% 4.00% Expected return on plan assets.............................. NA NA NA
75 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Assets for the supplemental plans are held in separate rabbi trusts and comprise the following:
UNREALIZED HOLDING MARKET COST GAIN (LOSS) VALUE ------- ----------- ------- (IN THOUSANDS) AS OF SEPTEMBER 30, 2003: Domestic equity mutual funds........................ $28,540 $(2,359) $26,181 Foreign equity mutual funds......................... 3,195 9 3,204 ------- ------- ------- $31,735 $(2,350) $29,385 ======= ======= ======= AS OF SEPTEMBER 30, 2002: Domestic equity mutual funds........................ $28,788 $(3,113) $25,675 Foreign equity mutual funds......................... 2,087 (27) 2,060 ------- ------- ------- $30,875 $(3,140) $27,735 ======= ======= =======
Net periodic pension cost for the supplemental plans for 2003, 2002 and 2001 is recorded as a component of operating expense and included the following components:
YEAR ENDED SEPTEMBER 30 ------------------------ 2003 2002 2001 ------ ------ ------ (IN THOUSANDS) Components of net periodic pension cost: Service cost............................................. $1,548 $1,028 $ 832 Interest cost............................................ 4,294 3,938 3,751 Amortization of transition asset......................... 96 96 96 Amortization of prior service cost....................... 1,022 1,022 1,022 Recognized actuarial loss................................ 772 542 325 ------ ------ ------ Net periodic pension cost............................. $7,732 $6,626 $6,026 ====== ====== ======
Supplemental Disclosures For Defined Benefit Plans with Accumulated Benefit Obligations in Excess of Plan Assets The following summarizes key information for defined benefit plans with accumulated benefit obligations in excess of plan assets:
ATMOS PENSION ACCOUNT SUPPLEMENTAL PLAN PLANS --------------------- ----------------- 2003 2002 2003 2002 --------- --------- ------- ------- (IN THOUSANDS) Projected Benefit Obligation................. $330,344 $226,197 $71,659 $59,152 Accumulated Benefit Obligation............... 323,663 225,124 62,642 53,191 Fair Value of Plan Assets.................... 322,703 209,941 -- --
POSTRETIREMENT BENEFITS Prior to January 1, 1999, Atmos sponsored two postretirement plans other than pensions that provided health care benefits to retired employees. One plan provided benefits to the Mid-States Division retirees and the other plan provided medical benefits to all other retired Atmos employees. Effective January 1, 1999, the 76 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Mid-States plan was merged into the Atmos plan and began providing benefits to future retirees that are essentially the same as provided to other Atmos employees. Substantially all of our employees become eligible for these benefits if they reach retirement age while working for us and attain certain specified years of service. In addition, participant contributions are required under the plan. The plan assets consist primarily of investments in registered investment companies and common/ collective trusts. The following table presents the funding status for the postretirement plan for 2003 and 2002.
2003 2002 -------- -------- (IN THOUSANDS) CHANGE IN BENEFIT OBLIGATION: Benefit obligation at beginning of year................... $112,295 $ 82,850 Service cost.............................................. 5,902 2,891 Interest cost............................................. 9,078 6,199 Plan participants' contributions.......................... 306 312 Actuarial loss............................................ 5,786 26,270 MVG acquisition........................................... 13,647 -- Benefits paid............................................. (9,729) (6,227) -------- -------- Benefit obligation at end of year......................... 137,285 112,295 CHANGE IN PLAN ASSETS: Fair value of plan assets at beginning of year............ 16,250 13,854 Actual return on plan assets.............................. (4,056) 2,396 Employer contributions.................................... 18,618 5,915 Plan participants' contributions.......................... 306 312 MVG acquisition........................................... 4,921 -- Benefits paid............................................. (9,729) (6,227) -------- -------- Fair value of plan assets at end of year.................. 26,310 16,250 -------- -------- RECONCILIATION: Funded status............................................... (110,975) (96,045) Unrecognized transition obligation.......................... 15,687 17,198 Unrecognized prior service cost............................. 1,166 1,534 Unrecognized net loss....................................... 38,543 29,466 -------- -------- Accrued postretirement cost................................. $(55,579) $(47,847) ======== ========
The current portion of the accrued post-retirement cost is recorded as a component of other current liabilities and the long-term portion of the accrued post-retirement cost is recorded as a component of deferred credits and other liabilities. 77 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The actuarial assumptions used to determine the liability for the post-retirement plan are as follows:
2003 2002 2001 ---- ----- ---- Discount rate............................................... 6.00% 7.25% 7.50% Expected return on plan assets.............................. 5.30% 5.30% 5.30% Initial trend rate.......................................... 9.00% 10.00% 7.00% Ultimate trend rate......................................... 5.00% 5.00% 5.00% Number of years from initial to ultimate trend.............. 5 6 3
Net periodic postretirement cost for 2003, 2002 and 2001 is recorded as a component of operating expense and included the following components:
YEAR ENDED SEPTEMBER 30 -------------------------- 2003 2002 2001 ------- ------- ------ (IN THOUSANDS) Components of net periodic postretirement cost: Service cost........................................... $ 5,902 $ 2,891 $2,274 Interest cost.......................................... 9,078 6,199 5,434 Expected return on assets.............................. (1,012) (759) (653) Amortization of transition obligation.................. 1,511 1,511 1,511 Amortization of prior service cost..................... 368 520 520 Recognized actuarial loss.............................. 1,778 -- -- ------- ------- ------ Net periodic postretirement cost.................... $17,625 $10,362 $9,086 ======= ======= ======
Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations:
1-PERCENTAGE 1-PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- (IN THOUSANDS) Effect on total service and interest cost components...... $ 1,720 $(1,570) Effect on postretirement benefit obligation............... $10,980 $(9,610)
We are currently recovering other postretirement benefits costs through our regulated rates under SFAS 106 accrual accounting in Colorado, Kansas, the majority of the Texas service area and Kentucky. We receive rate treatment as a cost of service item for other postretirement benefits costs on the pay-as-you-go basis in Louisiana. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by the Mid-States Division or have been included in a rate case and not disallowed. Management believes that accrual accounting in accordance with SFAS 106 is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses. RETIREMENT SAVINGS PLAN Atmos sponsors a Retirement Savings Plan for substantially all employees, which is subject to the provisions of Section 401(k) of the Internal Revenue Code. Effective January 1, 1999 the Retirement Savings Plan was amended to allow the deferral of a portion of a participant's salary ranging from a minimum of one percent of eligible compensation, as defined by the Plan, up to the maximum allowed by the Internal Revenue Service. We match 100 percent of a participant's contributions, limited to four percent of the participant's salary, in Atmos common stock. However, participants have the option to immediately transfer this matching 78 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) contribution into other funds held within the plan. Participants are also permitted to take out loans against their accounts subject to certain restrictions. Matching contributions to the Plan are expensed as incurred and amounted to $4.1 million, $3.6 million, and $3.2 million for 2003, 2002 and 2001. The Board of Directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code of 1986 and applicable regulations of the Internal Revenue Service. No discretionary contributions were made for 2003, 2002 or 2001. At September 30, 2003 and 2002, the Retirement Savings Plan held 4.4 percent and 5.8 percent of our common stock. 10. DETAILS OF SELECTED CONSOLIDATED BALANCE SHEET CAPTIONS The following tables provide additional information regarding the composition of certain of our balance sheet captions. OTHER CURRENT ASSETS Other current assets as of September 30, 2003 and 2002 are comprised of the following accounts.
SEPTEMBER 30 ----------------- 2003 2002 ------- ------- (IN THOUSANDS) Assets from risk management activities...................... $22,259 $27,984 Prepaid expenses............................................ 8,187 7,338 Materials and supplies...................................... 3,917 3,769 Deferred gas costs.......................................... 308 -- Other....................................................... 4,192 5,871 ------- ------- Total....................................................... $38,863 $44,962 ======= =======
PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following as of September 30, 2003 and 2002:
SEPTEMBER 30 ----------------------- 2003 2002 ---------- ---------- (IN THOUSANDS) Production plant............................................ $ 8,003 $ 9,017 Storage plant............................................... 64,714 53,527 Transmission plant.......................................... 122,014 97,708 Distribution plant.......................................... 1,851,228 1,572,549 General plant............................................... 376,777 340,419 Intangible plant............................................ 41,256 30,208 ---------- ---------- 2,463,992 2,103,428 Construction in progress.................................... 16,147 24,399 ---------- ---------- 2,480,139 2,127,827 Less: accumulated depreciation and amortization............. (964,150) (827,507) ---------- ---------- Net property, plant and equipment......................... $1,515,989 $1,300,320 ========== ==========
79 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DEFERRED CHARGES AND OTHER ASSETS Deferred charges and other assets as of September 30, 2003 and 2002 are comprised of the following accounts.
SEPTEMBER 30 ------------------- 2003 2002 -------- -------- (IN THOUSANDS) Pension plan assets in excess of plan obligations........... $116,696 $ -- Marketable securities....................................... 29,385 27,735 Long-term receivable on leased assets....................... 25,403 8,845 Investment in U.S. Propane.................................. 21,071 22,175 Regulatory assets........................................... 34,591 35,698 Rights of way............................................... 11,746 -- Deferred financing costs.................................... 8,867 8,944 Assets from risk management activities...................... 1,699 5,241 Prepaid weather insurance premiums.......................... -- 8,825 Other....................................................... 21,565 42,067 -------- -------- Total....................................................... $271,023 $159,530 ======== ========
OTHER CURRENT LIABILITIES Other current liabilities as of September 30, 2003 and 2002 are comprised of the following accounts.
SEPTEMBER 30 ------------------- 2003 2002 -------- -------- (IN THOUSANDS) Customer deposits........................................... $ 41,068 $ 31,147 Accrued employee costs...................................... 11,480 14,620 Deferred gas costs.......................................... -- 21,947 Accrued interest............................................ 20,972 18,557 Liabilities from risk management activities................. 20,790 18,487 Taxes payable............................................... 9,746 15,626 Post-retirement obligations................................. 5,300 5,300 Other....................................................... 18,567 34,043 -------- -------- Total....................................................... $127,923 $159,727 ======== ========
80 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DEFERRED CREDITS AND OTHER LIABILITIES Deferred credits and other liabilities as of September 30, 2003 and 2002 are comprised of the following accounts.
SEPTEMBER 30 ------------------- 2003 2002 -------- -------- (IN THOUSANDS) Post-retirement obligations................................. $ 50,279 $ 42,547 Nonqualified retirement plan obligation..................... 42,460 37,963 Defined benefit plan obligations............................ -- 15,735 Customer advances for construction.......................... 13,701 12,049 Liabilities from risk management activities................. 763 3,663 Deferred revenue............................................ 12,197 3,290 Other....................................................... 18,608 23,629 -------- -------- Total....................................................... $138,008 $138,876 ======== ========
11. EARNINGS PER SHARE Basic and diluted earnings per share at September 30 are calculated as follows:
2003 2002 2001 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Income before cumulative effect of accounting change.............................................. $79,461 $59,656 $56,090 Cumulative effect of accounting change, net of income tax benefit......................................... (7,773) -- -- ------- ------- ------- Net income............................................ $71,688 $59,656 $56,090 ======= ======= ======= Denominator for basic income per share -- weighted average common shares............................... 46,319 41,171 38,156 Effect of dilutive securities: Restricted stock.................................... 109 54 79 Stock options....................................... 68 25 12 ------- ------- ------- Denominator for diluted income per share -- weighted average common shares............................... 46,496 41,250 38,247 ======= ======= ======= Income per share -- basic: Before cumulative effect of accounting change....... $ 1.72 $ 1.45 $ 1.47 Cumulative effect of accounting change, net of income tax benefit............................... (.17) -- -- ------- ------- ------- Net income per share................................ $ 1.55 $ 1.45 $ 1.47 ======= ======= ======= Income per share -- diluted: Before cumulative effect of accounting change....... $ 1.71 $ 1.45 $ 1.47 Cumulative effect of accounting change, net of income tax benefit............................... (.17) -- -- ------- ------- ------- Net income per share................................ $ 1.54 $ 1.45 $ 1.47 ======= ======= =======
81 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) There were approximately 601,500, 1,118,167 and 685,000 out-of-the-money options excluded from the computation of diluted earnings per share for the years ended September 30, 2003, 2002 and 2001 as their exercise price is greater than the average market price of the common stock. 12. INCOME TAXES The components of income tax expense from continuing operations for 2003, 2002 and 2001 were as follows:
2003 2002 2001 -------- ------- ------- (IN THOUSANDS) Current Federal.............................................. $(13,446) $17,638 $13,624 State................................................ (441) 3,575 2,189 Deferred Federal.............................................. 54,656 12,964 14,971 State................................................ 6,690 1,420 3,013 Investment tax credits................................. (549) (417) (429) -------- ------- ------- $ 46,910 $35,180 $33,368 ======== ======= =======
The provision (benefit) for income taxes is included in the consolidated financial statements as follows:
2003 2002 2001 ------- ------- ------- (IN THOUSANDS) Income before cumulative effect of accounting change.... $46,910 $35,180 $33,368 Cumulative effect of accounting change.................. (5,117) -- -- ------- ------- ------- Income tax expense...................................... $41,793 $35,180 $33,368 ======= ======= =======
During 2003, we recorded a cumulative effect of accounting change to reflect the adoption of EITF 02-03, as described in Note 5. The $5.1 million benefit on the cumulative charge reflects a federal and state tax benefit of 39.7 percent. Reconciliations of the provision for income taxes before the cumulative effect of accounting change computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2003, 2002 and 2001 are set forth below:
2003 2002 2001 ------- ------- ------- (IN THOUSANDS) Tax at statutory rate of 35%............................ $44,230 $33,193 $31,310 Common stock dividends deductible for tax reporting..... (993) (707) (857) State taxes (net of federal benefit).................... 4,062 3,489 3,652 Other, net.............................................. (389) (795) (737) ------- ------- ------- Income tax expense...................................... $46,910 $35,180 $33,368 ======= ======= =======
82 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2003 and 2002 are presented below:
2003 2002 --------- --------- (IN THOUSANDS) DEFERRED TAX ASSETS: Costs expensed for book purposes and capitalized for tax purposes............................................... $ 2,336 $ 2,398 Accruals not currently deductible for tax purposes........ 5,254 3,968 Customer advances......................................... 6,158 4,578 Nonqualified benefit plans................................ 17,435 14,325 Postretirement benefits................................... 21,186 22,153 Unamortized investment tax credit......................... 564 902 Regulatory liabilities.................................... 1,271 1,328 Tax net operating loss and credit carryforwards........... 29,257 6,377 Other, net................................................ 7,198 9,201 --------- --------- Total deferred tax assets.............................. 90,659 65,230 DEFERRED TAX LIABILITIES: Difference in net book value and net tax value of assets................................................. (257,679) (194,573) Pension funding........................................... (42,681) 6,450 Gas cost adjustments...................................... (429) 6,464 Regulatory assets......................................... (3,154) (3,154) Cost capitalized for book purposes and expensed for tax purposes............................................... (8,054) (7,717) Other, net................................................ (2,012) (7,240) --------- --------- Total deferred tax liabilities......................... (314,009) (199,770) --------- --------- Net deferred tax liabilities................................ $(223,350) $(134,540) ========= ========= SFAS No. 109 deferred credits for rate regulated entities... $ 2,080 $ 1,704 ========= =========
We have tax carryforwards amounting to $29.3 million. The tax carryforwards include net operating losses for federal and state income tax purposes amounting to $14.4 million. The federal net operating loss will begin to expire in 2018. Depending on the jurisdiction in which the net operating loss was generated, the state net operating losses will begin to expire between 2016 and 2021. Also included in the tax carryforward is $12.3 million in alternative minimum tax credits which do not expire. The balance of tax carryforwards relate to federal tax credits claimed on research and development activities and expire beginning in 2011. During fiscal 2003, the Internal Revenue Service initiated a routine examination of our fiscal 1999, 2000 and 2001 tax returns. We believe all material tax items have been accrued related to the years under audit. 13. COMMITMENTS AND CONTINGENCIES LITIGATION Colorado-Kansas Division On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto, against more than 200 companies in the natural gas industry including us and our Colorado-Kansas Division. The plaintiffs, who purport to represent a class 83 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, allege the defendants have underpaid royalties on gas taken from wells situated on non-federal and non-Indian lands throughout the United States and offshore waters predicated upon allegations that the defendants' gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. On April 10, 2000, this case was consolidated for pre-trial proceedings with other similar pending litigation in federal court in Wyoming in which we are also a defendant along with over 200 other defendants in the case of In Re Natural Gas Royalties Qui Tam Litigation. In January 2001, the federal court elected to remand this case back to the Kansas state court. A reconsideration of remand was filed, but it was denied. The state court now has jurisdiction over this proceeding and has issued a preliminary case management order. On April 10, 2003, the court denied the plaintiffs' motion to certify this proceeding as a class action, which ruling was appealed by the plaintiffs. The court did allow the plaintiffs to file an amended complaint, which is somewhat narrower in scope than the original complaint. However, we continue to believe that the plaintiffs' claims are still lacking in merit, and we intend to continue to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows. Texas Division On February 13, 2002, a suit was filed in the 287th District Court of Parmer County, Texas by Anderson Brothers, a Partnership, against Atmos Energy Corporation, et al. The plaintiffs' claims arise out of an alleged breach of contract by us and by a number of our divisions and subsidiaries concerning the sale of natural gas used in irrigation activities since 1998 and an alleged violation of the Texas Agricultural Gas Users Act of 1985. The court has ruled proper venue to be in Parmer County, Texas. We have been responding to numerous discovery requests from the plaintiffs. We also filed suit in Travis County, Texas to have the Texas Agricultural Gas Users Act of 1985 declared unconstitutional. The court denied our motion for summary judgment which we have appealed. The plaintiffs seek class action status and to recover unspecified damages plus attorneys' fees. We have denied any liability and intend to vigorously defend against the plaintiffs' claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows. We are a plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc. and ONEOK Energy Marketing and Trading Company II, filed in December 2001, pending in the District Court of Lubbock County, Texas, 72nd Judicial District. In this case, we are seeking to collect our receivable related to approximately 5.0 Bcf of natural gas that we believe was not delivered. Atmos has settled a portion of its claims with the parties and will continue to pursue recovery of the remaining claims, which we believe are fully recoverable. United Cities Propane Gas, Inc. United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a party to an action filed in June 2000 which is pending in the Circuit Court of Sevier County, Tennessee. The plaintiffs' claims arise out of injuries alleged to have been caused by a low-level propane explosion. The plaintiffs seek to recover damages of $13.0 million. Discovery activities continue in this case. We have denied any liability, and we intend to vigorously defend against the plaintiffs' claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows. 84 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) We are a party to other litigation and claims that arise in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims will not have a material adverse effect on our financial condition, results of operations or net cash flows. ENVIRONMENTAL MATTERS Manufactured Gas Plant Sites We are the owner or previous owner of manufactured gas plant sites in Johnson City and Bristol, Tennessee and Hannibal, Missouri which were used to supply gas prior to the availability of natural gas. The gas manufacturing process resulted in certain by-products and residual materials including coal tar. The manufacturing process used by our predecessors was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, we may be responsible for response actions with respect to such materials if response actions are necessary. United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of 1997 which we have continued through September 30, 2003. The investigative phase of the work at the site has been completed and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We have completed a risk assessment report which is currently under review by the TDEC. Finally, we have completed a feasibility study for this site that was submitted in October 2003. The feasibility study recommends a remedial action that will limit the use of and access to the impacted soil, cap the site with the addition of a clay fill and geosynthetic liner, and groundwater monitoring for a period of up to 30 years. The estimated cost of the proposed remedial action is $1.5 million, which is comprised primarily of operating and maintenance costs associated with a groundwater monitoring project. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements. In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site which was completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site and we have proposed performing a focused removal action to remove any such residuals. The TDEC has requested that the focused removal action be conducted pursuant to a voluntary agreement. We are continuing the process of negotiating the voluntary agreement with TDEC and hope to conduct the focused removal action later this year. On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources addressing the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action, a subsequent site evaluation and to reimburse the response costs incurred by the state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site evaluation field work was conducted in August 1999. A risk assessment for the site has been completed and is currently under review by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site use limitations including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water. In 1995, United Cities Gas Company, entered into an agreement to pay $1.8 million to Union Electric, now Ameren, in exchange for an indemnity covering United Cities' share of additional investigations and 85 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) environmental response actions for soil contamination at a former manufactured gas plant in Keokuk, Iowa. However, the extent of groundwater contamination at the site, which is not covered by the indemnity, has yet to be determined. As of September 30, 2003, we had incurred costs of approximately $1.7 million for the investigations of the Johnson City and Bristol, Tennessee and Hannibal, Missouri sites and had a remaining accrual relating to these sites of $0.2 million, which is recorded as a component of other current liabilities. Mercury Contamination Sites We have completed investigation and remediation activities pursuant to Consent Orders between the Kansas Department of Health and Environment (KDHE) and United Cities Gas Company. The Orders provided for the investigation and remediation of mercury contamination at gas pipeline sites which utilize or formerly utilized mercury meter equipment in Kansas. The Final Interim Characterization and Remediation Report has been submitted to the KDHE. We amended the Orders with the KDHE to include all mercury meters that belonged to our Colorado-Kansas Division before the merger with United Cities Gas Company on July 31, 1997. All work on these sites has been completed. On October 1, 2003, we received a letter from the KDHE, in which the KDHE stated that upon our payment to the KDHE of all oversight costs, we will have fulfilled the terms of the Consent Orders, at which time we will be receiving a termination letter from the KDHE evidencing such fulfillment. As of September 30, 2003, we had incurred costs of $0.2 million for these sites and had a remaining accrual of $0.2 million for recovery, which is recorded as a component of other current liabilities. We are a party to other environmental matters and claims that arise out of our ordinary business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance. PURCHASE COMMITMENTS AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward Nymex strip or fixed price contracts. At September 30, 2003, AEM is committed to purchase 83.1 Bcf within one year and 24.8 Bcf within one to three years under indexed contracts. AEM is committed to purchase 2.2 Bcf within one year under fixed price contracts with prices ranging from $3.13 to $6.70. Purchases under these contracts totaled $1,454.8 million, $725.6 million and $361.4 million for 2003, 2002 and 2001. Our utility segment maintains supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract. OTHER The limited partnership agreement of U.S. Propane, L.P., an entity in which we own an approximate 19 percent membership interest, requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $4.7 million. As of September 30, 2003, our capital account was positive. 86 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. LEASES LEASING OPERATIONS Atmos Power Systems, Inc. constructs and operates electric peaking power generating plants and associated facilities and may enter into agreements to either lease or sell these plants. We completed a sales-type lease transaction for one distributed electric generation plant in 2001 and a second sales-type lease transaction in 2003. In 2001, we recognized a gain of $0.8 million and deferred $4.7 million of income, which will be recognized using the interest method through August 2011. In 2003, we recognized a gain of $3.9 million and deferred $8.6 million in income, which will be recognized using the interest method through September 2012. As of September 30, 2003 and 2002, we recorded receivables of $28.4 million and $9.8 million and recorded income of $2.0 million, $0.7 million and $0.2 million for fiscal years 2003, 2002 and 2001. The future minimum lease payments to be received for each of the five succeeding years are as follows:
MINIMUM LEASE RECEIPTS -------------- (IN THOUSANDS) 2004........................................................ $ 2,973 2005........................................................ 2,973 2006........................................................ 2,973 2007........................................................ 2,973 2008........................................................ 2,973 Thereafter.................................................. 13,513 ------- Total minimum lease receipts................................ $28,378 =======
CAPITAL AND OPERATING LEASES We have entered into non-cancelable operating leases for office and warehouse space used in our operations. The remaining lease terms range from one to 15 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. We have also entered into capital leases for division offices and operating facilities. Property, plant and equipment included amounts for capital leases of $5.2 million at September 30, 2003 and 2002. Accumulated depreciation for these capital leases totaled $2.2 million at September 30, 2003 and 2002. Depreciation expense for these assets is included in consolidated depreciation expense on the consolidated statement of income. The related future minimum lease payments at September 30, 2003 were as follows:
CAPITAL OPERATING LEASES LEASES ------- --------- (IN THOUSANDS) 2004........................................................ $ 876 $10,331 2005........................................................ 843 9,684 2006........................................................ 433 9,137 2007........................................................ 433 7,271 2008........................................................ 362 5,685 Thereafter.................................................. 2,178 16,817 ------- ------- Total minimum lease payments................................ 5,125 $58,925 ======= Less amount representing interest........................... (2,113) ------- Present value of net minimum lease payments................. $ 3,012 =======
87 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Consolidated lease and rental expense amounted to $8.9 million, $8.1 million and $5.9 million for fiscal 2003, 2002 and 2001. 15. CONCENTRATION OF CREDIT RISK Credit risk is the risk of financial loss to us if counterparties fail to perform their contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with commercial, residential and municipal energy consumers. These transactions principally occur in the South and Midwest regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable is limited due to the large number of customers. We maintain credit policies with respect to our counterparties that we believe minimize overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. We maintain a provision for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of counterparty nonperformance. The following table presents our credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of September 30, 2003. Investment grade counterparties have minimum credit ratings of BBB assigned by Standard & Poor's Rating Group or Baa3 assigned by Moody's Investor Service. Non-investment grade counterparties are comprised of counterparties that are below investment grade or are counterparties that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is comprised of numerous smaller counterparties, none of which is individually significant.
AT SEPTEMBER 30, 2003 ------------------------------------------------------ NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY SEGMENT(1) SEGMENT SEGMENT CONSOLIDATED ----------- ----------- ----------- ------------ (IN THOUSANDS) Investment grade counterparties......... $202 $10,866 $-- $11,068 Non-investment grade counterparties..... -- 12,890 -- 12,890 ---- ------- --- ------- $202 $23,756 $-- $23,958 ==== ======= === =======
- --------------- (1) Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers. Because AEM's operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Additionally, AEM's credit risk has increased due to higher natural gas prices as compared with the prior year. However, this risk is somewhat mitigated because a larger percentage of AEM's business in the current year is with municipal customers, who typically are rated investment grade, as compared with the prior year. 88 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 16. SUPPLEMENTAL CASH FLOW DISCLOSURES Supplemental disclosures of cash flow information for 2003, 2002 and 2001 are presented below.
2003 2002 2001 ------- ------- ------- (IN THOUSANDS) Cash paid for interest.................................. $62,088 $59,639 $41,042 Cash paid for income taxes.............................. $ 408 $16,588 $16,808
In December 2002, we partially funded the acquisition of MVG through the issuance of $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. In June 2003, we contributed to the Atmos Energy Corporation Master Retirement Trust for the benefit of the Atmos Pension Account Plan 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. In April 2001, we completed the acquisition of the remaining 55 percent of Woodward Marketing, L.L.C that we did not already own in exchange for 1,423,193 restricted shares of our common stock with a value of $26.7 million. 17. SEGMENT INFORMATION Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain non-utility businesses. We distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers through our six regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. Through our non-utility businesses, we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. We also supplement natural gas used by our customers through natural gas storage fields that we own or hold an interest in Kansas, Kentucky, Louisiana and Mississippi. We market natural gas to industrial customers primarily in West Texas and Louisiana. Finally, we construct electric power generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers. Our operations are divided into three segments: - The utility segment, which includes our regulated natural gas distribution and sales operations, - The natural gas marketing segment, which includes a variety of natural gas management services and - The other non-utility segment, which includes all of our other non-utility operations. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We 89 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) evaluate performance based on net income or loss of the respective operating units. Summarized income statements and capital expenditures by segment are shown in the following tables.
FOR THE YEAR ENDED SEPTEMBER 30, 2003 -------------------------------------------------------------------- NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED ---------- ----------- ----------- ------------ ------------ (IN THOUSANDS) Operating revenues from external parties......................... $1,552,857 $1,234,447 $12,612 $ -- $2,799,916 Intersegment revenues............. 1,225 434,046 9,018 (444,289) -- ---------- ---------- ------- --------- ---------- 1,554,082 1,668,493 21,630 (444,289) 2,799,916 Purchased gas cost................ 1,062,679 1,644,328 1,540 (443,607) 2,264,940 ---------- ---------- ------- --------- ---------- Gross profit................. 491,403 24,165 20,090 (682) 534,976 Depreciation and amortization..... 83,849 1,261 1,891 -- 87,001 Other operating expenses.......... 246,420 9,335 5,062 (682) 260,135 ---------- ---------- ------- --------- ---------- Operating income.................. 161,134 13,569 13,137 -- 187,840 Miscellaneous income (expense).... (218) 1,855 5,004 (4,450) 2,191 Interest charges.................. 63,226 2,864 2,020 (4,450) 63,660 ---------- ---------- ------- --------- ---------- Income before income taxes and cumulative effect of accounting change.......................... 97,690 12,560 16,121 -- 126,371 Income tax expense................ 35,553 5,757 5,600 -- 46,910 ---------- ---------- ------- --------- ---------- Income before cumulative effect of accounting change............... 62,137 6,803 10,521 -- 79,461 Cumulative effect of accounting change, net of income tax benefit......................... -- (7,773) -- -- (7,773) ---------- ---------- ------- --------- ---------- Net income (loss).......... $ 62,137 $ (970) $10,521 $ -- $ 71,688 ========== ========== ======= ========= ========== Capital expenditures.............. $ 154,777 $ 1,884 $ 2,778 $ -- $ 159,439 ========== ========== ======= ========= ==========
90 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEAR ENDED SEPTEMBER 30, 2002 ------------------------------------------------------------------ NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED -------- ----------- ----------- ------------ ------------ (IN THOUSANDS) Operating revenues from external parties.......................... $936,054 $ 700,519 $14,391 $ -- $1,650,964 Intersegment revenues.............. 1,472 331,355 10,314 (343,141) -- -------- ---------- ------- --------- ---------- 937,526 1,031,874 24,705 (343,141) 1,650,964 Purchased gas cost................. 559,891 994,318 8,022 (342,407) 1,219,824 -------- ---------- ------- --------- ---------- Gross profit..................... 377,635 37,556 16,683 (734) 431,140 Depreciation and amortization...... 77,704 2,069 1,696 -- 81,469 Other operating expenses........... 174,425 14,877 5,772 (734) 194,340 -------- ---------- ------- --------- ---------- Operating income................... 125,506 20,610 9,215 -- 155,331 Miscellaneous income (expense)..... 1,427 1,331 554 (4,633) (1,321) Interest charges................... 58,796 2,866 2,145 (4,633) 59,174 -------- ---------- ------- --------- ---------- Income before income taxes......... 68,137 19,075 7,624 -- 94,836 Income tax expense................. 25,143 6,461 3,576 -- 35,180 -------- ---------- ------- --------- ---------- Net income.................... $ 42,994 $ 12,614 $ 4,048 $ -- $ 59,656 ======== ========== ======= ========= ========== Capital expenditures............... $129,632 $ 779 $ 1,841 $ -- $ 132,252 ======== ========== ======= ========= ==========
FOR THE YEAR ENDED SEPTEMBER 30, 2001 -------------------------------------------------------------------- NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED ---------- ----------- ----------- ------------ ------------ (IN THOUSANDS) Operating revenues from external parties......................... $1,378,159 $291,152 $56,170 $ -- $1,725,481 Intersegment revenues............. 1,989 155,944 3,266 (161,199) -- ---------- -------- ------- --------- ---------- 1,380,148 447,096 59,436 (161,199) 1,725,481 Purchased gas cost................ 1,017,363 445,504 48,605 (161,199) 1,350,273 ---------- -------- ------- --------- ---------- Gross profit.................... 362,785 1,592 10,831 -- 375,208 Depreciation and amortization..... 65,614 1,062 988 -- 67,664 Other operating expenses.......... 170,663 3,733 4,339 (1,472) 177,263 ---------- -------- ------- --------- ---------- Operating income (loss)........... 126,508 (3,203) 5,504 1,472 130,281 Equity in earnings of Woodward Marketing L.L.C................. -- 8,062 -- -- 8,062 Miscellaneous income (expense).... (864) 1,819 1,539 (4,368) (1,874) Interest charges.................. 46,351 2,611 945 (2,896) 47,011 ---------- -------- ------- --------- ---------- Income before income taxes........ 79,293 4,067 6,098 -- 89,458 Income tax expense................ 29,412 1,516 2,440 -- 33,368 ---------- -------- ------- --------- ---------- Net income................... $ 49,881 $ 2,551 $ 3,658 $ -- $ 56,090 ========== ======== ======= ========= ========== Capital expenditures.............. $ 112,683 $ 32 $ 394 $ -- $ 113,109 ========== ======== ======= ========= ==========
91 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes our revenues by products and services for the year ended September 30.
2003 2002 2001 ---------- ---------- ---------- (IN THOUSANDS) Utility revenues: Gas sales revenues: Residential................................. $ 873,375 $ 535,981 $ 788,902 Commercial.................................. 367,961 221,728 342,945 Public authority and other.................. 65,921 31,731 58,539 Industrial.................................. 192,676 98,765 148,180 ---------- ---------- ---------- Total gas sales revenues.................. 1,499,933 888,205 1,338,566 Transportation revenues........................ 29,583 36,591 28,668 Other gas revenues............................. 23,341 11,258 10,925 ---------- ---------- ---------- Total utility revenues...................... 1,552,857 936,054 1,378,159 Natural gas marketing revenues................... 1,234,447 700,519 291,152 Other non-utility revenues....................... 12,612 14,391 56,170 ---------- ---------- ---------- Total operating revenues.................... $2,799,916 $1,650,964 $1,725,481 ========== ========== ==========
92 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Balance sheet information at September 30, 2003 and 2002 by segment is presented in the following tables:
AT SEPTEMBER 30, 2003 -------------------------------------------------------------------- NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED ---------- ----------- ----------- ------------ ------------ (IN THOUSANDS) ASSETS Property, plant and equipment, net......................... $1,446,976 $ 9,288 $ 59,725 $ -- $1,515,989 Investment in subsidiaries.... 133,586 (2,662) -- (130,924) -- Current assets Cash and cash equivalents... -- 14,880 803 -- 15,683 Assets from risk management activities............... 202 22,941 -- (884) 22,259 Other current assets........ 230,609 197,239 85,119 (92,912) 420,055 Intercompany receivables.... 114,550 -- -- (114,550) -- ---------- -------- -------- --------- ---------- Total current assets..... 345,361 235,060 85,922 (208,346) 457,997 Intangible assets............. -- 5,030 -- -- 5,030 Goodwill...................... 233,741 22,600 12,128 -- 268,469 Noncurrent assets from risk management activities....... -- 1,896 -- (197) 1,699 Investment in US Propane LLC......................... -- -- 21,071 -- 21,071 Deferred charges and other assets...................... 220,258 2,214 25,781 -- 248,253 ---------- -------- -------- --------- ---------- $2,379,922 $273,426 $204,627 $(339,467) $2,518,508 ========== ======== ======== ========= ========== CAPITALIZATION AND LIABILITIES Shareholders' equity.......... $ 857,517 $ 74,759 $ 58,827 $(133,586) $ 857,517 Long-term debt................ 858,720 -- 5,198 -- 863,918 ---------- -------- -------- --------- ---------- Total capitalization..... 1,716,237 74,759 64,025 (133,586) 1,721,435 Current liabilities Current maturities of long-term debt........... 8,227 -- 1,118 -- 9,345 Short-term debt............. 118,595 -- -- -- 118,595 Liabilities from risk management activities.... 7,941 13,400 -- (551) 20,790 Other current liabilities... 184,365 183,082 10,008 (90,470) 286,985 Intercompany payables....... -- 5,549 109,001 (114,550) -- ---------- -------- -------- --------- ---------- Total current liabilities............ 319,128 202,031 120,127 (205,571) 435,715 Deferred income taxes......... 221,912 (9,498) 11,081 (145) 223,350 Noncurrent liabilities from risk management activities.................. -- 928 -- (165) 763 Deferred credits and other liabilities................. 122,645 5,206 9,394 -- 137,245 ---------- -------- -------- --------- ---------- $2,379,922 $273,426 $204,627 $(339,467) $2,518,508 ========== ======== ======== ========= ==========
93 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
AT SEPTEMBER 30, 2002 -------------------------------------------------------------------- NATURAL GAS OTHER UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED ---------- ----------- ----------- ------------ ------------ (IN THOUSANDS) ASSETS Property, plant and equipment, net.......... $1,223,901 $ 9,893 $ 66,526 $ -- $1,300,320 Investment in subsidiaries............ 122,988 (5,752) -- (117,236) -- Current assets Cash and cash equivalents.......... -- 47,887 104 -- 47,991 Assets from risk management activities........... 4,424 28,909 -- (5,349) 27,984 Other current assets.... 126,066 141,526 4,275 (16,687) 255,180 Intercompany receivables.......... 76,174 -- -- (76,174) -- ---------- -------- -------- --------- ---------- Total current assets............. 206,664 218,322 4,379 (98,210) 331,155 Intangible assets......... -- 5,365 -- -- 5,365 Goodwill.................. 150,287 21,288 13,440 -- 185,015 Noncurrent assets from risk management activities.............. -- 5,241 -- -- 5,241 Investment in US Propane LLC..................... -- -- 22,175 -- 22,175 Deferred charges and other assets.................. 87,157 37,294 7,663 -- 132,114 ---------- -------- -------- --------- ---------- $1,790,997 $291,651 $114,183 $(215,446) $1,981,385 ========== ======== ======== ========= ========== CAPITALIZATION AND LIABILITIES Shareholders' equity...... $ 573,235 $ 75,675 $ 47,313 $(122,988) $ 573,235 Long-term debt............ 667,946 -- 2,517 -- 670,463 ---------- -------- -------- --------- ---------- Total capitalization..... 1,241,181 75,675 49,830 (122,988) 1,243,698 Current liabilities Current maturities of long-term debt....... 20,907 -- 1,073 -- 21,980 Short-term debt......... 145,791 -- -- -- 145,791 Liabilities from risk management activities........... -- 18,487 -- -- 18,487 Other current liabilities.......... 134,138 151,046 9,113 (16,284) 278,013 Intercompany payables... -- 33,027 43,147 (76,174) -- ---------- -------- -------- --------- ---------- Total current liabilities........ 300,836 202,560 53,333 (92,458) 464,271 Deferred income taxes..... 130,575 (3,227) 7,192 -- 134,540 Noncurrent liabilities from risk management activities.............. -- 3,663 -- -- 3,663 Deferred credits and other liabilities............. 118,405 12,980 3,828 -- 135,213 ---------- -------- -------- --------- ---------- $1,790,997 $291,651 $114,183 $(215,446) $1,981,385 ========== ======== ======== ========= ==========
94 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 18. RELATED PARTY TRANSACTIONS AEM provides a variety of natural gas management services to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions including furnishing natural gas supplies at fixed and market-based prices and the management of certain of our underground storage facilities. Additionally, at times, AEM places financial instruments for our various divisions to protect us and our customers from unusually large winter period gas price increases. The following summarizes these transactions with AEM.
2003 2002 2001 -------- -------- -------- Gas purchases(1): Dollars (in thousands)............................. $333,390 $190,594 $525,568 Volumes (Mcf)...................................... 62,729 67,657 96,252 Average sales price per Mcf........................ $ 5.31 $ 2.82 $ 5.46 Storage contract fees (in thousands)................. $ 4,236 $ 4,305 $ 3,366
- --------------- (1) Gas purchases are made in a competitive bidding process, reflect market prices and exclude demand and other charges. JD Woodward became Senior Vice President, Non-Utility Operations of the Company on April 1, 2001. Woodward Marketing L.L.C., a wholly-owned subsidiary of the Company through September 30, 2003 and its successor, AEM (see Note 1), leases office space from one corporation owned by Mr. Woodward. The lease originated in April 2002 and expires in March 2007. Base lease payments are $225,000 in the first year of the lease and increase to $253,000 in the final year. During 2003 and 2002, our utility division leased office space and vehicles from our natural gas marketing and other non-utility segments. Base lease payments were $0.7 million in 2003 and 2002. There were no such leasing activities during 2001. Effective in October 1994, Charles Vaughan retired as an officer and employee of the Company and entered into a consulting agreement with the Company. Under the terms of the agreement, Mr. Vaughan performed such consulting services as the Board requested from time to time. During fiscal 2002, Mr. Vaughan received $130,000 in payment for his services during that period. In addition, pursuant to the terms of the agreement, upon early termination of the agreement by the Company in September 2002, Mr. Vaughan received a total of $175,000, representing the total sums due him under the remainder of the agreement that was due to expire September 30, 2004. 19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized unaudited quarterly financial data is 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. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the "Results of Operations" discussion included in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section herein. As more fully described in Note 5, upon the adoption of EITF 02-03, our inventory, storage, transportation and index-priced physical forward contracts are no longer marked to market. Our index-priced physical forward contracts are now considered normal purchases and sales under SFAS 133. In conjunction with the adoption of EITF 02-03, energy trading contracts resulting in delivery of a commodity where we are 95 ATMOS ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the principal in the transaction are included as natural gas marketing sales or purchases. The following selected quarterly financial data has been reclassified to conform with this new presentation.
QUARTER ENDED -------------------------------------------------- DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30 ----------- ---------- -------- ------------ (IN THOUSANDS, EXCEPT PER SHARE DATA) FISCAL YEAR 2003: Operating revenues Utility segment.................. $399,968 $ 696,561 $245,998 $211,555 Natural gas marketing segment.... 343,498 620,402 374,832 329,761 Other non-utility segment........ 2,900 9,657 3,685 5,388 Intersegment eliminations........ (65,934) (132,478) (136,045) (109,832) -------- ---------- -------- -------- 680,432 1,194,142 488,470 436,872 Gross profit........................ 137,166 202,968 95,064 99,778 Operating income.................... 52,624 107,878 14,056 13,282 Income (loss) before cumulative effect of accounting change...... 25,793 56,305 (201) (2,436) Cumulative effect of accounting change, net of income tax benefit.......................... -- (7,773) -- -- Net income (loss)................... 25,793 48,532 (201) (2,436) Income (loss) before cumulative effect of accounting change per basic and diluted share.......... $ .60 $ 1.24 $ (.00) $ (.05) Cumulative effect of accounting change, net of income tax benefit, per basic and diluted share............................ $ -- $ (.17) $ -- $ -- -------- ---------- -------- -------- Net income (loss) per basic and diluted share.................... $ .60 $ 1.07 $ (.00) $ (.05) ======== ========== ======== ======== FISCAL YEAR 2002: Operating revenues Utility segment.................. $265,156 $ 376,811 $159,493 $136,066 Natural gas marketing segment.... 254,042 256,172 282,396 239,264 Other non-utility segment........ 7,466 9,494 3,888 3,857 Intersegment eliminations........ (86,510) (112,218) (57,672) (86,741) -------- ---------- -------- -------- 440,154 530,259 388,105 292,446 Gross profit........................ 116,528 159,487 86,092 69,033 Operating income.................... 43,446 86,333 19,178 6,374 Net income (loss)................... 20,633 41,378 3,254 (5,609) Net income (loss) per basic share... $ .51 $ 1.01 $ .08 $ (.14) Net income (loss) per diluted share............................ $ .50 $ 1.01 $ .08 $ (.14)
96 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including the Chairman, President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chairman, President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures continue to be effective. Such disclosure controls and procedures are controls and procedures designed to ensure that all information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods set forth in applicable Securities and Exchange Commission forms, rules and regulations. In addition, we have reviewed our internal control over financial reporting and have concluded that there has been no change in such internal control during the fourth quarter of fiscal 2003 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding directors and compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 11, 2004. Information regarding executive officers is included in Part I of this Form 10-K. Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors' determination as to whether one or more audit committee financial experts is serving on the Audit Committee of the Board of Directors is incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 11, 2004. The Company has adopted a code of ethics for its principal executive officer and senior financial officers. Such code of ethics is represented by the Company's Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Company's principal executive officer and senior financial officers. A copy of the Company's Code of Conduct is posted on the Company's website under "Corporate Governance". ITEM 11. EXECUTIVE COMPENSATION Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 11, 2004. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 11, 2004. 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 11, 2004. 97 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Incorporated herein by reference from the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders on February 11, 2004. PART IV ITEM 15. 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 schedule listed in the Index to Financial Statements in Item 8 are filed as part of this Form 10-K. 3. Exhibits The exhibits listed in the accompanying Exhibits Index are filed as part of this Form 10-K. The exhibits numbered 10.15(a) through 10.26(b) are management contracts or compensatory plans or arrangements. (b) Reports on Form 8-K None. 98 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/ JOHN P. REDDY ------------------------------------ John P. Reddy Senior Vice President and Chief Financial Officer Date: November 21, 2003 99 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Robert W. Best and John P. Reddy, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, 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 in and about the premises, 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, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ ROBERT W. BEST Chairman, President and Chief November 21, 2003 - -------------------------------------- Executive Officer Robert W. Best /s/ JOHN P. REDDY Senior Vice President and Chief November 21, 2003 - -------------------------------------- Financial Officer John P. Reddy /s/ F.E. MEISENHEIMER Vice President and Controller November 21, 2003 - -------------------------------------- (Principal Accounting Officer) F.E. Meisenheimer /s/ TRAVIS W. BAIN, II Director November 21, 2003 - -------------------------------------- Travis W. Bain, II /s/ DAN BUSBEE Director November 21, 2003 - -------------------------------------- Dan Busbee /s/ RICHARD W. CARDIN Director November 21, 2003 - -------------------------------------- Richard W. Cardin /s/ THOMAS J. GARLAND Director November 21, 2003 - -------------------------------------- Thomas J. Garland /s/ RICHARD K. GORDON Director November 21, 2003 - -------------------------------------- Richard K. Gordon /s/ GENE C. KOONCE Director November 21, 2003 - -------------------------------------- Gene C. Koonce /s/ THOMAS C. MEREDITH Director November 21, 2003 - -------------------------------------- Thomas C. Meredith /s/ PHILLIP E. NICHOL Director November 21, 2003 - -------------------------------------- Phillip E. Nichol /s/ CARL S. QUINN Director November 21, 2003 - -------------------------------------- Carl S. Quinn /s/ CHARLES K. VAUGHAN Director November 21, 2003 - -------------------------------------- Charles K. Vaughan /s/ RICHARD WARE II Director November 21, 2003 - -------------------------------------- Richard Ware II
100 SCHEDULE II ATMOS ENERGY CORPORATION VALUATION AND QUALIFYING ACCOUNTS THREE YEARS ENDED SEPTEMBER 30, 2003 (IN THOUSANDS)
ADDITIONS ----------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE BEGINNING COST & OTHER AT END OF OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ---------- ---------- ---------- ---------- --------- 2003 Allowance for doubtful accounts...... $10,509 $13,249 $ -- $10,707(2) $13,051 2002 Allowance for doubtful accounts...... $16,151 $ -- $1,500(1) $ 7,142(2) $10,509 2001 Allowance for doubtful accounts...... $10,589 $26,226 -- $20,664(2) $16,151
- --------------- (1) This amount was charged to regulatory assets within deferred charges and other assets as recovery was specifically permitted by the relevant regulators. (2) Uncollectible accounts written off. 101 EXHIBITS INDEX ITEM 14.(A)(3)
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- Plan of Reorganization 2.1 Purchase and Sale Agreement (Louisiana Gas Exhibit 2.1 to Registration Statement on Operations), by and among Citizens Utilities Form S-3/A filed November 6, 2000 (File No. Company (now known as Citizens Communications 333-73705) Company), LGS Natural Gas Company and Atmos Energy Corporation, dated as of April 13, 2000 2.2 Agreement and Plan of Merger and Exhibit 2.2 of Form 10-K for fiscal year Reorganization dated as of September 21, ended September 30, 2001 (File No. 1-10042) 2001, by and among Atmos Energy Corporation, Mississippi Valley Gas Company and the Shareholders Named on the Signature Pages hereto Articles of Incorporation and Bylaws 3.1(a) Restated Articles of Incorporation of the Exhibit 3.1 of Form 10-K for fiscal year Company, as Amended (as of July 31, 1997) ended September 30, 1997 (File No. 1-10042) 3.1(b) Articles of Amendment to the Restated Exhibit 3a of Form 10-Q for quarter ended Articles of Incorporation of Atmos Energy March 31, 1999 (File No. 1- 10042) Corporation as Amended (Texas) 3.1(c) Articles of Amendment to the Restated Exhibit 3b of Form 10-Q for quarter ended Articles of Incorporation of Atmos Energy March 31, 1999 (File No. 1- 10042) Corporation as Amended (Virginia) 3.2(a) Bylaws of the Company (Amended and Restated Exhibit 3.2 of Form 10-K for fiscal year as of November 12, 1997) ended September 30, 1997 (File No. 1-10042) 3.2(b) Amendment No. 1 to Bylaws of Atmos Energy Exhibit 3.1 of Form 10-Q for quarter ended Corporation (Amended and Restated as of March 31, 2001 (File No. 1- 10042) November 12, 1997) 3.2(c) Amendment No. 2 to Bylaws of Atmos Energy Corporation (Amended and Restated as of November 12, 1997) Instruments Defining Rights of Security Holders 4.1 Specimen Common Stock Certificate (Atmos En- Exhibit (4)(b) of Form 10-K for fiscal year ergy Corporation) ended September 30, 1988 (File No. 1-10042) 4.2 Rights Agreement, dated as of November 12, Exhibit 4.1 of Form 8-K dated November 12, 1997, between the Company and BankBoston, 1997 (File No. 1-10042) N.A., as Rights Agent 4.3 First Amendment to Rights Agreement dated as Exhibit 2 of Form 8-A, Amendment No. 1, of August 11, 1999, between the Company and dated August 12, 1999 (File No. 1-10042) BankBoston, N.A., as Rights Agent 4.4 Second Amendment to Rights Agreement dated as Exhibit 4 of Form 10-Q for quarter ended of February 13, 2002, between the Company and December 31, 2001 (File No. 1-10042) EquiServe Trust Company, N.A., as Rights Agent 4.5 Registration Rights Agreement, dated as of Exhibit 4.1 of Form 10-Q for quarter ended June 30, 2003, between Atmos Energy June 30, 2003 (File No. 1-10042) Corporation and Gary A. Morris, as Asset Manager 4.6 Registration Rights Agreement, dated as of Exhibit 99.2 of Form 8-K/A, dated December December 3, 2002, by and among Atmos Energy 3, 2002 (File No. 1-10042) Corporation and the Shareholders of Mississippi Valley Gas Company
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 4.7 Standstill Agreement, dated as of December 3, Exhibit 99.3 of Form 8-K/A, dated December 2002, by and among Atmos Energy Corporation 3, 2002 (File No. 1-10042) and the Shareholders of Mississippi Valley Gas Company 4.8 Form of Indenture between Atmos Energy Exhibit 4.1 to Registration Statement on Corporation and U.S. Bank Trust National Form S-3 filed April 20, 1998 (File No. Association, Trustee 333-50477) 4.9 Indenture between Atmos Energy Corporation, Exhibit 99.3 of Form 8-K dated May 15, 2001 as Issuer, and Suntrust Bank, Trustee dated (File No. 1-10042) as of May 22, 2001 4.10(a) Indenture of Mortgage, dated as of July 15, Exhibit to Registration Statement of United 1959, from United Cities Gas Company to First Cities Gas Company on Form S-3 (File No. Trust of Illinois, National Association, and 33-56983) M.J. Kruger, as Trustees, as amended and supplemented through December 1, 1992 (the Indenture of Mortgage through the 20th Supplemental Indenture) 4.10(b) Twenty-First Supplemental Indenture dated as Exhibit 10.7(a) of Form 10-K for fiscal year of February 5, 1997 by and among United ended September 30, 1997 (File No. 1-10042) Cities Gas Company and Bank of America Illinois and First Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959 4.10(c) Twenty-Second Supplemental Indenture dated as Exhibit 10.7(b) of Form 10-K for fiscal year of July 29, 1997 by and among the Company and ended September 30, 1997 (File No. 1-10042) First Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959 4.11(a) Form of Indenture between United Cities Gas Exhibit to Registration Statement of United Company and First Trust of Illinois, National Cities Gas Company on Form S-3 (File No. Association, as Trustee dated as of November 33-56983) 15, 1995 4.11(b) First Supplemental Indenture between the Exhibit 10.8(a) of Form 10-K for fiscal year Company and First Trust of Illinois, National ended September 30, 1997 (File No. 1-10042) Association, as Trustee dated as of July 29, 1997 4.12(a) Seventh Supplemental Indenture, dated as of Exhibit 10.1 of Form 10-Q for quarter ended October 1, 1983 between Greeley Gas Company June 30, 1994 (File No. 1-10042) ("The Greeley Gas Division") and the Central Bank of Denver, N.A. ("Central Bank") 4.12(b) Ninth Supplemental Indenture, dated as of Exhibit 10.2 of Form 10-Q for quarter ended April 1, 1991, between The Greeley Gas June 30, 1994 (File No. 1-10042) Division and Central Bank 4.12(c) Tenth Supplemental Indenture, dated as of Exhibit 10.4 of Form 10-Q for quarter ended December 1, 1993, between the Company and June 30, 1994 (File No. 1-10042) Colorado National Bank, formerly Central Bank 9 Not Applicable Material Contracts 10.1 Bond Purchase Agreement, dated as of April 1, Exhibit 10.3 of Form 10-Q for quarter ended 1991, between the Greeley Division and June 30, 1994 (File No. 1-10042) Central Bank 10.2(a) Purchase Agreement for 6 3/4% Debentures due Exhibit 99.1 of Form 8-K dated July 22, 1998 2028 by and among Merrill Lynch Co., (File No. 1-10042) NationsBanc Montgomery Securities L.L.C., Edward D. Jones & Co., L.P. and Atmos Energy Corporation dated July 22, 1998
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.2(b) Purchase Agreement for 7 3/8% Senior Notes Exhibit 99.1 of Form 8-K dated May 15, 2001 due 2011 by and among Banc of America (File No. 1-10042) Securities L.L.C., Banc One Capital Markets, Inc., First Union Securities, Inc, Fleet Securities, Inc, SG Cowen Securities Corporation and Atmos Energy Corporation dated May 15, 2001 10.2(c) Purchase Agreement for 5 1/8% Senior Notes Exhibit 1.1 of Form 8-K dated January 13, due 2013 by and among Banc One Capital 2003 (File No. 1-10042) Markets, Inc., SG Cowen Securities Corporation, SunTrust Capital Markets, Inc., Wachovia Securities, Inc., Banc of America Securities LLC, KBC Financial Products USA Inc., U.S. Bancorp Piper Jaffray Inc., Hibernia Southcoast Capital, Inc. and Atmos Energy Corporation dated January 13, 2003 10.2(d) Purchase Agreement for 6,741,500 Shares of Exhibit 99.1 of Form 8-K dated December 14, Common Stock (No Par Value) by and among 2000 (File No. 1-10042) Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Warburg L.L.C., A.G. Edwards & Sons, Inc, Edward D. Jones & Co., L.P. and Atmos Energy Corporation dated December 14, 2000 10.2(e) Purchase Agreement for 4,100,000 Shares of Exhibit 1.1 of Form 8-K dated June 18, 2003 Common Stock (No Par Value) by and among (File No. 1-10042) Merrill Lynch & Co., Merrill Lynch, Pierce Fenner & Smith Incorporated, UBS Securities LLC, A.G. Edwards & Sons, Inc., Edward D. Jones & Co., L.P. and Atmos Energy Corporation dated June 18, 2003 10.3(a) 364-Day Revolving Credit Agreement, dated as Exhibit 10.1 of Form 10-Q for quarter ended of July 29, 2003, among Atmos Energy June 30, 2003 (File No. 1-10042) Corporation, Bank One, NA, Suntrust Bank and Bank of America, N.A. and the lenders identified therein 10.3(b) Uncommitted Amended and Restated Credit Exhibit 10.1 of Form 10-Q for quarter ended Agreement, dated to be effective July 1, June 30, 2002 (File No. 1-10042) 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(c) First Amendment, entered into effective as of Exhibit 10.1 of Form 10-Q for quarter ended December 23, 2002, to the Uncommitted Amended March 31, 2003 (File No. 1-10042) and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(d) Second Amendment, entered into effective as Exhibit 10.2 of Form 10-Q for quarter ended of February 7, 2003, to the Uncommitted March 31, 2003 (File No. 1-10042) Amended and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(e) Third Amendment, entered into effective as of Exhibit 10.3 of Form 10-Q for quarter ended February 28, 2003, to the Uncommitted Amended March 31, 2003 (File No. 1-10042) and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.3(f) Fourth Amendment, entered into effective as Exhibit 10.4 of Form 10-Q for quarter ended of March 31, 2003, to the Uncommitted Amended March 31, 2003 (File No. 1-10042) and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(g) Fifth Amendment and Waiver, entered into Exhibit 10.5 of Form 10-Q for quarter ended effective as of April 28, 2003, to the March 31, 2003 (File No. 1-10042) Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(h) Sixth Amendment to Credit Agreement, Global Amendment to Loan Documents and Waiver, en- tered into effective as of October 1, 2003, to the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Woodward Marketing, L.L.C., Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto 10.3(i) Bridge Credit Agreement, dated as of October Exhibit 10.8(c) of Form 10-K for fiscal year 7, 2002, among Atmos Energy Corporation, Bank ended September 30, 2002 (File No. 1-10042) One, NA, Wachovia Bank, National Association, Suntrust Bank and Societe Generale, New York Branch Gas Supply Contracts 10.4(a) Firm Gas Service Transportation Agreement No. 123535 dated May 1, 2003 between Atmos Energy Corporation (Colorado-Kansas Division) and Public Service Company of Colorado 10.4(b) Transportation Storage Service Agreement No. Exhibit 10.6(b) of Form 10-K for fiscal year TA-0544 between Greeley Gas Company and ended September 30, 1994 (File No. 1-10042) Southern Star Central Gas Pipeline, Inc. dated October 1, 1993, as renewed to extend to October 1, 2008 10.4(c) Firm Transportation Service Agreement No. 33182000D, Rate Schedule TF-1, dated April 1, 2003 between Atmos Energy Corporation (Colorado-Kansas Division) and Colorado Interstate Gas Company 10.4(d) No-Notice Storage and Transportation Delivery Service Agreement No. 31044000A, Rate Sched- ule NNT-1, dated October 1, 2002 between Atmos Energy Corporation (Colorado-Kansas Division) and Colorado Interstate Gas Company 10.4(e) Transportation-Storage Contract No. TA-0614 Exhibit 10.6 of Form 10-Q for quarter ended (Request 0180) between Greeley Gas Company March 31, 1998 (File No. 1-10042) (transferred from United Cities Gas Company effective January 1, 2000) and Southern Star Central Gas Pipeline, Inc. dated October 1, 1993, as amended to extend to October 1, 2005 10.4(f) Transportation-Storage Contract No. TA-0611 Exhibit 10.7 of Form 10-Q for quarter ended (Request 0002) between Greeley Gas Company March 31, 1998 (File No. 1-10042) (transferred from United Cities Gas Company effective January 1, 2000) and Southern Star Central Gas Pipeline, Inc. dated October 1, 1993, as renewed to extend to October 1, 2008
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.5(a) Agreement for Firm Intrastate Transportation Exhibit 10.1 of Form 10-Q for quarter ended of Natural Gas in the State of Louisiana March 31, 1998 (File No. 1-10042) between Trans La (now known as Atmos Energy Louisiana) and Louisiana Intrastate Gas Company L.L.C. (LIG) dated December 22, 1997 and effective July 1, 1997, as amended to extend to July 1, 2005 and for successive 1 year terms 10.5(b) Agreement for Firm 311(a)(2) Transportation Exhibit 10.2 of Form 10-Q for quarter ended of Natural Gas in the State of Louisiana March 31, 1998 (File No. 1-10042) between Trans La (now known as Atmos Energy Louisiana) and Louisiana Intrastate Gas Company L.L.C. (LIG) dated December 22, 1997 and effective July 1, 1997, as amended to extend to July 1, 2005 and for successive 1 year terms 10.5(c) No-Notice Service Agreement No. 29865, (formerly Contract No. 29267), Rate Schedule NNS, dated April 1, 2002 between Atmos Energy Corporation (Louisiana Division) and Gulf South Pipeline Company, L.P., as amended to extend to March 31, 2008 10.6(a) Gas Transportation Agreement between Texas Exhibit 10.3 of Form 10-Q for quarter ended Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042) 1, 1993 (Contract No. T3355, zone 3), as amended to extend to November 1, 2004 10.6(b) Gas Transportation Agreement between Texas Exhibit 10.4 of Form 10-Q for quarter ended Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042) 1, 1993 (Contract No. T3819, zone 4), as amended to extend to November 1, 2004 10.6(c) Gas Transportation Agreement between Texas Exhibit 10.5 of Form 10-Q for quarter ended Gas and Western Kentucky Gas dated November December 31, 1993 (File No. 1-10042) 1, 1993 (Contract No. N0210, Zone 2, Contract No. N0340, Zone 3, Contract No. N0435, Zone 4), as amended to extend to November 1, 2004 10.7(a) Gas Transportation Agreement, Contract No. Exhibit 10.17(a) of Form 10-K for fiscal 2550, dated September 1, 1993, between year ended September 30, 1993 (File No. Tennessee Gas Pipeline Company, a division of 1-10042) Tenneco, Inc. ("Tennessee Gas"), and Western Kentucky, Campbellsville Service Area, as amended to extend to November 1, 2007 10.7(b) Gas Transportation Agreement, Contract No. Exhibit 10.17(b) of Form 10-K for fiscal 2546, dated September 1, 1993, between year ended September 30, 1993 (File No. Tennessee Gas and Western Kentucky, Danville 1-10042) Service Area, as amended to extend to November 1, 2007 10.7(c) Gas Transportation Agreement, Contract No. Exhibit 10.17(c) of Form 10-K for fiscal 2385, dated September 1, 1993, between year ended September 30, 1993 (File No. Tennessee Gas and Western Kentucky, 1-10042) Greensburg et al Service Area, as amended to extend to November 1, 2007 10.7(d) Gas Transportation Agreement, Contract No. Exhibit 10.17(d) of Form 10-K for fiscal 2551, dated September 1, 1993, between year ended September 30, 1993 (File No. Tennessee Gas and Western Kentucky, 1-10042) Harrodsburg Service Area, as amended to extend to November 1, 2007 10.7(e) Gas Transportation Agreement, Contract No. Exhibit 10.17(e) of Form 10-K for fiscal 2548, dated September 1, 1993, between year ended September 30, 1993 (File No. Tennessee Gas and Western Kentucky, Lebanon 1-10042) Service Area, as amended to extend to November 1, 2007
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.8 Transportation Service Agreement between Exhibit 10.13 of Form 10-K for fiscal year Energas Company and ONEOK WesTex ended September 30, 2002 (File No. 1-10042) Transmission, L.P. dated January 1, 2002, as amended by Service Orders dated October 1, 2003 to extend to March 31, 2009 10.9 Amarillo Supply Agreement dated January 2, Exhibit 10.7(a) of Form 10-K for fiscal year 1993 between Energas and Pioneer Natural ended September 30, 1994 (File No. 1-10042) Resources, USA, Inc. (formerly Mesa Operating Company) 10.10(a) Gas Transportation Agreement No. 30774, Rate Exhibit 10.1 of Form 10-Q for quarter ended Schedules FT-A and FT-GS, between United December 31, 1999 (File No. 1-10042) Cities Gas Company and East Tennessee Natural Gas Company dated October 1, 1999, as amended to extend to October 31, 2004 10.10(b) Gas Transportation Agreement No. 27311 Exhibit 10.20(c) of Form 10-K for fiscal between United Cities Gas Company and year ended September 30, 2000 (File No. Tennessee Gas Pipeline Company dated November 1-10042) 1, 2000 10.10(c) Service Agreement No. 867760, under Rate Exhibit 10.8 of Form 10-Q for quarter ended Schedule FT, between United Cities Gas March 31, 1998 (File No. 1-10042) Company and Southern Natural Gas Company dated November 1, 1993, as amended to extend to October 31, 2005 10.10(d) Service Agreement No. 867761 under Rate Exhibit 10.9 of Form 10-Q for quarter ended Schedule FT-NN between United Cities Gas March 31, 1998 (File No. 1-10042) Company and Southern Natural Gas Company dated November 1, 1993, as amended to extend to October 31, 2005 10.10(e) FTS-1 Service Agreement No. 59572 between Exhibit 10.20(f) of Form 10-K for fiscal United Cities Gas Company and Columbia Gulf year ended September 30, 2000 (File No. Transmission Company dated November 1, 1998 1-10042) 10.10(f) Gas Transportation Agreement No. 34538 (Rocky Exhibit 10.20(g) of Form 10-K for fiscal Top Expansion) between United Cities Gas Com- year ended September 30, 2000 (File No. pany and East Tennessee Natural Gas Company 1-10042) dated November 1, 2000 10.11 Firm Transportation Service Agreement under Rate Schedule FTS dated November 1, 2002 between Atmos Energy Corporation (Mid-States Division) and Ozark Gas Transmission, L.L.C. as renewed to extend to October 31, 2004 10.12 Service Agreement #400227 for Rate Schedule Exhibit 10.18 of Form 10-K for fiscal year SS-1 between United Cities Gas Company and ended September 30, 2002 (File No. 1-10042) Texas Eastern Transmission Corporation dated May 31, 2000 10.13(a) No Notice Service Agreement No. 16086 dated November 1, 1993 between Mississippi Valley Gas Company and Gulf South Pipeline Company LP., (formerly Koch Gateway Pipeline Co.), as amended to extend to March 31, 2005 10.13(b) Service Agreement No. FSNG46 under Rate Schedule FT and/or FT-NN between Mississippi Valley Gas Company and Southern Natural Gas Company dated November 1, 2000 10.13(c) Firm Contract Storage Service Agreement No. SSNG23 under Rate Schedule CSS between Mississippi Valley Gas Company and Southern Natural Gas Company dated November 1, 1993, as amended to extend to October 31, 2005
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.13(d) Gas Transportation Agreement No. T018170 be- tween Texas Gas and Mississippi Valley Gas Company dated October 29, 2001, as amended to extend to October 31, 2004 10.13(e) Gas Transportation Agreement No. T018171 be- tween Texas Gas and Mississippi Valley Gas Company dated October 29, 2001, as amended to extend to October 31, 2004 10.13(f) Gas Transportation Agreement No. T-15793 between Texas Gas and Mississippi Valley Gas Company dated November 5, 1999 10.13(g) Firm No-Notice Transportation Agreement No. N-0120 between Texas Gas and Mississippi Valley Gas Company dated November 1, 1997, as amended to extend to October 31, 2004 10.13(h) Firm Standby Gas Storage Contract Part A and B between Hattiesburg Gas Storage Company, (formerly Hattiesburg Industrial Gas Sales Company), and Mississippi Valley Gas Company dated February 21, 1990 10.13(i) Firm Standby Gas Storage Contract Phase 1A between Hattiesburg Gas Storage Company and Mississippi Valley Gas Company dated August 24, 1990 10.13(j) Gas Transportation Agreement Contract No. 1443 between Tennessee Gas Pipeline and Mississippi Valley Gas Company dated September 1, 1993, as automatically renewed to extend to August 31, 2007 10.13(k) Gas Transportation Agreement Contract No. 1478 (winter only) between Tennessee Gas Pipeline and Mississippi Valley Gas Company dated November 1, 1993, as amended to extend to March 31, 2005 10.13(l) Gas Transportation Agreement Contract No. 5151 between Tennessee Gas Pipeline and Mississippi Valley Gas Company dated November 1, 1993, as amended to extend to November 30, 2006 Asset Purchase Agreements 10.14 Asset Purchase Agreement by and among Atmos Exhibit 10.1 to Registration Statement on Energy Corporation, Atmos Energy Marketing Form S-3/A filed November 6, 2000 (File No. LLC, Woodward Marketing, Inc., JD and Linda 333-93705) Woodward and James and Rita B. Kifer dated as of August 7, 2000 Executive Compensation Plans and Arrangements 10.15(a)* Form of Atmos Energy Corporation Change in Exhibit 10.21(b) of Form 10-K for fiscal Control Severance Agreement -- Tier I year ended September 30, 1998 (File No. 1-10042) 10.15(b)* Form of Atmos Energy Corporation Change in Exhibit 10.21(c) of Form 10-K for fiscal Control Severance Agreement -- Tier II year ended September 30, 1998 (File No. 1-10042) 10.16* Atmos Energy Corporation Long-Term Stock Plan Exhibit 99.1 of Form S-8 filed July 29, 1997 for the United Cities Gas Company Division (File No. 333-32343) 10.17(a)* Atmos Energy Corporation Executive Retiree Exhibit 10.31 of Form 10-K for fiscal year Life Plan ended September 30, 1997 (File No. 1-10042)
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.17(b)* Amendment No. 1 to the Atmos Energy Exhibit 10.31(a) of Form 10-K for fiscal Corporation Executive Retiree Life Plan year ended September 30, 1997 (File No. 1-10042) 10.18(a)* Description of Financial and Estate Planning Exhibit 10.25(b) of Form 10-K for fiscal Program year ended September 30, 1997 (File No. 1-10042) 10.18(b)* Description of Sporting Events Program Exhibit 10.26(c) of Form 10-K for fiscal year ended September 30, 1993 (File No. 1-10042) 10.19(a)* Atmos Energy Corporation Supplemental Exhibit 10.26 of Form 10-K for fiscal year Executive Benefits Plan, Amended and Restated ended September 30, 1998 (File No. 1-10042) in its Entirety: August 12, 1998 10.19(b)* Atmos Energy Corporation Performance-Based Exhibit 10.32 of Form 10-K for fiscal year Supplemental Executive Benefits Plan, ended September 30, 1998 (File No. 1-10042) Effective Date: August 12, 1998 10.19(c)* Amendment Number One to the Atmos Energy Exhibit 10.2 of Form 10-Q for quarter ended Corporation Performance-Based Supplemental December 31, 2000 (File No. 1-10042) Executive Benefits Plan, Effective Date: January 1, 1999 10.19(d)* Atmos Energy Corporation Performance-Based Exhibit 10.1 of Form 10-Q for quarter ended Supplemental Executive Benefits Plan Trust December 31, 2000 (File No. 1-10042) Agreement, Effective Date December 1, 2000 10.19(e)* Form of Individual Trust Agreement for the Exhibit 10.3 of Form 10-Q for quarter ended Supplemental Executive Benefits Plan December 31, 2000 (File No. 1-10042) 10.20* Atmos Energy Corporation Restricted Stock Exhibit 99.1 of Form S-8 filed February 13, Grant Plan (Amended and Restated as of 1998 (File No. 333-46337) February 12, 1998) 10.21* Atmos Energy Corporation Executive Exhibit 10.33 of Form 10-K for fiscal year Nonqualified Deferred Compensation Plan ended September 30, 1998 (File No. 1-10042) 10.22(a)* Consulting Agreement between the Company and Exhibit 10.2 of Form 10-Q for quarter ended Charles K. Vaughan, effective October 1, 1994 June 30, 1997 (File No. 1-10042) 10.22(b)* Amendment No. 1 to Consulting Agreement Exhibit 10.3 of Form 10-Q for quarter ended between the Company and Charles K. Vaughan, June 30, 1997 (File No. 1-10042) dated May 14, 1997 10.22(c)* Amendment No. 2 to Consulting Agreement Exhibit 10.30(c) of Form 10-K for fiscal between the Company and Charles K. Vaughan, year ended September 30, 1998 (File No. dated August 12, 1998 1-10042) 10.22(d)* Amendment No. 3 to Consulting Agreement Exhibit 10.30(d) of Form 10-K for fiscal between the Company and Charles K. Vaughan, year ended September 30, 1999 (File No. dated November 10, 1999 1-10042) 10.22(e)* Amendment No. 4 to Consulting Agreement Exhibit 10.32(e) of Form 10-K for fiscal between the Company and Charles K. Vaughan, year ended September 30, 2000 (File No. dated November 9, 2000 1-10042) 10.22(f)* Mini-Med/Dental Benefit Extension Agreement Exhibit 10.28(f) of Form 10-K for fiscal dated October 1, 1994 year ended September 30, 2001 (File No. 1-10042) 10.22(g)* Amendment No. 1 to Mini-Med/Dental Benefit Exhibit 10.28(g) of Form 10-K for fiscal Extension Agreement dated August 14, 2001 year ended September 30, 2001 (File No. 1-10042) 10.22(h)* Amendment No. 2 to Mini-Med/Dental Benefit Exhibit 10.1 of Form 10-Q for quarter ended Extension Agreement dated December 31, 2002 December 31, 2002 (File No. 1-10042)
EXHIBIT NUMBER DESCRIPTION PAGE NUMBER OR INCORPORATION BY REFERENCE TO - ------- --------------------------------------------- -------------------------------------------- 10.23* Atmos Energy Corporation Equity Incentive and Exhibit C of Definitive Proxy Statement on Deferred Compensation Plan for Non-Employee Schedule 14A filed December 30, 1998 (File Directors No. 1-10042) 10.24(a)* Atmos Energy Corporation Retirement Plan for Exhibit 10(y) of Form 10-K for fiscal year Outside Directors ended September 30, 1992 (File No. 1-10042) 10.24(b)* Amendment No. 1 to the Atmos Energy Exhibit 10.2 of Form 10-Q for quarter ended Corporation Retirement Plan for Outside December 31, 1996 (File No. 1-10042) Directors 10.25* Atmos Energy Corporation Outside Directors Exhibit 10.28 of Form 10-K for fiscal year Stock-for-Fee Plan (Amended and Restated as ended September 30, 1997 (File No. 1-10042) of November 12, 1997) 10.26(a)* Atmos Energy Corporation 1998 Long-Term Exhibit 10.1 of Form 10-Q for quarter ended Incentive Plan (as amended and restated March 31, 2002 (File No. 1-10042) February 14, 2002) 10.26(b)* Atmos Energy Corporation Annual Incentive Exhibit 10.2 of Form 10-Q for quarter ended Plan for Management (as amended and restated March 31, 2002 (File No. 1-10042) February 14, 2002) 11 Not applicable 12 Computation of ratio of earnings to fixed charges 13 Not applicable 16 Not applicable 18 Not applicable Other Exhibits, as indicated 21 Subsidiaries of the registrant 22 Not applicable 23 Consent of independent auditor, Ernst & Young LLP 24 Power of Attorney Signature page of Form 10-K for fiscal year ended September 30, 2003 31 Certifications by the Company's Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(a) Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification Pursuant to 18 U.S.C Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by the Company's Chief Executive Officer** 32.2 Certification Pursuant to 18 U.S.C Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by the Company's Chief Financial Officer** 99 Annual Certification Pursuant to Section 303A.12 of the New York Stock Exchange Listed Company Manual
- --------------- * This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement." ** These certifications pursuant to 18 U.S.C. Section 1350 by the Company's Chief Executive Officer and Chief Financial Officer, furnished as Exhibits 32.1 and 32.2, respectively, to this Annual Report on Form 10-K, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference. EX-3.2(C) 3 d10753exv3w2xcy.txt AMENDMENT NO. 2 TO BYLAWS Exhibit 3.2(c) AMENDMENT NO. 2 TO BYLAWS OF ATMOS ENERGY CORPORATION (Adopted by the Board of Directors on August 13, 2003) RESOLVED, that the first sentence of Section 10.01 of the Bylaws of the Company (as Amended and Restated as of November 12, 1997) shall be, and hereby is, deleted and replaced in its entirety with the following: 10.01 Certificates Representing Shares. Unless the Articles of Incorporation or these Bylaws provides otherwise, the Board of Directors may provide by resolution the issue of some or all of the shares of any or all of its classes or series with or without certificates, provided that such resolution shall not apply to shares represented by a certificate until such certificate is surrendered to the corporation. Unless the Texas Business Corporation Act or the Virginia Stock Corporation Act provides otherwise, there shall be no differences in the rights and obligations of shareholders based on whether or not their shares are represented by certificates. In the event that the Board of Directors authorizes shares with certificates, the corporation shall deliver certificates representing all shares to which shareholders are entitled. and; FURTHER RESOLVED, that the third sentence of Section 10.01 of the Bylaws of the Company shall be, and hereby is, deleted and replaced in its entirety with the following: The signatures of the Chairman of the Board, President, or Vice President, and the Secretary or Assistant Secretary, upon a certificate may be facsimiles, if the certificate is countersigned by a transfer agent or registered by a registrar, which may also be facsimiles, either of which is other than the corporation itself or an employee of the corporation. EX-10.3(H) 4 d10753exv10w3xhy.txt SIXTH AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10.3(h) SIXTH AMENDMENT TO CREDIT AGREEMENT, GLOBAL AMENDMENT TO LOAN DOCUMENTS AND WAIVER This SIXTH AMENDMENT TO CREDIT AGREEMENT, GLOBAL AMENDMENT TO LOAN DOCUMENTS AND WAIVER (this "Amendment") is entered into effective as of October 1, 2003, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002 (as amended, supplemented or otherwise modified prior to the date hereof, the "Credit Agreement") by and among WOODWARD MARKETING, L.L.C., a Delaware limited liability company (the "Borrower"), the financial institutions parties thereto (the "Banks"), FORTIS CAPITAL CORP., a Connecticut corporation ("Fortis"), as a Bank, as an Issuing Bank, as Collateral Agent and as Administrative Agent for the Banks, and BNP PARIBAS, a bank organized under the laws of France ("BNP Paribas"), as a Bank, as an Issuing Bank, and as Documentation Agent. WHEREAS, the Borrower has requested that the Administrative Agent and each of the Banks agree to waive any Default or Event of Default which may exist under Section 8.02 of the Credit Agreement based solely upon (i) Southern Resources, Inc., a Kentucky corporation ("Southern") and a Subsidiary of the Borrower, merging with and into the Borrower, (ii) Trans Louisiana Industrial Gas Company, Inc., a Delaware corporation ("TLIG") and a Subsidiary of Atmos Energy Marketing, LLC, a Delaware limited liability company ("AEM"), merging with and into AEM, (iii) AEM merging with and into the Borrower, (iv) the existing Guaranty of AEM being concurrently released upon the effective time of such merger, and (v) the Borrower changing its name to "Atmos Energy Marketing, LLC" (the transaction described in the foregoing clauses (i) through (v), the "Restructuring Transaction"). WHEREAS, the Borrower has requested that the Administrative Agent and the Banks agree to amend certain provisions of the Credit Agreement, as more fully set forth herein, in connection with the Restructuring Transaction; and WHEREAS, the Administrative Agent and the Banks are willing to agree to such waivers and amendments, but only on the terms and subject to the conditions set forth in this Amendment; NOW, THEREFORE, in consideration of premises and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Borrower, Fortis, BNP Paribas and the other Banks agree as follows: 1. Defined Terms. Unless otherwise defined herein, terms defined in the Credit Agreement are used herein as therein defined. 2. Amendments. Upon the satisfaction of all of the conditions precedent set forth in Section 5 of this Amendment, the Credit Agreement and the other Loan Documents shall be deemed amended with effect as of October 1, 2003 such that (a) all references in the Credit Agreement and in each other Loan Document to the Borrower as "Woodward Marketing, L.L.C." shall be deleted and replaced with "Atmos Energy Marketing, LLC", (b) the definition of "Guarantors" shall be amended to read: "Guarantor" means Atmos Energy Holdings, Inc." and (c) all references in the Credit Agreement and in each other Loan Document to "Guarantors" shall be deleted and replaced with "Guarantor", and such conforming changes shall be made in such Loan Documents to reflect such change in number. 3. Waiver. The Administrative Agent and each of the Banks hereby waive any Default or Event of Default which may exist under Section 8.02 of the Credit Agreement based solely upon the occurrence of the Restructuring Transaction. 4. Representations. To induce the Administrative Agent and the Banks to enter into this Amendment, Borrower ratifies and confirms each representation and warranty set forth in the Credit Agreement as if such representations and warranties were made on even date herewith, and further represents and warrants (a) that no material adverse change has occurred in the financial condition or business prospects of Borrower since the date of the last financial statements delivered to the Administrative Agent and the Banks, (b) that, other than the violations of Section 8.02 of the Credit Agreement described in this Amendment, which violations have been waived by the Administrative Agent and each of the Banks in Section 3 herein, no Event of Default exists and no event or condition exists or has occurred which with passage of time, or notice, or both, would become an Event of Default (a "Default"), and (c) that Borrower is fully authorized to enter into this Amendment. BORROWER ACKNOWLEDGES THAT THE CREDIT AGREEMENT PROVIDES FOR A CREDIT FACILITY THAT IS COMPLETELY OPTIONAL ON THE PART OF THE BANKS AND THAT THE BANKS HAVE ABSOLUTELY NO DUTY OR OBLIGATION TO ADVANCE ANY REVOLVING LOAN OR TO ISSUE ANY LETTER OF CREDIT. BORROWER REPRESENTS AND WARRANTS TO THE BANKS THAT BORROWER IS AWARE OF THE RISKS ASSOCIATED WITH CONDUCTING BUSINESS UTILIZING AN UNCOMMITTED FACILITY. 5. Conditions Precedent. This Amendment shall become effective, with effect as of October 1, 2003, upon the Administrative Agent and the Banks having received: (a) Payment of all fees and expenses owed to them on October 1, 2003; and 2 (b) Executed originals of each of the following documents and instruments, in form and substance satisfactory to the Administrative Agent and the Banks: (i) this Amendment, duly executed by Borrower and the Banks; (ii) amended and restated Notes of the Borrower, duly executed by the Borrower; (iii) an amendment to the Guaranty, in form and substance satisfactory to the Administrative Agent and the Lenders; (iv) copies of the resolutions of the members of the Borrower authorizing the transactions contemplated hereby and by the Credit Agreement, certified as of the date hereof by the Secretary of the Borrower, and certifying the names and true signatures of the officers of the Borrower authorized to execute, deliver and perform, as applicable, this Amendment and the other Loan Documents; (v) copies of the documents and instruments entered into in connection with the Restructuring Transaction, certified as of the date hereof by a Secretary of the Borrower; (vi) evidence satisfactory to the Administrative Agent that the Restructuring Transaction shall have occurred; (vii) the certificate of formation and the operating agreement of the Borrower as in effect after giving effect to the Restructuring Transaction, all certified by the Secretary of the Borrower as of the date hereof, together with certificates of existence and good standing for the Borrower from the Secretary of State (or similar, applicable Governmental Authority) of its state of formation and each state where the Borrower is qualified to do business, certified as of the date hereof; (viii) an amendment to the financing statement of the Borrower in favor of the Administrative Agent as secured party for the benefit of the Banks, amending the name of the Borrower as provided herein, and evidence that all other filings or actions needed to maintain the perfection of the security interests granted by the Security Agreements have been completed or due provision has been made therefor; (ix) evidence of insurance required to be maintained by the Borrower under the Credit Agreement, reflecting the Borrower's name as amended herein; and 3 (x) such other documents or certificates as the Administrative Agent may reasonably request. Upon the satisfaction of the foregoing conditions precedent, including without limitation an instrument executed and delivered by the Borrower expressly confirming the Borrower's assumption of all obligations of AEM in respect of the Loan Documents upon the effective time of the merger of AEM into the Borrower, the Guaranty of AEM shall be released without further action of any Person. 6. Miscellaneous. (a) No Other Amendments or Waivers. Except as expressly consented to hereby, the Credit Agreement and the other Loan Documents shall remain in full force and effect in accordance with their respective terms, without any consent, amendment, waiver or modification of any provision thereof. (b) Severability. In case any of the provisions of this Amendment shall for any reason be held to be invalid, illegal, or unenforceable, such invalidity, illegality, or unenforceability shall not affect any other provision hereof, and this Amendment shall be construed as if such invalid, illegal, or unenforceable provision had never been contained herein. (c) Execution in Counterparts. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any party hereto may execute this Amendment by signing one or more counterparts. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of an originally executed counterpart of this Amendment. (d) Governing Law. This Amendment shall be construed in accordance with and governed by the laws of the State of New York (without reference to principles of conflicts of laws); provided, however, that the Administrative Agent, the Banks and all Agent-Related Persons shall retain all rights under federal law. (e) Rights of Third Parties. All provisions herein are imposed solely and exclusively for the benefit of Borrower, Administrative Agent, the Banks, Agent-Related Persons, and their permitted successors and assigns, and no other Person shall be a direct or indirect legal beneficiary of, or have any direct or indirect cause of action or claim in connection with this Amendment or any of the other Loan Documents. (f) COMPLETE AGREEMENT. THIS WRITTEN AMENDMENT AND THE OTHER WRITTEN AGREEMENTS ENTERED INTO AMONG THE PARTIES REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF 4 THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES. [SIGNATURE PAGES FOLLOW] 5 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written. WOODWARD MARKETING, L.L.C. (TO BE RENAMED ATMOS ENERGY MARKETING, LLC), a Delaware limited liability company By: /s/ Richard C. Alford ---------------------------------- Name: Richard C. Alford Title: Senior Vice President Borrower's Address: 11251 Northwest Freeway, Suite 400 Houston, Texas 77092 Attention: Ronald W. Bahr Telephone: (713) 688-7771 Facsimile: (713) 688-5124 [Signatures continue on following page.] [Amendment to Credit Agreement] FORTIS CAPITAL CORP., a Connecticut corporation as Administrative Agent, Collateral Agent, Issuing Bank and a Bank By: /s/ Irene Rummel --------------------------------- Name: Irene Rummel Title: Senior Vice President By: /s/ Chad Clark --------------------------------- Name: Chad Clark Title: Vice President 15455 N. Dallas Parkway Suite 1400 Dallas, TX 75001 Telephone: (214) 953-9313 Facsimile: (214) 969-9332 [Signatures continue on following page.] [Amendment to Credit Agreement] BNP PARIBAS, a bank organized under the laws of France as a Bank, Issuing Bank, and Documentation Agent By: /s/ Edward K. Chin ---------------------------------- Name: Edward K. Chin Title: Director By: /s/ Zali Win ---------------------------------- Name: Zali Win Title: Director 787 Seventh Avenue New York, New York 10019 Attention: Ed Chin Telephone: (212) 841-2020 Facsimile: (212) 841-2536 [Signatures continue on following page.] [Amendment to Credit Agreement] SOCIETE GENERALE, as a Bank By: /s/ Barbara Paulsen ---------------------------------- Name: Barbara Paulsen Title: Vice President By: /s/ Emmanuel Chesneau ---------------------------------- Name: Emmanuel Chesneau Title: Director 1221 Avenue of the Americas New York, New York 10020 Attention: Barbara Paulsen Telephone: (212) 278-6496 Facsimile: (212) 278-7417 [Signatures continue on following page.] [Amendment to Credit Agreement] NATEXIS BANQUES POPULAIRES, NEW YORK BRANCH, as a Bank By: /s/ David Pershad ---------------------- Name: David Perhad Title: Vice President By: /s/ Guillaume de Parscau ---------------------------- Name: Guillaume de Parscau Title: First Vice President & Manager, Commodities Finance Group 1251 Avenue of the Americas, 34th Floor New York, New York 10020 Attention: David Pershad Telephone: (212) 872-5015 Facsimile: (212) 354-9095 RZB FINANCE LLC, as a Bank By: /s/ Frank J.Yautz ------------------------ Name: Frank J. Yautz Title: First Vice President By: /s/ Pearl Geffers ------------------------- Name: Pearl Geffers Title: First Vice President 1133 Avenue of the Americas New York, New York 10036 Attention: Hermine Kirolos Telephone: (212) 845-4114 Facsimile: (212) 944-6389 [Signatures continue on following page.] [Amendment to Credit Agreement] CONSENTED TO: ATMOS ENERGY HOLDINGS, INC., GUARANTOR By: /s/ Ronald W. Bahr ------------------------ Name: Ronald W. Bahr Title: Vice President 1800 Three Lincoln Centre 5430 LBJ Freeway Dallas, TX 75240 [Amendment to Credit Agreement] EX-10.4(A) 5 d10753exv10w4xay.txt FIRM GAS TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.4(a) Contract No. 123535 FIRM GAS TRANSPORTATION SERVICE AGREEMENT THIS SERVICE AGREEMENT (Agreement), made and entered into as of this 1st day of May, 2003, by and between Public Service Company of Colorado (Company), a Colorado corporation, having a mailing address of P.O. Box 840, Denver, Colorado, 80202, and Atmos Energy Corporation (Shipper), a Texas corporation, having a mailing address of 700 Three Lincoln Centre, 5430 LBJ Freeway, P.O. Box 650205, Dallas, Texas 75265-0205. Company and Shipper are collectively referred to as the "Parties." THE PARTIES REPRESENT: Shipper has by separate agreement acquired supplies of natural gas, hereinafter referred to as "Shipper's Gas;" Shipper has made the necessary arrangements and/or has entered into separate agreements to cause Shipper's Gas to be delivered to Company's Receipt Point(s) as specified in Exhibit(s) "A- 1" through "C-2;" Shipper has requested and Company agrees to receive and transport Shipper's Gas from the Receipt Point(s) to the Delivery Point(s), as specified in Exhibit(s) "A-l" through "C-2," on a firm capacity basis and, if applicable, to sell gas to Shipper on a firm supply reservation basis; and Shipper assumes responsibility for the installation and maintenance costs for a communication line necessary for electronic metering for the facility(s) specified in Exhibit(s) "A-1," "B-1" and "C-1." THEREFORE, THE PARTIES AGREE AS FOLLOWS: 1. Shipper acknowledges and agrees that gas transportation service provided hereunder is subject to the terms and conditions of Company's applicable gas transportation tariff as on file and in effect from time to time with the Public Utilities Commission of the State of Colorado (Commission) and such terms and conditions are incorporated herein as part of this Agreement. 2. Rates and Payment: Transportation service, Firm Capacity service and Firm Supply Reservation service provided by Company under this Service Agreement shall be paid for by Shipper at the charges under the standard rate set forth in Company's gas transportation tariff unless otherwise specified in Exhibit(s) "A-l" through "C-2." Applicable facility charges shall be paid at the rate set forth in Company's Gas Transportation Tariff unless otherwise specified in Exhibit(s) "A-l" through "C-2." 3. Back-up Supply Sales Service: In the event that adequate supplies of Shipper's gas are not available for receipt by Company, Company shall sell to Shipper sufficient quantity(s) of natural gas as necessary to meet Shipper's backup natural gas supply needs, up to the Total Peak Day Quantity for the Firm Supply Reservation Service (if any) as specified in Exhibit(s) "A-l" through "C-2," but in no event greater at any Delivery Point than the Firm Capacity Peak Day Quantity at such Delivery Point as specified in Exhibit(s) "A-l" through "C-2," except as provided for in paragraph 11 hereof. If Shipper does not purchase Firm Supply Reservation Service or exceeds the Firm Supply Reservation Quantity, Shipper may nominate and purchase from Company Back-up Supply Sales Service on an interruptible basis, to the extent such Back-up Supply Sales Service is available, in the event that adequate supplies of Shipper's Gas are not available for receipt by Company. Applicable charges shall be as set forth in Company's tariff. 4. Quality: Gas delivered by the Shipper or for the Shipper's account at the Receipt Point(s) as specified in Exhibit(s) "A-l" through "C-2" shall conform to the specifications for gas as specified in Exhibit "D" and Exhibit "E." 5. Term - Effective Date: Service hereunder shall commence effective May 1, 2003 and, unless otherwise mutually agreed, shall continue through April 30, 2005 and from year to year thereafter until terminated by either party effective upon the expiration of the initial term or May 1 of any succeeding year upon six (6) months written notice. 6. Notices: Except as otherwise provided, any notice or information that either party may desire to give to the other regarding this agreement shall be in writing to the following address, or to such other address as either of the parties shall designate in writing. COMPANY: SHIPPER: Payments Only: Atmos Energy Corporation Xcel Energy P.O. Box 650205 P.O. Box 9477 Dallas, Texas 75265-0205 Denver, Colorado 80217-0230 Invoices only: Phone: (303)623-1234 Attn: Gas Purchase Accounting Dept. Fax: (303)294-2136 Phone: (972)855-3296 Fax: (214)550-9369 Contracts and Notices: Attn: Contract Administration Phone: (972)855-3753 Fax: (972)855-3773 E-Mail Capacity Overrun Notification: Attn: Phil Davis Phillip.Davis@atmosenergy.com All Others: Xcel Energy All Others: 550 15th Street Atmos Energy Corporation Suite 500 Attn: Gas Supply Dept Denver, Colorado 80202 1301 Pennsylvania, Suite 800 Attn: Unit Manager, Gas Transportation Denver, Colorado 80203-5014 Phone: (303)294-8318 Phone: (303)831-5667 Fax: (303)294-2757 Fax: (303)831-9549 - 2 - Routine communications, including monthly statements and payments, shall be considered as duly delivered or furnished three (3) days after being mailed or when transmitted electronically. 7. Assignment - Consent: This Service Agreement shall not be assigned by either party hereto without the prior written consent of the other party. Consent for assignment of this Service Agreement shall not be unreasonably withheld by or from either party. 8. Cancellation of Prior Agreement: This Service Agreement supersedes, cancels and terminates, as of the date of this Service Agreement, the following agreements and any amendments thereto: Gas Transportation Service Agreement, dated 11/1/98 (Document No. 123535), between Greeley Gas Company, a division of Atmos Energy Company and Public Service Company of Colorado 9. Maximum Capacity by Zone: (a) Administrative circumstances require the separation of electronically metered and non-electronically metered volumes into two separate Exhibits covering the same regional area, as reflected in the attached Exhibit "A-l" (Electronically Metered Front Range) and Exhibit "A-2" (Non-Electronically Metered Front Range), Exhibit "B-l" (Electronically Metered Southern) and Exhibit "B-2" (Non-Electronically Metered Southern(, and Exhibit "C-l" (Electronically Metered Western) and Exhibit "C-2" (Non-Electronically Metered Western). When electronic measurement facilities are installed and their proper operation is mutually agreed to by both parties for any Delivery Point identified on any Non-Electronically Metered Exhibit A-2, B-2 and C-2 attached hereto, such Delivery Point, its associated Peak Day Quantity and allocable Receipt Point Capacity shall be transferred to the applicable Electronically Metered Exhibit effective the first day of the following month. (b) Transporter shall make available firm transportation service hereunder up to the maximum contracted volume by Zone reflected on Exhibits A-3, B-3 and C-3 attached hereto. A Zone is an operationally contiguous segment of Company's delivery system within an Exhibit area. A Zone may contain Delivery Points from both Electronically and Non-Electronically Metered Exhibits, i.e., the Front Range Area Zones 1,2,3,4 and 5, comprised of Delivery Points under Exhibits "A-l" and "A-2", the Southern Area Zones 1, 2 and 3, comprised of Delivery Points under Exhibit "B-l" and "B-2", and the Western Area Zones 1, 2 and 3, comprised of Delivery Points under Exhibits "C-1" and "C-2". Exhibits A-3, B-3 and C-3 attached hereto identify the Zones and associated Delivery Point and Peak Day Quantities available to Shipper hereunder. 10. Delivery Point Peak Day Quantity: (a) The Delivery Points reflected in the attached Exhibits "A-l" through "C-2" are interconnections between Company's pipeline system and Shipper's downstream natural gas facilities and the parties recognize the mutual operational benefits of providing for flexibility in coordinating gas flows at each of these Delivery Points. The Peak Day Quantities identified in the attached Exhibits "A-l" through "C-2" represent Shipper's current and best information of - 3 - Delivery Point peaking volumes. Shipper and Company agree that the parties will reevaluate these volumes on a periodic basis, but at least once annually, to determine if and at what level any adjustments to the individual Delivery Point Peak Day Quantities are needed. Company does not guarantee its ability to make firm deliveries for quantities in excess of the individual Delivery Point Peak Day Quantities identified on the above referenced Exhibits. Requests for increased capacity shall be subject to the terms of Company's tariff. (b) (i) On a monthly basis, Company will review the actual deliveries made to these points and, provided the total volumes delivered within a Zone do not exceed the total contracted-for volume applicable to the corresponding Delivery Points within the Zone, Company will authorize any volume exceeding the Delivery Point Peak Day Quantity as authorized overrun gas; provided, however, in no event shall any volume at any Delivery Point ever exceed the design capacity of Company's facilities for such point. Should delivered volumes at any Delivery Point consistently exceed the Peak Day Quantity for that point, Shipper will request and Company will accept, subject to available capacity, an increase in the contracted-for Peak Day Quantity at the specified Delivery Point. In increasing the contracted volume at a Delivery Point, Shipper may shift volumes from other Delivery Point(s) within the same Zone if volumes delivered at such other Delivery Point(s) do not exceed their established maximum Peak Day Quantities. During quarterly meetings, Company and Shipper shall review Delivery Points which have exceeded Peak Day Quantities and, if the Parties agree that such overrun(s) are recurring or are expected to be recurring, Shipper shall request an increase to the Delivery Point Peak Day Quantity. (ii) If on any day total deliveries within a Zone exceed the combined Peak Day Quantities of Delivery Points within the Zone, Company shall provide Shipper with written notification of such overrun and, subject to available capacity, the increase in Delivery Point Peak Day Quantity(s) that will be implemented to increase the Zone combined Peak Day Quantities to the actual maximum day usage. Within ten business days following such written notification, Shipper may request and Company will authorize, subject to available capacity, revision(s) in the Peak Day Quantity(s) for the Delivery Point(s) identified by the Company in said notification in order that the combined Zone Peak Day Quantity shall be equal to the maximum daily usage experienced for that Zone. Unless otherwise agreed to by the parties, the new Peak Day Quantities shall become effective the first day of the month following the month in which the Zone overrun occurred. If Company, in its sole opinion, determines that sufficient firm capacity is unavailable for any such requested increase, then Company shall provide written notification to Shipper of the Company's denial of Shipper's requested increase of firm capacity. Any unauthorized quantities in excess of the maximum Zone capacity occurring after such written notification shall be deemed unauthorized overrun gas, subject to unauthorized overrun capacity charges as set forth in Company's tariff. (c) If, pursuant to any applicable state law or administrative action, order, or regulation Shipper restructures its gas utility services to provide unbundled gas sales and transportation services to some or all of its customers, and such restructuring results in Shipper holding Peak Day Quantities under this Agreement in excess of that required to provide service to the markets served by Shipper using the gas transportation service provided under this Agreement subsequent to such restructuring ("Excess Capacity"), Shipper shall have the right to reduce the Peak Day Quantities hereunder by the quantity of such Excess Capacity to the extent Shipper is unable, - 4 - through the use of its best efforts, to assign any of such Excess Capacity to third parties or to acquire the necessary regulatory approvals to permit Shipper to recover the costs of such Excess Capacity through its service rates or charges. Any such reduction to the Peak Day Quantities hereunder shall become effective upon the implementation date of Shipper's restructuring of services. If Shipper elects to exercise its right to reduce Peak Day Quantities hereunder pursuant to this subsection, Shipper shall provide Company at least ninety (90) days prior written notice of such election. 11. Because daily usage information is unavailable until the succeeding month for non-electronically metered Delivery Points, for all Delivery Points listed on Exhibits "A-2," "B-2" and "C-2," Shipper will nominate transportation volumes based on all infonnation Shipper deems appropriate including but not limited to historic usage information and projected load requirements utilizing anticipated weather conditions. Therefore, imbalances accrued with respect to such non-electronically metered Delivery Points are exempt from only the current-month balancing provisions of Company's Tariff as they would apply to this Agreement, so long as there is no determination by the Colorado Public Utilities Commission that such an exemption is unlawful. 12. Exhibit(s) and Addendums: All exhibits attached hereto are incorporated into the terms of this Agreement. 13. This Agreement shall be governed by and construed in accordance with the laws of the State of Colorado. IN WITNESS WHEREOF, the parties have executed this Firm Gas Transportation Service Agreement as of the day and year first above written. COMPANY: SHIPPER: PUBLIC SERVICE COMPANY ATMOS ENERGY CORPORATION OF COLORADO /s/ Cynthia A. Evans /s/ Gary Schlessman - ----------------------------------- ------------------------------------- By Cynthia A. Evans By Gary Schlessman Vice President President, Colorado-Kansas Division Reviewed Legal Taxpayer ID. No. 84-0296600 Taxpayer I.D. No. 75-1743247 - 5 - Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "A-l" ELECTRONICALLY METERED FRONT RANGE TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity Dth/Day Utilization Curve - ------------------------------------------------------------------------------------------------- Front Range Pipeline - Owl Creek 16,540 General CIG Ault 9,893 General CIG Ft. Lupton 14,949 General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Commodity Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate - ----------------------------------------------------------------------------------------------------------------------------- Platteville 906412745 609 TF N/A Standard 4/30/05 Monfort Meas Stat. 706412727 36 TF N/A Standard 4/30/05 Kersey Group 706412713 80 TF N/A Standard 4/30/05 Lasalle 406412719 702 TF N/A Standard 4/30/05 Ault #1 & #2 306412692 650 TF N/A Standard 4/30/05 North Greeley 106412730 10,300 TF N/A Standard 4/30/05 Promontory 770150163 693 TF N/A Standard 4/30/05 West Greeley 606412761 11,078 TF NA Standard 4/30/05 Lucerne #1 606412723 150 TF N/A Standard 4/30/05 South Greeley 106412754 10,100 TF N/A Standard 4/30/05 Eaton #1 & #2 206412763 3,800 TF N/A Standard 4/30/05
Total Firm Capacity Reservation Peak Day Quantity: 38,198 Dth 3. FIRM SUPPLY RESERVATION SERVICE Total Firm Supply Reservation Quantity available for delivery to all of Shipper's Delivery Points as may be nominated from time to time under contract numbers 123535 and 177473: 3,005 Dth Contract No.: 123535 Effective Date of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "A-2" NON-ELECTRONICALLY METERED FRONT RANGE TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ------------------------------------------------------------------------------------------------- Front Range Pipeline-Owl Creek 3,460 General CIG Ft Lupton 51 General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Commodity Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate - ----------------------------------------------------------------------------------------------------------------------------- Keenesburg 306412710 353 TF N/A Standard 4/30/2005 Gilcrest 506412766 321 TF N/A Standard 4/30/2005 Prospect Valley 306412748 31 TF N/A Standard 4/30/2005 South Gate Trailer 106412768 54 TF N/A Standard 4/30/2005 South Roggen 106412773 5 TF N/A Standard 4/30/2005 Roggen 706412751 39 TF N/A Standard 4/30/2005 Nunn 206412739 151 TF N/A Standard 4/30/2005 West LaSalle Group 506412771 34 TF N/A Standard 4/30/2005 Hill-N-Park 206412697 293 TF N/A Standard 4/30/2005 Corsey Group 906412694 57 TF N/A Standard 4/30/2005 Pierce 606412742 349 TF N/A Standard 4/30/2005 Greeley Farm Taps 980121701 1000 N/A N/A Standard 4/30/2005 West Hudson 306412705 299 TF N/A Standard 4/30/2005 Hudson 406412700 338 TF N/A Standard 4/30/2005 East Keenesburg 606412695 48 TF N/A Standard 4/30/2005 Kersey Farm Taps TBD 20 N/A N/A Standard 4/30/2005 Gilcrest Farm Taps TBD 80 N/A N/A Standard 4/30/2005 Ault Farm Taps TBD 300 N/A N/A Standard 4/30/2005 Hudson Farm Taps TBD 30 N/A N/A Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 3,802 Dth Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "A-3" - FRONT RANGE ZONES TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company)
Firm Capacity Peak Day Zone Delivery Point(s) Load Point Quantity (Dth) - ------------------------------------------------------------------------------ FR ZONE 1 Kersey Group 706412713 80 Kersey Farm Taps 20 TOTAL FR ZONE 1: 100 FR ZONE 2 West LaSalle Group 506412771 34 Lasalle 406412719 702 Platteville 906412745 609 Gilcrest 506412766 321 South Gate Trailer 106412768 54 Gilcrest Farm Taps 80 TOTAL FR ZONE 2: 1,800 FR ZONE 3 Monfort Meas Stat. 706412727 36 Hill-N-Park 206412697 293 North Greeley 106412730 10,300 West Greeley 606412761 11,078 South Greeley 106412754 10,100 Promontory 770150163 693 Greeley Farm Taps 980121701 1000 TOTAL FR ZONE 3: 33,500
Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "A-3" - FRONT RANGE ZONES continued
Firm Capacity Peak Day Zone Delivery Point(s) Load Point Quantity (Dth) - ---------------------------------------------------------------------------- FR ZONE 4 Lucerne #1 & #2 606412723 150 Eaton #1 & #2 206412763 3,800 Nunn 206412739 151 Ault #l & #2 306412692 650 Pierce 606412742 349 Ault Farm Taps 300 TOTAL FR ZONE 4: 5,400 FR ZONE 5 Prospect Valley 306412748 31 South Roggen 106412773 5 Roggen 706412751 39 Keenesburg 306412710 353 Corsey Group 906412694 57 West Hudson 306412705 299 Hudson 406412700 338 East Keenesburg 606412695 48 Hudson Farm Taps 30 TOTAL FR ZONE 5: 1,200 TOTAL FR ZONES 42,000
Contract No.: 123535 Effective Date of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "B-l" ELECTRONICALLY METERED SOUTHERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ------------------------------------------------------------------------------------------------- Outlet of Tiffany Compressor Station 6,500 Stabilized
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Commodity Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate - ---------------------------------------------------------------------------------------------------------------------------- Chalk Creek 206412678 86 TF N/A Standard 4/30/2005 West Gunnison Town Border 906412707 596 TF N/A Standard 4/30/2005 East Gunnison Town Border Station 306412687 2,338 TF N/A Standard 4/30/2005 Salida Town Border Station 206412701 2,523 TF N/A Standard 4/30/2005 Crested Butte Town Border Station 406412639 754 TF N/A Standard 4/30/2005 Poncha Springs 706412690 108 TF N/A Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 6,405 Dth Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "B-2" NON-ELECTRONICALLY METERED SOUTHERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ------------------------------------------------------------------------------------------------- Outlet of Tiffany Compressor Station 807 Stabilized
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Commodity Delivery Point(s) Load Point (Dth) Charge Facility Charge Charge Term of Rate - --------------------------------------------------------------------------------------------------------------------------- Durango Farm Tap 660156934 1 N/A NA Standard 4/30/2005 Gunnison Farm Tap 606412681 150 N/A NA Standard 4/30/2005 Tomichi Village 106412706 29 TF NA Standard 4/30/2005 Salida Farm Taps 270039611 231 N/A NA Standard 4/30/2005 Crested Butte Farm Taps 806412642 260 N/A NA Standard 4/30/2005 Crested Butte South 960022981 124 TF NA Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 795 Dth Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "B-3" SOUTHERN ZONES TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company)
Firm Capacity Peak Day Zone Delivery Point(s) Load Point Quantity (Dth) - ----------------------------------------------------------------------------------------------- SO. ZONE 1 Crested Butte Town Border Station 406412639 754 Crested Butte South 960022981 124 Crested Butte Farm Taps 806412642 260 TOTAL SO. ZONE 1 : 1,138 SO. ZONE 2 West Gunnison Town Border 906412707 596 East Gunnison Town Border Station 306412687 2,338 Gunnison Farm Tap 606412681 150 Tomichi Village 106412706 29 TOTAL SO. ZONE 2: 3,113 SO. ZONE 3 Salida Town Border Station 206412701 2,523 Salida Farm Taps 270039611 231 Chalk Creek 206412678 86 Poncha Springs 706412690 108 Durango Farm Tap 660156934 1 TOTAL SO. ZONE 3: 2,949 TOTAL SO. ZONES: 7,200
Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "C-l" ELECTRONICALLY METERED WESTERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ---------------------------------------------------------------------- KNGWRD 680 General MOFRRO 575 General LONGCA 266 General NF1GCA 1,770 General NF1GHC 3,540 General NF2GCA 3,540 General ROSGCA 89 General TERGCA 22 General TWIGCA 66 General CIG Ft Lupton General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Facility Commodity Delivery Point(s) Load Point (Dth) Charge Charge Charge Term of Rate - ---------------------------------------------------------------------------------------------------------------------------- Meeker 706413010 1,057 TF N/A Standard 4/30/2003 Yampa Valley 850040820 417 TF N/A Standard 4/30/2003 Steamboat II West 206412758 178 TF N/A Standard 4/30/2003 Steamboat TBS 306412772 1,231 TF N/A Standard 4/30/2003 Brooklyn Station 606412737 624 TF N/A Standard 4/30/2003 Craig 206412744 3,822 TF N/A Standard 4/30/2003 Hayden TBS 506412747 567 TF N/A Standard 4/30/2003 Mt. Werner #1 506412752 3,968 TF N/A Standard 4/30/2003
Total Firm Capacity Reservation Peak Day Quantity: 11,864 Dth Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "C-2" NON-ELECTRONICALLY METERED WESTERN TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company) 1. PRIMARY RECEIPT POINT(S)
Receipt Point Peak Day Quantity - Dth/Day Utilization Curve - ----------------------------------------------------------------------------------- KNGWRD 88 General MOFRRO 75 General LONGCA 34 General NF1GCA 230 General NF1GHC 460 General NF2GCA 460 General ROSGCA 11 General TERGCA 3 General TWIGCA 9 General CIG Ft Lupton General
2. FIRM CAPACITY SERVICE - DELIVERY POINT(S)
Firm Capacity Service Transport- Peak Day and ation Quantity Facility Specific Facility Commodity Delivery Point(s) Load Point (Dth) Charge Charge Charge Term of Rate - ----------------------------------------------------------------------------------------------------------------------------- Milner Town Brder 106412749 63 TF N/A Standard 4/30/2005 Craig Farm Taps 570067947 143 N/A N/A Standard 4/30/2005 Meeker Farm Taps 906413009 42 N/A N/A Standard 4/30/2005 Thompson Hill 406412762 74 TF N/A Standard 4/30/2005 Steamboat Springs Farm Taps 906412769 147 N/A N/A Standard 4/30/2005
Total Firm Capacity Reservation Peak Day Quantity: 469 Dth Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "C-3" WESTERN ZONES TO THE FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN ATMOS ENERGY CORPORATION (Shipper) AND PUBLIC SERVICE COMPANY OF COLORADO (Company)
Firm Capacity Peak Day Zone Delivery Point(s) Load Point Quantity (Dth) - -------------------------------------------------------------------------------- W. ZONE 1 Meeker 706413010 1,057 Meeker Farm Taps 906413009 42 TOTAL W. ZONE 1 1,099 W. ZONE 2 Craig 206412744 3,822 Craig Farm Taps 570067947 143 Hayden TBS 506412747 567 Thompson Hill 406412762 74 TOTAL W. ZONE 2 4,606 W. ZONE 3 Mt. Werner #1 506412752 3,968 Brooklyn Station 606412737 624 Milner Town Brder 106412749 63 Yampa Valley 850040820 417 Steamboat TBS 306412772 1,231 Steamboat II West 206412758 178 Steamboat Springs Farm Taps 906412769 147 TOTAL W. ZONE 3 6,628 TOTAL W ZONES: 12,333
Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "D" GAS UTILIZATION CURVES Stabilized Utilization Curve Public Service Company of Colorado STABILIZED UTILIZATION CURVE [GRAPH SHOWING STABILIZED UTILIZATION CURVE] The Utilization Curve is a general representation of the natural gas quality which is acceptable from a utilization standpoint. However, the gas composition must be known in order to determine if a supply is acceptable and can be interchanged with supplies in a pipeline system. PSCo reserves the right in all instances to evaluate gas composition to determine system compatibility and to refuse any gas which is unacceptable from a utilization basis. Contract No.: 123535 Effective Date Of Agreement: 5/01/2003 Effective Date of Exhibit: 5/01/2003 EXHIBIT "E" GAS UTILIZATION CURVES General Utilization Curve Public Service Company of Colorado GENERAL UTILIZATION CURVE [GRAPH SHOWING GENERAL UTILIZATION CURVE] The Utilization Curve is a general representation of the natural gas quality which is acceptable from a utilization standpoint. However, the gas composition must be known in order to determine if a supply is acceptable and can be interchanged with supplies in a pipeline system. PSCo reserves the right in all instances to evaluate gas composition to determine system compatibility and to refuse any gas which is unacceptable from a utilization basis. EX-10.4(C) 6 d10753exv10w4xcy.txt FIRM TRANSPORTATION SERVICE AGREEMENT EXHIBIT 10.4(c) Contract No. 33182000D GGC-10476-CO Firm Transportation Service Agreement Rate Schedule TF-1 between COLORADO INTERSTATE GAS COMPANY and ATMOS ENERGY CORPORATION Dated: APRIL 1, 2003 Contract No. 33182000D TRANSPORTATION SERVICE AGREEMENT RATE SCHEDULE TF-1 The Parties identified below, in consideration of their mutual promises, agree as follows: 1. TRANSPORTER: COLORADO INTERSTATE GAS COMPANY 2. SHIPPER: ATMOS ENERGY CORPORATION 3. APPLICABLE TARIFF: Transporter's FERC Gas Tariff, First Revised Volume No. 1, as the same may be amended or superseded from time to time ("the Tariff). 4. CHANGES IN RATES AND TERMS: Transporter shall have the right to propose to the FERC changes in its rates and terms of service, and this Agreement shall be deemed to include any changes which are made effective pursuant to FERC Order or regulation or provisions of law, without prejudice to Shipper's right to protest the same. 5. TRANSPORTATION SERVICE: Transportation Service at and between Primary Point(s) of Receipt and Primary Point(s) of Delivery shall be on a firm basis. Receipt and Delivery of quantities at Secondary Point(s) of Receipt and/or Secondary Point(s) of Delivery shall be in accordance with the Tariff. 6. POINTS OF RECEIPT AND DELIVERY: Shipper agrees to Tender Gas for Transportation Service and Transporter agrees to accept Receipt Quantities at the Primary Point(s) of Receipt identified in Exhibit "A." Transporter agrees to provide Transportation Service and Deliver Gas to Shipper (or for Shipper's account) at the Primary Point(s) of Delivery identified in Exhibit "A." Minimum and maximum receipt and delivery pressures, as applicable, are listed on Exhibit "A." 7. RATES AND SURCHARGES: As set forth in Exhibit "B." For example, Transporter and Shipper may agree that a specified discount rate will apply: (a) only to certain specified firm service entitlements under this Agreement; (b) only if specified quantity levels are actually achieved under this Agreement (with higher rates, charges, and fees applicable to all quantities above those levels, or to all quantities under the Agreement if the specified levels are not achieved); (c) only to production reserves committed by the Shipper; (d) only during specified time periods; (e) only to specified Point(s) of Receipt, Pomt(s) of Delivery, mainline area segments, supply areas, Transportation routes, or defined geographical areas; or (f) in a specified relationship to the quantities actually Delivered (i.e., that the rates shall be adjusted in a specified relationship to quantities actually Delivered); provided, however, that any such discounted rates set forth above shall be between the minimum and maximum rates applicable to the sendee provided under this Agreement. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter's maximum rates so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates that had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable. 8. NEGOTIATED RATE AGREEMENT: YES____ NO X 9. MAXIMUM DAILY QUANTITY (MDQ):
MDQ (Dth/d) EFFECTIVE - -------------------------------- 6,121 4/01/03-9/30/06
10. TERM OF AGREEMENT: Beginning: APRIL 1, 2003 Extending through: SEPTEMBER 30, 2006 Contract No. 33182000D 11. NOTICES, STATEMENTS, AND BILLS: TO SHIPPER: INVOICES FOR TRANSPORTATION: Atmos Energy Corporation 1301 Pennsylvania, Suite 800 Denver, Colorado 80203-5015 Attention: Gas Supply Colorado-Kansas Service Area ALL NOTICES: Atmos Energy Corporation P. O. Box 650205 Dallas, Texas 75265-0205 Attention: Contract Administration Colorado-Kansas Service Area TO TRANSPORTER: See Payments, Notices, Nominations, and Points of Contact sheets in the Tariff. 12. SUPERSEDES AND CANCELS PRIOR AGREEMENT: When this Agreement becomes effective, it shall cancel and supersede the following agreement between the Parties: The Firm Transportation Service Agreement between Transporter and Shipper dated OCTOBER 1, 2001, referred to as Transporter's Agreement No. 33182000C. 13. ADJUSTMENTS TO RATE SCHEDULE TF-1 AND/OR GENERAL TERMS AND CONDITIONS: N/A. 14. INCORPORATION BY REFERENCE: This Agreement in all respects shall be subject to the provisions of Rate Schedule TF-1 and to the applicable provisions of the General Terms and Conditions of the Tariff as filed with, and made effective by, the FERC as same may change from time to time (and as they may be amended pursuant to Section 13 of the Agreement). IN WITNESS WHEREOF, the parties hereto have executed this Agreement. TRANSPORTER: SHIPPER: COLORADO INTERSTATE GAS COMPANY ATMOS ENERGY CORPORATION By: /s/ Thomas L. Price By: /s/ Gary L. Schlessman ------------------ --------------------- Thomas L. Price Name: Gary L. Schlessman Vice President Title: President (Colorado-Kansas Division) [STAMP OF LEGAL DEBT] Accepted and agreed to this 19 day of May, 2003. Accepted and agreed to this 21 day of April, 2003. Contract No. 33182000D EXHIBIT "A" Firm Transportation Service Agreement between COLORADO INTERSTATE GAS COMPANY and ATMOS ENERGY CORPORATION Dated: APRIL 1, 2003 1. Shippers Maximum Delivery Quantity ("MDQ"): 6,121 Dth per Day.
Primary Point(s) of Receipt Quantity Primary Point(s) of Receipt (Dth per Day) Minimum Receipt Maximum Receipt (Note 1) Effective Dates (Note 2) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - --------------------------- ---------------- ------------------- ------------------- -------------------- NORTHERN SYSTEM: Echo Springs MM 4/01/03 - 9/30/06 300 850 Lost Cabin 4/01/03 - 9/30/06 1,200 1,100 Uintah 4/01/03 - 9/30/06 593 940 --------- TOTAL Northern: 2,093 CENTRAL SYSTEM: Lakin MM 4/01/03 - 9/30/06 491 220 SOUTHERN SYSTEM: Big Canyon 4/01/03 - 9/30/06 491 350 955 Mocane 4/01/03 - 9/30/06 1,260 65 --------- TOTAL Southern: 1,751 --------- TOTAL 6,121
Primary Point(s) of Primary Point(s) of Delivery Delivery Quantity Minimum Delivery Maximum Delivery (Note 1) Effective Dates (Dth per Day) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - ----------------------------- ----------------- ------------------- ------------------- -------------------- CANON CITY GROUP: Canon City 4/01/03 - 9/30/06 4,231 100 LP Colorado State Penitentiary 4/01/03 - 9/30/06 298 100 Engineering Station 476+78 4/01/03 - 9/30/06 5 LP Florence City Gate 4/01/03 - 9/30/06 989 60 Fremont Cty. Industrial Park 4/01/03 - 9/30/06 9 LP Penrose City Gate 4/01/03 - 9/30/06 135 60 Penrose PBS-2 4/01/03 - 9/30/06 129 LP Portland City Gate 4/01/03 - 9/30/06 35 100 Pritchett City Gate 4/01/03 - 9/30/06 35 150 --------- TOTAL Canon City Group 5,866
Contract No. 33182000D EXHIBIT "A"
Primary Point(s) of Primary Point(s) of Delivery Delivery Quantity Minimum Delivery Maximum Delivery (Note 1) Effective Dates (Dth per Day) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - -------------------------------------------------------------------------------------------------------------------------- EADS GROUP: Brandon Station 4/01/03 - 9/30/06 28 350 Eads City Gate 4/01/03 - 9/30/06 207 60 Highline Taps: Neoplan (Bent County) 4/01/03 - 9/30/06 3 LP Penrose South(Fremont Cty) 4/01/03 - 9/30/06 11 LP The Piggery (Fremont Cty.) 4/01/03 - 9/30/06 3 LP L. J. Stafford (Baca County) 4/01/03 - 9/30/06 5 LP ----- TOTAL Eads Group 257 ----- McClave Delivery 4/01/03 - 9/30/06 350 500 ----- Springfield 4/01/03 - 9/30/06 700 LP ----- TOTAL 6,121 - --------------------------------------------------------------------------------------------------------------------------
Primary Point(s) of Primary Point(s) of Delivery Quantity Delivery Storage (Dth per Day) Minimum Delivery Maximum Delivery Injection (Note 1) Effective Dates (Notes 3 and 4) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - ----------------------------------------------------------------------------------------------------------------------- Storage Injection 4/01/03-9/30/06 2,814 - -----------------------------------------------------------------------------------------------------------------------
NOTES: (1) Information regarding Point(s) of Receipt and Point(s) of Delivery, including legal descriptions, measuring Parties, and interconnecting Parties, shall be posted on Transporter's Electronic Bulletin Board. Transporter shall update such information from time to time to include additions, deletions, or any other revisions deemed appropriate by Transporter. (2) Each Point of Receipt Quantity may be increased by an amount equal to Transporter's Fuel Reimbursement percentage. Shipper shall be responsible for providing such Fuel Reimbursement at each Point of Receipt on a pro rata basis based on the quantities received on any Day at a Point of Receipt divided by the total quantity Delivered at all Point(s) of Delivery under this Transportation Service Agreement. (3) The sum of the Delivery Quantities at Point(s) of Delivery shall be equal to or less than Shipper's MDQ. (4) Transporter's obligation to make Deliveries to Transporter's storage injection point under this Agreement and to Transporter's storage injection point under all other Firm Transportation Service Agreements between Transporter and Shipper providing for deliveries to Transporter's storage injection point shall be limited by the provisions of Rate Schedule NNT-1 and Shipper's NNT-1 service agreement(s). Contract No. 33182000D EXHIBIT "B" Firm Transportation Service Agreement between COLORADO INTERSTATE GAS COMPANY and ATMOS ENERGY CORPORATION Dated: APRIL 1, 2003
Primary Point(s) Primary Point(s) R(1) Reservation Commodity Fuel of Receipt of Delivery Rate(s) Rate Term of Rate Reimbursement Surcharges - ------------------------------------------------------------------------------------------------------------------------------ As listed on As Listed on (Note 1) (Note 1) 4/01/03-9/30/06 (Note 2) (Note 3) Exhibit "A" Exhibit "A" - ------------------------------------------------------------------------------------------------------------------------------
Secondary Secondary Point(s) of Point(s) of R(1) Reservation Commodity Fuel Receipt Delivery Rate(s) Rate Term of Rate Reimbursement Surcharges - ------------------------------------------------------------------------------------------------------------------------------ All All (Note 1) (Note 1) 4/01/03-9/30/06 (Note 2) (Note 3) - ------------------------------------------------------------------------------------------------------------------------------
NOTES: (1) Unless otherwise agreed by the Parties in writing, the rates for service hereunder shall be Transporter's maximum rates for service under Rate Schedule TF-1 or other superseding Rate Schedules, as such rates may be changed from time to time. (2) Fuel Reimbursement shall be as stated on Transporter's Schedule of Surcharges and Fees in the Tariff, as they may be changed from time to time, unless otherwise agreed between the Parties. (3) Surcharges, If Applicable: All applicable surcharges, unless otherwise specified, shall be the maximum surcharge rate as stated in the Schedule of Surcharges and Fees in the Tariff, as such surcharges may be changed from time to time, GAS QUALITY CONTROL SURCHARGE: The Gas Quality Control Reservation Rate and commodity rate shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in the Tariff. GRI: The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms and Conditions as set forth in the Tariff. ORDER NO. 636 TRANSITION COST MECHANISM: Surcharge(s) shall be assessed pursuant to Article 21 of the General Terms and Conditions as set forth in the Tariff. ACA: The ACA Surcharge shall be assessed pursuant to Article 19 of the General Terms and Conditions as set forth in the Tariff. EX-10.4(D) 7 d10753exv10w4xdy.txt NO-NOTICE STORAGE AND TRANSPORTATION DELIVERY EXHIBIT 10.4(d) Contract No. 31044000A GGC- 10474-CO No-Notice Storage and Transportation Delivery Service Agreement Rate Schedule NNT-1 between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY (A DIVISION OF ATMOS ENERGY CORPORATION) Dated: OCTOBER 1, 2002 Contract No. 31044000A NO-NOTICE STORAGE AND TRANSPORTATION DELIVERY SERVICE AGREEMENT RATE SCHEDULE NNT-1 The Parties identified below, in consideration of their mutual promises, agree as follows: 1. TRANSPORTER: COLORADO INTERSTATE GAS COMPANY 2. SHIPPER: GREELEY GAS COMPANY, (A DIVISION OF ATMOS ENERGY CORPORATION) 3. APPLICABLE TARIFF: Transporter's FERC Gas Tariff, First Revised Volume No. 1, as the same may be amended or superseded from time to time ("the Tariff"). 4. CHANGES IN RATES AND TERMS: Transporter shall have the right to propose to the FERC changes in its rates and terms of service, and this Agreement shall be deemed to include any changes which are made effective pursuant to FERC Order or regulation or provisions of law, without prejudice to Shipper's right to protest the same. 5. TRANSPORTATION SERVICE: Transportation Service at and between Point of Withdrawal and Primary Point(s) of Delivery shall be on a firm basis. Delivery of quantities at Secondary Point(s) shall be in accordance with the Tariff. 6. 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." Minimum and Maximum delivery pressures, as applicable, are listed on Exhibit "A." 7. RATES AND SURCHARGES: As set forth in Exhibit "B." For example, Transporter and Shipper may agree that a specified discount rate will apply: (a) only to certain specified firm service entitlements under this Agreement; (b) only if specified quantity levels are actually achieved under this Agreement (with higher rates, charges, and fees applicable to all quantities above those levels, or to all quantities under the Agreement if the specified levels are not achieved); (c) only to production reserves committed by the Shipper; (d) only during specified time periods; (e) only to specified Point(s) of Receipt, Point(s) of Delivery, mainline area segments, supply areas, Transportation routes, or defined geographical areas under the associated Transportation Agreement; or (f) in a specified relationship to the quantities actually Delivered (i.e., that the rates shall be adjusted in a specified relationship to quantities actually Delivered); provided, however, that any such discounted rates set forth above shall be between the minimum and maximum rates applicable to the service provided under this Agreement. In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporter's maximum rates so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates that had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable. 8. MAXIMUM DELIVERY QUANTITY (" MDQ"): 12,985 Dth per Day MAXIMUM AVAILABLE CAPACITY ("MAC"): 422,142 Dth MAXIMUM DAILY INJECTION QUANTITY ("MDIQ"): 4,151 Dth per Day MAXIMUM DAILY WITHDRAWAL QUANTITY ("MDWQ"): 12,985 Dth per Day All storage entitlements as stated herein ("MAC", "MDIQ", and "MDWQ") are based on an Average Thermal Content of Gas in Storage of 1,000 Btu per cubic foot. The Available Daily Injection Quantity ("ADIQ"), Available Daily Withdrawal Quantity ("ADWQ"), and storage entitlements shall be subject to the General Terms and Conditions of the Tariff and stated on Transporter's Electronic Bulletin Board. 1 Contract No. 31044000A 9. NEGOTIATED RATE AGREEMENT: NO 10. TERM OF AGREEMENT: Beginning: OCTOBER 1, 2002 Extending through: APRIL 30, 2005 11. NOTICES, STATEMENTS, AND BILLS: TO SHIPPER: INVOICES FOR TRANSPORTATION: Greeley Gas Company, (a division of Atmos Energy Corporation) 160 Lincoln Centre Three 5430 LBJ Freeway Dallas, Texas 75240 Attention: John Hack ALL NOTICES: Greeley Gas Company, (a division of Atmos Energy Corporation) 160 Lincoln Centre Three 5430 LBJ Freeway Dallas, Texas 75240 Attention: John Hack TO TRANSPORTER: See Notices, Payments, Nominations, and Points of Contact sheets in the Tariff. 12. SUPERSEDES AND CANCELS PRIOR AGREEMENT: When this Agreement becomes effective, it shall supersede and cancel the following agreement between the Parties: The No-Notice Storage and Transportation Delivery Service Agreement between Transporter and Shipper dated October 1, 2001, referred to as Transporter's Agreement No. 31044000. 13. ADJUSTMENTS TO RATE SCHEDULE NNT-1 AND/OR GENERAL TERMS AND CONDITIONS: N/A. 14. INCORPORATION BY REFERENCE: This Agreement in all respects shall be subject to the provisions of Rate Schedule NNT-1 and to the applicable provisions of the General Terms and Conditions of the Tariff as filed with, and made effective by, the FERC as same may change from time to time (and as they may be amended pursuant to Section 12 of the Agreement). IN WITNESS WHEREOF, the parties hereto have executed this Agreement. TRANSPORTER: SHIPPER: COLORADO INTERSTATE GAS COMPANY GREELEY GAS COMPANY, (a division of Atmos Energy Corporation By: /s/ Thomas L. Price By: /s/ Robert E. Mattingly ------------------------ ------------------------------- Thomas L. Price Name: ROBERT E. MATTINGLY Vice President Title: VICE PRESIDENT [STAMP OF LEGAL DEBT] Accepted and agreed to this 18th day of November, 2002. Accepted and agreed to this 6th day of November, 2002. 2 Contract No. 31044000A EXHIBIT "A" No-Notice Storage and Transportation Delivery Service Agreement between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY, (A DIVISION OF ATMOS ENERGY CORPORATION) dated: OCTOBER 1,2002 1. Shipper's Maximum Delivery Quantity ("MDQ"): 12,985 Dth per Day. 2. Shipper's Maximum Available Capacity ("MAC"): 422,142 Dth. 3. Shipper's Maximum Daily Injection Quantity ("MDIQ"): 4,151 Dth per Day. 4. Shipper's Maximum Daily Withdrawal Quantity ("MDWQ"): 12,985 Dth per Day.
Primary Point(s) of Primary Point(s) of Delivery Delivery Quantity Minimum Delivery Maximum Delivery (Dth per Day) (Note 1) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - ------------------------------------------------------------------------------------------------------------------------------- CANON CITY GROUP Canon City 7,799 (Note 2) Colorado State Penitentiary 552 100 Engineer's Station 476+78 10 LP Florence City Gate 1,823 60 Fremont County Industrial Park 16 LP Penrose City Gate 248 60 Penrose PBS-2 238 LP Portland City Gate 65 100 Pritchett City Gate 65 150 ------ TOTAL CANON CITY GROUP 10,816 - -------------------------------------------------------------------------------------------------------------------------------
A-1 Contract No. 31044000A EXHIBIT "A"
Primary Point(s) of Delivery Quantity Minimum Delivery Maximum Delivery Primary Point(s) of Delivery (Dth per Day) (Note 1) Pressure (p.s.i.g.) Pressure (p.s.i.g.) - ------------------------------------------------------------------------------------------------------------------- McCLAVE GROUP McClave Delivery 650 500 Brandon Station 52 350 Eads City Gate 382 60 Highline Taps: Nepolan (Bent County) 8 LP Penrose (Fremont County) 20 LP Piggery (Fremont County) 7 LP L.J Stafford (Baca County) 7 LP ------ TOTAL McCLAVE GROUP 1,126 ------ SPRINGFIELD 2,993 LP ------ TOTAL 14,935 - -------------------------------------------------------------------------------------------------------------------
NOTES: (1) The sum of the Delivery Quantities at Point(s) of Delivery shall not be greater than Shipper's MDQ. (2) Line Pressure but not less than 100 p.s.i.g. A-2 Contract No. 31044000A EXHIBIT "B" No-Notice Storage and Transportation Delivery Service Agreement between COLORADO INTERSTATE GAS COMPANY and GREELEY GAS COMPANY, (a division of Atmos Energy Corporation) Dated: OCTOBER 1, 2002
Commodity Injection Rate Fuel Reimbursement Surcharges - ------------------------------------------------------------------------------------------------------- Storage Injection................. (Note 1) (Note 2) (Note 3) - ------------------------------------------------------------------------------------------------------
R1 Reservation Commodity Primary Point(s) of Delivery Rate Delivery Rate Term of Rate Surcharges - --------------------------------------------------------------------------------------------------------------------- As listed on Exhibit "A" (Note 1) (Note 1) Through 4/30/05 (Note 3) - -------------------------------------------------------------------------------------------------------------------
NOTES: (1) Unless otherwise agreed by the Parties in writing, the rates for service hereunder shall be Transporter's maximum rates for service under Rate Schedule NNT-1 or other superseding Rate Schedule, as such rates may be changed from time to time. (2) Fuel Reimbursement shall be as stated on Transporter's Schedule of Surcharges and Fees in the Tariff, as they may be changed from time to time, unless otherwise agreed between the Parties. (3) 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 SURCHARGE: The Gas Quality Control Reservation Rate and commodity rate shall be assessed pursuant to Article 20 of the General Terms and Conditions as set forth in the Tariff. GRI: The GRI Surcharge shall be assessed pursuant to Article 18 of the General Terms and Conditions as set forth in the Tariff. ORDER NO. 636 TRANSITION COST MECHANISM: Surcharge(s) shall be assessed pursuant to Article 21 of the General Terms and Conditions as set forth in the Tariff. ACA: The ACA Surcharge shall be assessed pursuant to Article 19 of the General Terms and Conditions as set forth in the Tariff. EX-10.5(C) 8 d10753exv10w5xcy.txt NO-NOTICE SERVICE AGREEMENT EXHIBIT 10.5(c) GULF SOUTH 29865 [GULF SOUTH LOGO] March 05, 2003 Atmos Energy Corporation 1515 Poydras St., Suite 2[ILLEGIBLE]80 New Orleans, LA 70112 Arm: Shawn Audibert Re: No Notice and Interruptible Transportation Service Agreement between GULF SOUTH PIPELINE COMPANY, LP and ATMOS ENERGY CORPORATION Dear Shawn: As a result of the DUNS Number change from 031196988 to 10820324., Gulf Soml has been required to modify the Contract Number of the referenced agreements as follows:
Old Contract # New Contract # Type of Service - -------------- ------------- --------------- 29267 29865 No Notice Service (NNS) 29119 29864 Interruptible Transportation (ITS)
All terms of the referenced agreements remain as previously agreed between the parties. This action has been required purely for administrative purposes. These changes are effective as of March 1, 2003. Please utilize the new contract numbers for all future activity. Thank you for your consideration to this matter. Should you have any questions, please do not hesitate to give me a call a: (713) 544 - 1783. Sincerely, /s/ Larry Tape Larry Tape Account Manager Customer Service EX-10.11 9 d10753exv10w11.txt FIRM TRANSPORATION SERVICE AGREEMETN EXHIBIT 10.11 UCG-10752 FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN OZARK GAS TRANSMISSION, L.L.C. AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION UNDER RATE SCHEDULE FTS THIS AGREEMENT ("Agreement"), entered into on August 23, 2002, is between Ozark Gas Transmission, L.L.C. ("Transporter"), an Oklahoma limited liability company and United Cities Gas Company, a division of Atmos Energy Corporation ("Shipper"); WITNESSETH: WHEREAS, Shipper has requested that Transporter transport Natural Gas for Shipper; and WHEREAS, Transporter has agreed to provide such transportation for Shipper subject to the terms and conditions set forth in this Agreement. NOW, THEREFORE, in consideration of the promises and the mutual covenants herein contained, the parties agree as follows: ARTICLE I DEFINITIONS 1.1 "Maximum Daily Delivery Obligation (MDDO)" means the maximum daily quantity of Natural Gas, expressed in MMBtu's, that Transporter is obligated to deliver from time to time at each Point of Delivery specified in Exhibit B to the executed Agreement. ARTICLE II GAS TRANSPORTATION SERVICE 2.1 Transportation service rendered hereunder shall be firm service as provided in Transporter's Rate Schedule FTS, and as described in Section 2 of Transporter's Rate Schedule FTS. ARTICLE III POINT(S) OF RECEIPT 3.1 The Point(s) of Receipt at which Transporter shall receive Natural Gas for transportation under this Agreement shall be specified in Exhibit A to this Agreement. ARTICLE IV POINT(S) OF DELIVERY 4.1 The Point(s) of Delivery (both primary and secondary) at which Transporter shall redeliver to Shipper or for the account of Shipper an Equivalent Quantity of gas for transportation under this Agreement shall be specified in Exhibit B to this Agreement. Notwithstanding the MDDO at each Point of Delivery, Shipper shall not nominate a total quantity of natural gas at all Points of Delivery that exceeds the MDQ set forth in this Agreement. FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN OZARK GAS TRANSMISSION, L.L.C. AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION UNDER RATE SCHEDULE FTS (continued) ARTICLE V TERM OF AGREEMENT 5.1 Subject to the provisions of the General Terms and Conditions of Transporter's FERC Gas Tariff and of Rate Schedule FTS, this Agreement shall be effective as of November 1, 2002 and shall continue for a primary term through October 31, 2003. 5.2 Any portions of this Agreement necessary to enable the parties to balance receipts and deliveries under this Agreement as required by the Rate Schedule FTS, shall survive the other parts of this Agreement until such time as such balancing has been accomplished. 5.3 The term of this Agreement shall automatically be extended for additional periods of one (1) Year following the conclusion of the primary term or any extension thereof unless Shipper notifies Transporter in writing but not later than one hundred eighty (180) Days prior to the conclusion of the primary term or any extension thereof that it desires to terminate this Agreement as of the conclusion of such primary or extended term. 5.4 Upon receipt of termination notification, and for a period of sixty (60) Days, Transporter will post on its electronic bulletin board ("EBB") notice of such termination, and begin offering firm capacity for bid. Shipper will continue to receive service in accordance with this Rate Schedule FTS until service is actually terminated. If there are bidders for the capacity, Shipper must meet or exceed the value (as defined by the terms and conditions posted during notification) of the competing bids if it desires to retain its capacity under this Agreement. If shipper fails to meet the value of the bid properly submitted by a competing bidder, then subject to the competing bidder's satisfaction of applicable requirements of Transporter's FERC Gas Tariff, Transporter will provide transportation service to such competing bidder under the terms and conditions of the offer. If a competing bidder bids the maximum rate for only a portion of the capacity under Shipper's Agreement, Shipper need only meet the competing bid for the amount of capacity to which the bid applies. In determining which offer has the highest value, Transporter will post on its EBB, at the time of notice of termination of this Agreement, terms and conditions upon which the offers will be evaluated. Transporter may request a third party bidder to post a bond or provide other security before accepting the bid with the highest value. Transporter will post on its EBB the highest value bid. FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN OZARK GAS TRANSMISSION, L.L.C. AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION UNDER RATE SCHEDULE FTS (continued) ARTICLE VI PERIOD AFTER SHIPPER'S FAILURE TO PAY RATE SCHEDULE AND CHARGES 6.1 Except as provided to the contrary in any written or electronic agreement(s) between Transporter and Shipper in effect during the term of this Agreement, Shipper shall pay Transporter the maximum allowable rate for the service hereunder in accordance with Transporter's Rate Schedule FTS, the applicable provisions of that Rate Schedule, and the General Terms and Conditions of Transporter's FERC Gas Tariff, all as may be revised from time to time. Such Rate Schedule FTS and General Terms and Conditions are incorporated by reference and made a part hereof. Transporter and Shipper may agree that a specified discount rate will apply only to specified volumes under the Agreement; that a specified discounted rate will apply only if specified volumes are achieved (with the maximum rates applicable to volumes above the specified volumes or to all volumes if the specified volumes are never achieved); that a specified discounted rate will apply only during specified periods of the Year or over a specifically defined period of time; and/or that a specified discounted rate will apply only to specified points, zones, markets or other defined geographical areas. 6.2 Transporter may seek authorization from the FERC and/or other appropriate body to change any rate(s) and/or term(s) set forth herein or in the Rate Schedule FTS. Nothing herein shall be construed to deny Shipper any rights it may have under the Natural Gas Act or the Natural Gas Policy Act, including the right to participate fully in rate proceedings by intervention or otherwise, to contest increased rates in whole or in part. ARTICLE VII REDUCTION IN CAPACITY 7.1 If Transporter's capacity is reduced for any reason and a reduction of the quantity of Natural Gas being transported hereunder is required, Shipper's MDQ shall be reduced pro rata with MDQs of the other firm Shippers during the period of such capacity reduction. ARTICLE VIII MISCELLANEOUS 8.1 Amendment. This Agreement shall only be amended, varied or modified by an instrument in writing executed by Transporter and Shipper. Such amendment will be effective upon compliance with Article VIII herein. 8.2 Applicable Law. This Agreement and the rights and duties of Transporter and Shipper hereunder shall be governed by and interpreted in accordance with the laws of the State of Oklahoma, without recourse to the law governing conflict of laws. FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN OZARK GAS TRANSMISSION, L.L.C. AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION UNDER RATE SCHEDULE FTS (continued) 8.3 Waiver. No waiver by either Transporter or Shipper of any default by the other in the performance of any provision, condition or requirement herein shall be deemed a waiver of, or in any manner release from, performance of any other provision, condition or requirement herein, nor deemed to be a waiver of, or in any manner release from, future performance of the same provision, condition or requirement; nor shall any delay or omission by Transporter or Shipper to exercise any right hereunder impair the exercise of any such right or any like right accruing to it thereafter. 8.4 Headings. The headings of each of the various sections in this Agreement are included for convenience of reference only and shall have no effect on, nor be deemed part of the text of, this Agreement. 8.5 Further Assurances. Transporter and Shipper shall execute and deliver all instruments and documents and shall do all acts necessary from time to time to effectuate this Agreement. 8.6 Entire Agreement. This Agreement constitutes the entire agreement between Transporter and Shipper concerning the subject matter hereof and supersedes all prior understandings and written and oral agreements relative to said matter. 8.7 Cancellation of Prior Agreement(s). This Agreement, upon its effective date, supersedes and cancels any and all other agreements between Transporter and Shipper relating to the transportation of gas by Transporter for Shipper. ARTICLE IX NOTICES 9.1 All notices, requests, statements or other communications provided for under this Agreement shall be in writing and shall be given by personal delivery or by United States mail, postage prepaid, and addressed as follows: If to Shipper: Atmos Energy Corporation P.O. Box 650205 Dallas, TX 75265-0205 Attn: Contract Administration 972-855-3280 972-855-3773 (Fax) E-mail: pat.capps@atmosenergy.com FIRM TRANSPORTATION SERVICE AGREEMENT BETWEEN OZARK GAS TRANSMISSION, L.L.C. AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION UNDER RATE SCHEDULE FTS (continued) If to Transporter: Ozark Gas Transmission, L.L.C. 515 Central Park Drive Suite 600 Oklahoma City, OK 73105 Attn: Sr. Scheduler 405-557-5220 405-557-5709 (Fax) E-mail: srscheduler@oge.com All written notices, requests, statements or other communications shall be sufficiently given if mailed postage prepaid by registered, certified, or regular mail and shall be deemed to have been duly delivered on the third Business Day following the date on which same was deposited in the United States mail, addressed in accordance with this Article IX. Either Shipper or Transporter may designate a different address to which notices, requests, statements, payments or other communications shall be sent upon proper notice as set forth in this Article IX IN WITNESS WHEREOF, Transporter and Shipper have caused this Agreement to be duly executed by their duly authorized officers in two (2) original counterparts as of the______________day of _________________, 2002. "TRANSPORTER" OZARK GAS TRANSMISSION, L.L.C. By -s- E. KEITH MITCHELL ---------------------------------------- "SHIPPER" UNITED CITIES, A DIVISION OF ATMOS ENERGY CORPORATION By -s- ROBERT E. MATTINGLY ---------------------------------------- EXHIBIT A TO FIRM TRANSPORTATION SERVICE AGREEMENT UNDER RATE SCHEDULE FTS BETWEEN OZARK GAS TRANSMISSION, L.L.C. ("Transporter") AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION ("Shipper")
POINT OF RECEIPT METER NUMBER Primary Receipts Enogex Boiling Springs OZ1031890 Transok Wilburton OZ1029890 Vastar Wilburton OZ1029990
EXHIBIT B TO FIRM TRANSPORTATION SERVICE AGREEMENT UNDER RATE SCHEDULE FTS BETWEEN OZARK GAS TRANSMISSION, L.L.C. ("Transporter") AND UNITED CITIES GAS COMPANY, A DIVISION OF ATMOS ENERGY CORPORATION ("Shipper")
POINT OF DELIVERY MDDO DELIVERY PRESSURE United Cities/Atmos 13,370 Prevailing Ozark Pipeline Pressure
EX-10.13(A) 10 d10753exv10w13xay.txt NO NOTICE SERVICE AGREEMENT 16086 EXHIBIT 10.13(a) NO NOTICE SERVICE AGREEMENT PURSUANT TO SECTION 284, SUBPART "G" or "B" between KOCH GATEWAY PIPELINE COMPANY, as KGPC, and MISSISSIPPI VALLEY GAS COMPANY, as CUSTOMER Rate Schedule NNS Contract No.: 16086-10 Contract Date: November 01, 1993 Option SCO: No CUSTOMER CORRESPONDENCE: CUSTOMER BILLING: MISSISSIPPI VALLEY GAS COMPANY MISSISSIPPI VALLEY GAS COMPANY Primary Term: 101 month(s) 711 West Capitol Street PO BOX 3348 JACKSON, MS 39203 711 WEST CAPITOL STREET JACKSON, MS 39207 Beginning 9:00 A.M. on: February 03, 2000 Attn. Tony Richard Attn. MS. SHERI W. ROWE Telephone No.: (601) 961-6846 Thru 9:00 A.M. on: April 01, 2002 Telephone No.: (601) 961-6843 Seasonal Daily Contract Demand: Fax No.: (601) 973-7055 Fax No.: (601) 961-6995 Winter Season: 123,750 Shoulder Months: 61,875 Summer Season: 43,312 Customer Service Department: Telephone No.: (800) 890-0205 Fax No.: (713) 544-4624 Customer's Dispatcher: Tony Richard Telephone No.: (601) 961-6800 Fax No.: (601) 973-7055 PRIMARY RECEIPT POINTS Station Location Numbers Description Primary Point MDQ Winter Season --- SEE EXHIBIT A --- Shoulder Month Season Winter Season PRIMARY DELIVERY POINTS Station Location Numbers Description Primary Point MDQ Winter Season --- SEE EXHIBIT B --- Shoulder Month Season Winter Season MAXIMUM STORAGE MAXIMUM DAILY INJECTION MAXIMUM DAILY WITHDRAWAL QUANTITY (MSQ) QUANTITY (MDIQ) QUANTITY (MDWQ) 2/ Dekatherm Dekatherm Dekatherm 1,237,500 30,938 Winter Season : 51,875 Shoulder Month Season: 30,938 Summer Season: 21,656
(Additional Primary Receipt Points are subject to the provisions of Section 2(b) of the NNS Rate Schedule may be continued on Exhibit A which is hereby incorporated by references.) (Additional Primary Delivery Points are subject to the provisions of Section 2(c) of the NNS Rate Schedule may be continued on Exhibit B which is hereby incorporated by references.) (ALL RECEIPT POINTS ARE AVAILABLE AS SUPPLEMENTAL RECEIPT POINTS) 1/ The MDIQ shall equal the Maximum Storage Quantity divided by (40) forty. 2/ The MDWQ cannot exceed the Seasonal Daily Contract Demand divided by (2) two or quantity in storage. Service hereunder is subject to Subpart G, Section 284,223, Title 18, of the Code of Federal Regulations. THE STANDARD TERMS AND CONDITIONS SET FORTH ON THE REVERSE SIDE ARE INCORPORATED HEREIN BY REFERENCE. IF YOU ARE IN AGREEMENT WITH THE FOREGOING, PLEASE INDICATE IN THE SPACE PROVIDED BELOW. KGPC Signature: -s- [ILLEGIBLE] Name [ILLEGIBLE] Title: Vice President Date: 2/9/00 CUSTOMER Signature: -s- Sandy Novick Name: Sandy Novick Title: Executive V.P. Date: 2/2/00 NO NOTICE TERMS BELOW: STANDARD TERMS & CONDITIONS 1. CONDITIONS OF SERVICE: Services provided hereunder are subject to and governed by the applicable rate schedule and the General Terms and Conditions of Gulf South's current tariff, as may be revised from time to time, or any effective superseding tariff (Tariff) on file with the Federal Energy Regulatory Commission (FERC). The Tariff is incorporated by reference. In the event of any conflict between this Agreement and the Tariff, the Tariff shall govern as to the conflict. Gulf South shall have the right to interrupt service under this Agreement to the extent permitted by the Tariff. 2. NO NOTICE QUANTITY: Customer may deliver or cause to be delivered to Gulf South at authorized firm Primary and Supplemental Receipt Points and Gulf South agrees to accept at such point(s) quantities of natural gas for transportation to No Notice Delivery Points up to the Seasonal Daily Contract Demand. The Summer Season and Shoulder Month Daily Contract Demand shall not be less than 35% or 50% of the Winter Season Daily Contract Demand. Any variance between monthly allocated receipts and deliveries shall be recorded as a storage withdrawal or injection during such month except to the extent the Customer executes a PAA. Customer may not withdraw from storage on a daily basis more than 50% of its seasonal MDQ. Storage injections during the period April 1 through September 30 (Injection Period) shall be made on a uniform monthly basis to the extent practicable up to the Customer's MSQ. Storage injections under this service made after October 1 of each year shall only be subject to the same injection schedule as FSS during periods when Gulf South has issued an operational flow order due to operational constraints on its system which prevent an NNS customer from making storage injections up to its MDIQ as defined in section 2(g) of this rate schedule. Should CUSTOMER desire a change in the Seasonal Daily Contract Demand. CUSTOMER shall notify Gulf South in writing of the amount of the increase or decrease and of the date CUSTOMER desires the change to become effective. If Gulf South advises it is not agreeable to the changed quantities of gas requested in CUSTOMER's notice, the Contract Demand shall remain unchanged. Gulf South shall review CUSTOMER's request within thirty (30) days subject to the Tariff. Nothing herein shall require Gulf South to install equipment or facilities for new or additional service. 3. QUALITY AND PRESSURE: The gas received and delivered hereunder shall be merchantable and of a quality sufficient to meet the standards in the Tariff. Gas delivered to Gulf South shall be at a delivery pressure adequate to enter Gulf South's facilities and such pressure shall not exceed the Maximum Allowable Operating Pressure. Gulf South shall not be obligated to maintain pressure in excess of the contract delivery pressure shown in Exhibit B or the Maximum Allowable Operating Pressure of Gulf South's system, as set by the appropriate governmental agency, whichever is less. 4. TERM: This Agreement shall become effective as of 9:00 A.M. on the beginning Primary Term Date and continue as stated on the face hereof and month to month thereafter. 5. NNS CHARGES: CUSTOMER shall be obligated to pay Gulf South monthly for the service provided under this Agreement. 6. PAYMENTS: Payment shall be made in compliance with the Tariff. Payments by check shall be made to the remittance address indicated on Gulf South's invoice. Payment by wire transfer shall be to a bank account designated by Gulf South. 7. WAIVER: No waiver by either party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be construed as a waiver of any future default(s), whether of a like or different character. 8. APPLICABLE LAW: THE VALIDITY, CONSTRUCTION, INTERPRETATION AND EFFECT OF THIS AGREEMENT SHALL BE GOVERNED BY THE LAWS OF THE STATE OF TEXAS, THE PARTIES AGREE THAT TEXAS' CHOICE OF LAW RULES MAY NOT BE USED TO DIRECT OR DETERMINE THAT SOME OTHER STATES' LAW SHALL GOVERN A DISPUTE ARISING UNDER THIS AGREEMENT. 9. SUCCESSORS AND ASSIGNS: This Agreement shall be binding upon and inure to the benefit of the respective heirs, representatives, successors and assigns of the parties hereto. Except as provided in the General Terms and Conditions of the Tariff, neither party may assign, pledge or otherwise transfer or convey its rights, obligations or interests hereunder for any purpose without the prior written consent of the other party, which consent shall not unreasonably be withheld. Any assignment, pledge, transfer or conveyance in breach of this provision is voidable by the non-breaching party. 10. FILINGS: Each party shall make and diligently prosecute, all necessary filings with governmental bodies as may be required for the initiation and continuation of the transportation service subject to this Agreement, as well as inform and, upon request, provide copies to the other party of all filing activities. Gulf South shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (i) the filed rates and charges applicable under this Rate Schedule, including both the level and design of such rates and charges; and/or (ii) this Rate Schedule and the General Terms and Conditions. Customer shall have the right to protest or contest the aforementioned filings. 11. NOTICES: Routine communications and payments shall be considered delivered when received by ordinary mail. Communications concerning scheduling, curtailments, and changes in nominations shall be made via EDI or the Customer Electronic System or by fax in the event of failure of Gulf South's or the Customer's electronic communication system. CUSTOMER's Dispatcher on the face hereof shall be the recipient on a twenty-four (24) hour basis of all notices regarding scheduling, curtailments, and changes in nominations. Either party shall immediately notify the other of any changes of the designated individuals or addresses herein. All Administration Notices and Accounting Matters: Gulf South Pipeline Company 20 E. Greenway Plaza, Suite 900 Houston, Texas 77046 Attention: Customer Service EX-10.13(B) 11 d10753exv10w13xby.txt FIRM TRANSPORATION SERVICE AGREEMENT EXHIBIT 10.13(b) Service Agreement No. FSNG46 FIRM TRANSPORTATION SERVICE AGREEMENT UNDER RATE SCHEDULE FT AND/OR RATE SCHEDULE FT-NN THIS AGREEMENT, made and entered into as of this 1st day of November, 2000, by and between Southern Natural Gas Company, a Delaware corporation, hereinafter referred to as "Company", and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Shipper". WITNESSETH WHEREAS, Company is an interstate pipeline, as defined in Section 2(15) of the Natural Gas Policy Act of 1978 (NGPA); and WHEREAS, Shipper has requested firm transportation pursuant to Rate Schedule FT and/or FT-NN of various supplies of gas for redelivery for Shipper's account and has submitted to Company a request for such transportation service in compliance with Section 2 of the General Terms and Conditions applicable to such Rate Schedules and/or WHEREAS, Shipper may acquire, from time to time, released firm transportation capacity under Section 22 of the General Terms and Conditions to Company's FERC Gas Tariff; and WHEREAS, Company has agreed to provide Shipper with transportation service of such gas supplies or through such acquired capacity release in accordance with the terms and conditions of this Agreement. NOW, THEREFORE, the parties hereto agree as follows: ARTICLE I TRANSPORTATION QUANTITY 1.1 Subject to the terms and provisions of this Agreement, Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, Shipper agrees to deliver or cause to be delivered to Company at the Receipt Point(s) described in Exhibit A and Exhibit A-l to this Agreement, and Company agrees to accept at such point(s) for transportation under this Agreement, an aggregate quantity of natural gas per day up to the total Transportation Demand set forth on Exhibit B hereto. Company's obligation to accept gas on a firm basis at any Receipt Point is limited to the Receipt Points set out on Exhibit A and to the Maximum Daily Receipt Quantity (MDRQ) Service Agreement No. FSNG46 stated for each such Receipt Point. The sum of the MDRQ's for the Receipt Points on Exhibit A shall not exceed the Transportation Demand. 1.2 Subject to the terms and provisions of this Agreement, Rate FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, Company shall deliver a thermally equivalent quantity of gas, less the applicable fuel charge as set forth in the applicable FT or FT-NN Rate Schedule, to Shipper at the Delivery Point(s) described in Exhibit B and Exhibit B-l hereto. Company's obligation to redeliver gas at any Delivery Point on a firm basis is limited to the Delivery Points specified on Exhibit B and to the Maximum Daily Delivery Quantity (MDDQ) stated for each such Delivery Point. The sum of the MDDQs for the Delivery Points on Exhibit B shall equal the Transportation Demand. 1.3 In the event Shipper is the successful bidder on released firm transportation capacity under Section 22 of Company's General Terms and Conditions, Company will promptly finalize by means of SoNet Premier the appropriate Addendum to this Agreement in the format attached hereto. Upon the finalization of an Addendum, subject to the terms, conditions and limitations hereof and of Company's Rate Schedule FT, Company agrees to provide the released firm transportation service to Shipper under Rate Schedule FT, the General Terms and Conditions thereto, and this Agreement. ARTICLE II CONDITIONS OF SERVICE 2.1 It is recognized that the transportation service hereunder is provided on a firm basis pursuant to, in accordance with and subject to the provisions of Company's Rate Schedule FT and/or FT-NN, and the General Terms and Conditions thereto, which are contained in Company's FERC Gas Tariff, as in effect from time to time, and which are hereby incorporated by reference. In the event of any conflict between this Agreement and the terms of the applicable Rate Schedule, the terms of the Rate Schedule shall govern as to the point of conflict. Any limitation of transportation service hereunder shall be in accordance with the priorities set out in Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto. 2.2 This Agreement shall be subject to all provisions of the General Terms and Conditions applicable to Company's Rate Schedule FT and/or FT-NN as such conditions may be revised from time to time. Unless Shipper requests otherwise, Company shall provide to Shipper the filings Company makes at the Federal Energy Regulatory Commission ("Commission") of such provisions of the General Terms and Conditions or other matters relating to Rate Schedule FT or FT-NN. 2.3 Company shall have the right to discontinue service under this Agreement in accordance with Section 15.3 of the General Terms and Conditions hereto. 2 Service Agreement No. FSNG46 2.4 The parties hereto agree that neither party shall be liable to the other party for any special, indirect, or consequential damages (including, without limitation, loss of profits or business interruptions) arising out of or in any manner related to this Agreement. 2.5 This Agreement is subject to the provisions of Part 284 of the Commission's Regulations under the NGPA and the Natural Gas Act. Upon termination of this Agreement, Company and Shipper shall be relieved of further obligation to the other party except to complete the transportation of gas underway on the day of termination, to comply with the provisions of Section 14 of the General Terms and Conditions with respect to any imbalances accrued prior to termination of this Agreement, to render reports, and to make payment for all obligations accruing prior to the date of termination. ARTICLE III NOTICES 3.1 Except as provided in Section 8.6 herein, notices hereunder shall be given pursuant to the provisions of Section 18 of the General Terms and Conditions to the respective party at the applicable address, telephone number or facsimile machine number stated in Exhibit D or such other addresses, telephone numbers or facsimile machine numbers as the parties shall respectively hereafter designate in writing from time to time: ARTICLE IV TERM 4.1 Subject to the provisions hereof, this Agreement shall become effective as of the date first hereinabove written and shall be in full force and effect for the primary term(s) set forth on Exhibit B hereto, if applicable, and shall continue and remain in force and effect for successive evergreen terms specified on Exhibit B hereto unless canceled by either party giving the required amount of written notice specified on Exhibit B to the other party prior to the end of the primary term(s) of any extension thereof. 4.2 In the event SHIPPER has not contracted for firm Transportation Demand under this Agreement directly with COMPANY, as set forth on Exhibit B hereto, then the term of this Agreement shall be effective as of the date first hereinabove written and shall remain in full force and effect for a primary term through the end of the month and month to month thereafter unless canceled by either party giving at least five (5) days written notice to the other party prior to the end of the primary term or any extension thereof. It is provided, however that this Agreement shall not terminate prior to the expiration of the effective date of any Addendum to this Agreement. 3 Service Agreement No. FSNG46 ARTICLE V CONDITIONS PRECEDENT 5.1 This agreement is conditioned upon receipt of final regulatory approvals by both the Federal Energy Regulatory Commission and Mississippi Public Service Commission prior to transfer and completion of the Starkville Lateral in accordance with the terms and conditions of the purchase and sale agreement dated as of July 14, 2000, ("Starkville Lateral Agreement"). In the event that either (1) all final regulatory approvals for the abandonment by Company and the purchase by Shipper of the Starkville Lateral are not received upon terms satisfactory to both parties by October 31, 2000, or (2) the Starkville Lateral transaction is not completed within 60 days of the last of those approvals, then the Shipper may terminate this agreement in whole or in part. Shipper's right to terminate this agreement shall be effective upon not less than sixty (60) days written notice to Company, and such notice must be given no later than January 31,2001. ARTICLE VI REMUNERATION 6.1 Shipper shall pay Company monthly for the transportation services rendered hereunder the charges specified in Rate Schedule FT, Rate Schedule FT-NN, as discounted in accordance with Exhibit E, and on each effective Addendum, as applicable, including any penalty assessed under the applicable FT or FT-NN Rate Schedule FT and the General Terms and Conditions. For new service requested from Company under Rate Schedule FT or FT-NN from and after the date of this Service Agreement, Company shall notify Shipper as soon as practicable of the date services will commence hereunder, and if said date is not the first day of the month, the Reservation Charge for the first month of service hereunder shall be adjusted to reflect only the actual number of days during said month that transportation service is available. Company may agree from time to time to discount the rates charged Shipper for services provided hereunder in accordance with the provisions of Rate Schedule FT and/or FT-NN, as applicable. Said discounted charges shall be set forth on Exhibit E hereto. 6.2 The rates and charges provided for under Rate Schedule FT shall be subject to increase or decrease pursuant to any order issued by the Commission in any proceeding initiated by Company or applicable to the services performed hereunder. Shipper agrees that Company shall, without any further agreement by Shipper, have the right to change from time to time, all or any part of Rate Schedule FT or FT-NN, as applicable, or the General Terms and Conditions thereto, including without limitation the right to change the rates and charges in effect thereunder, pursuant to Section 4(d) of the Natural Gas Act as may be deemed necessary by Company, in its reasonable judgment, to assure just and reasonable service and rates under the Natural Gas Act. It is recognized, however, that once an Addendum has been issued. Company cannot increase the Reservation Charge to be paid by Shipper under that Addendum. Nothing contained herein shall prejudice the rights of Shipper to contest at any time the changes made pursuant to this Section 6.2, from time to time, in any subsequent rate proceedings by Company under Section 4 of the Natural Gas Act or to file a compliant under Section 5 of the Natural Gas 4 Service Agreement No. FSNG46 Act with respect to such transportation rates or charges. This paragraph 6.2 shall not apply to the rates and charges set forth on Exhibit E hereto. ARTICLE VII SPECIAL PROVISIONS 7.1 If Shipper is a seller of gas under more than one Service Agreement and requests that Company allow it to aggregate nominations for certain Receipt Points for such Agreements, Company will allow such an arrangement under the terms and conditions set forth in this Article VII. To be eligible to aggregate gas, Shipper must comply with the provisions of Section 2.2 of the General Terms and Conditions and the terms and conditions of the Supply Pool Balancing Agreement executed by Shipper and Company pursuant thereto 7.2 If Shipper is a purchaser of gas from a seller that is selling from an aggregate of Receipt Points, and Shipper wishes to nominate to receive gas from such seller's aggregate supplies of gas, Company will allow such a nomination, provided that the seller (i) has entered into a Supply Pool Balancing Agreement with Company and (ii) submits a corresponding nomination to deliver gas to Shipper from its aggregate supply pool. ARTICLE VIII MISCELLANEOUS 8.1 This Agreement constitutes the entire Agreement between the parties and no waiver by Company or Shipper of any default of either party under this Agreement shall operate as a waiver of any subsequent default whether of a like or different character. 8.2 The laws of the State of Alabama shall govern the validity, construction, interpretation, and effect of this Agreement. 8.3 No modification of or supplement to the terms and provisions hereof shall be or become effective except by execution of a supplementary written agreement between the parties except that (i) Addenda shall be generated by Shipper's successful bids for released capacity, and (ii) in accordance with the provisions of Rate Schedule FT and/or FT-NN, as applicable, and the General Terms and Conditions thereto, Receipt Points may be added to or deleted from Exhibit A and the Maximum Daily Receipt Quantity for any Receipt Point on Exhibit A may be changed upon execution by Company and Shipper of a Revised Exhibit A to reflect said change(s), and (iii) Delivery Points may be added to or deleted from Exhibit B and the Maximum Daily Delivery Quantity for any Delivery Point may be changed upon execution by Company and Shipper of a Revised Exhibit B to reflect said change(s). It is provided, however, that any such change to Exhibit A or Exhibit B must include corresponding changes to the existing Maximum Daily Receipt Quantities or Maximum Daily Delivery Quantities, respectively, such that the sum of the changed Maximum Daily Receipt Quantities shall not exceed the Transportation Demand and the sum of the Maximum Daily Delivery Quantities equals the Transportation Demand. 5 Service Agreement No. FSNG46 8.4 This Agreement shall bind and benefit the successors and assigns of the respective parties hereto. Subject to the provisions of Section 22 of the General Terms and Conditions applicable hereto, neither party may assign this Agreement without the prior written consent of the other party, which consent shall not be unreasonably withheld; provided, however, that either party may assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture or similar instrument. 8.5 Exhibits A, A-l, B, B-l and/or E, if applicable, and any effective Addendum attached to this Agreement constitute a part of this Agreement and are incorporated herein. 8.6 This Agreement is subject to all present and future valid laws and orders, rules, and regulations of any regulatory body of the federal or state government having or asserting jurisdiction herein. After the execution of this Agreement for firm transportation capacity from Company, each party shall make and diligently prosecute all necessary filings with federal or other governmental bodies, or both, as may be required for the initiation and continuation of the transportation service which is the subject of this Agreement and to construct and operate any facilities necessary therefor. Each party shall have the right to seek such governmental authorizations as it deems necessary, including the right to prosecute its requests or applications for such authorization in the manner it deems appropriate. Upon either party's request, the other party shall timely provide or cause to be provided to the requesting party such information and material not within the requesting party's control and/or possession that may be required for such filings. Each party shall promptly inform the other party of any changes in the representations made by such party herein and/or in the information provided pursuant to this paragraph. Each party shall promptly provide the party with a copy of all filings, notices, approvals, and authorizations in the course of the prosecution of its filings. In the event all such necessary regulatory approvals have not been issued or have not been issued on terms and conditions acceptable to Company or Shipper within twelve (12) months from the date of the initial application therefor, then Company or Shipper may terminate this Agreement without further liability or obligation to the other party by giving written notice thereof at any time subsequent to the end of such twelve-month period, but prior to the receipt of all such acceptable approvals. Such notice will be effective as of the date it is delivered to the U.S. Mail, for delivery by certified mail, return receipt requested. 8.7 If Shipper experiences the loss of any load after November 1, 1993, by direct connection of such load to the Company's system, Shipper may reduce its Transportation Demand under this Service Agreement or any other Service Agreement for firm transportation service between Shipper and Company by giving Company 30 days prior written notice of such reduction within six (6) months of the date Company initiates direct services to the industrial customer; provided, however, that any such reduction shall be applied first to the Transportation Demand under the Service Agreement with the shortest remaining contract term. In order to qualify for a reducing in its Transportation Demand, Shipper must certify and provide supporting data that: 6 Service Agreement No. FSNG46 (i) The load was actually being served by Shipper with gas transported by Company prior to November 1, 1993. (ii) If the load lost by Shipper was served under a firm contract, the daily contract quantity shall be provided. (iii) If the load lost by Shipper was served under an interruptible contract, the average daily volumes during the latest twelve months of service shall be provided. Shipper may reduce its aggregate Transportation Demand under all its Service Agreements by an amount up to the daily contract quantity in the case of the loss of a firm customer and/or up to the average daily deliveries during the latest twelve month period in the case of the loss of an interruptible customer. Such reduction shall become effective thirty days after the date of Shipper's notice that it desires to reduce its Transportation Demand. 8.8 This Agreement supersedes and cancels the following firm transportation Service Agreements between the parties hereto: FT Service Agreement #907500 dated March 1, 1995 and FT-NN Service Agreement #907501 dated March 1, 1995. IN WITNESS WHEREOF, this Agreement has been executed by the parties as of the date first written above by their respective duly authorized officers. Attest: SOUTHERN NATURAL GAS COMPANY [ILLEGIBLE] By [ILLEGIBLE] - ---------------------------------- ------------------------------------ Assist. Secretary Its Executive Vice President MISSISSIPPI VALLEY GAS COMPANY [ILLEGIBLE] By -s- SANFORD NOVICK ------------------------------------ Its Executive VP & COO 7 Page 1 of 1 SoNet Premier SOUTHERN NATURAL GAS COMPANY FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 EXHIBIT A
RECEIPT POINTS --------------------------------------- MDRQ SERVICE TYPE SERVICE TYPE CODE POINT CODE POINT NAME (MCF) - ------------ ----------------- ---------- ---------- ----- FT/FTNN 1 605500 COLUMBIA GULF - SHADYSIDE TO SNG 13,750
By: Sanford Novick By: [ILLEGIBLE] ---------------------------- --------------------------------- MISSISSIPPI VALLEY GAS COMPANY SOUTHERN NATURAL GAS COMPANY EFFECTIVE DATE: 11/1/00 Service Agreement No. FSNG46 EXHIBIT A-1 RECEIPT POINTS All active Receipt Points on Company's contiguous pipeline system, a current list of which shall be maintained by Company on its SoNet Premier bulletin board. SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 1 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- --------------- --------------- 604000 ANR - SHADYSIDE TO SNG 0 N 305,000 664100 ARCO - MOPS EXCH - MATAGORDA ISLAND 686 0 Y 52,000 024130 BAKER RECEIVING STATION 0 N 2,666 015200 BASTIAN BAY #1 0 N 11,500 032400 BAYOU CROOK CHENE 0 N 10,000 017000 BAYOU FELICE #1 - BAY COQUILLE 0 N 6,500 018800 BAYOU FELICE #3 - VINTAGE - SOUTH PASS 2 0 N 19,848 024700 BAYOU LONG #3 - VINTAGE 0 N 9,600 030900 BAYOU POSTILLION #2 - ANSON #2 0 N 52,000 030850 BAYOU POSTILLION #5 - LLOG 0 N 8,800 030000 BAYOU SALE #1 - TEXACO - HORSESHOE BAYOU 0 N 65,000 035900 BAYOU SALE #3 - NRM 0 N 6,000 036300 BAYOU SALE #4 - P & P 0 N 6,000 503971 BEAR CREEK - RECEIPTS FROM TENNESSEE 0 Y 100,000 053500 BEAR CREEK FIELD R/S 0 N 40,000 050900 BENSON #1 0 N 2,000 604800 BENSON #2 - SABINE-TEXICAN 0 N 4,500 024120 BENSON #4 - CAMTERRA 0 N 4,776 045000 BIG ESCAMBIA 2 Y 500 602200 BIG POINT 0 N 10,500 046830 BLUE CREEK #2 - RIVER GAS 2 N 40,704 046835 BLUE CREEK #2 - SIA TO SNG EXCHANGE 2 N 13,464 046840 BLUE CREEK #3 - RIVER GAS 2 N 40,608 046845 BLUE CREEK #3 - SIA TO SNG EXCHANGE 2 N 21,000 690700 BOURBON LINE (FGT) FROM MISS CANYON 268 0 N 37,500 690600 BOURBON LINE (FGT) FROM MISS CANYON 311 0 N 37,500 690500 BOURBON LINE (FGT) FROM WEST DELTA 152 0 N 37,500 503300 BRAZOS 367-L 0 Y 1,000 508400 BRAZOS A-47 - TEXAS GULF 0 Y 11,400 512100 BRETON SOUND 11 0 N 10,500 016200 BRETON SOUND 18 (19,30,35,& MP 21) 0 N 6,500 020600 BRETON SOUND 21 0 N 51,500 020300 BRETON SOUND 32 0 N 20,000 020800 BRETON SOUND 32 0 N 10,500 045800 BROOKWOOD 2 N 37,248 035800 BULL BAYOU 0 N 1,500 022800 CARTHAGE - ETGS 0 N 36,000 021400 CHANDELEUR SOUND 71 - MLG 0 N 11,000 013400 CHANDELEUR SOUND 73 0 N 7,000 685600 COGNAC LINE (TGPL) FROM MISS CANYON 109 0 N 27,000 685400 COGNAC LINE (TGPL) FROM MISS CANYON 194 0 N 27,000 685500 COGNAC LINE (TGPL) FROM MISS CANYON 20 0 N 27,000 685700 COGNAC LINE (TGPL) FROM SOUTH PASS 27 0 N 27,000 605500 COLUMBIA GULF - SHADYSIDE TO SNG 0 N 186,888 015700 COQUILLE BAY #1 - UPRC 0 N 22,000 027000 COQUILLE BAY #3 - LLOG 0 N 6,000 513000 CORINNE FIELD - ROUNDTREE 1 N 2,712 043350 CORINNE FIELD - TOTAL VOLUME 1 N 33,456
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 2 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- -------------- --------------- 014800 COX BAY 0 N 22,500 048300 CRANFIELD - BLANCHARD EDWARDS #3 - COHO 1 N 8,951 041200 CRANFIELD NORTH - KAISER FRANCIS 1 N 6,192 039500 CREOLE RECEIVING STATION 0 N 89,872 046800 DEERLICK CREEK - TRW 2 N 8,000 025500 DESOTO GAS PLANT R/S #1 - HS RESOURCES 0 N 6,200 605900 DESTIN - ENTERPRISE TO SNG 1 N 769,000 048500 DEXTER RECEIVING STATION 1 N 35,000 038100 EAST ATCHAFALAYA FIELD - UPRC 0 N 14,600 503404 EAST CAMERON 23 0 Y 5,000 502200 EAST CAMERON 46 0 Y 20,000 790310 EAST TENN - CLEVELAND TO SNG #1 DISPLACE 3 N 67,626 790410 EAST TENN - CLEVELAND TO SNG #2 DISPLACE 3 N 20,860 508300 EUGENE ISLAND 108 0 Y 15,000 037203 EUGENE ISLAND 341 0 Y 3,650 029000 FGT - FRANKLINTON - TO SNG (DISPLACE) 0 N 61,224 605610 FGT - FRANKLINTON WEST TO SNG (DISPLACE) 0 N 162,480 038500 GRAND CANE - TEXICAN 0 N 2,000 043600 GRANGE - STEELE #1 WELL 1 N 6,500 024200 GRAYS CREEK 0 N 9,312 601950 GULF STATES - GSP TO SNG 0 N 99,576 025200 GURNEE #1 - MCKENZIE METHANE 2 N 16,000 047900 GWINVILLE FIELD - WILL-DRILL 1 N 7,000 044700 HOOKER 1 N 5,000 049912 JOAQUIN - ARCO J.S. PRICE #2 0 N 8,000 049913 JOAQUIN - ARCO J.S. PRICE #3 0 N 3,336 049911 JOAQUIN - ARCO R/S #1 0 N 5,544 049944 JOAQUIN - BIG RUN SILER #1 0 N 1,368 049952 JOAQUIN - CAMTERRA HANSON #2 0 N 3,000 049910 JOAQUIN - FREDONIA COOK#1 0 N 2,856 049927 JOAQUIN - GRAND ENERGY 0 N 5,544 049929 JOAQUIN - GRAND ENERGY R/S #2 0 N 1,752 049905 JOAQUIN - GRAND ENERGY R/S #3 0 N 6,192 049930 JOAQUIN - KEY BROOKS #1 0 N 1,128 049917 JOAQUIN - KEY C. CHILDRESS #1 0 N 14,448 049919 JOAQUIN - KEY E.L LOWE #1 0 N 2,856 049920 JOAQUIN - KEY E.L. LOWE #2 0 N 5,544 049922 JOAQUIN - KEY GARRETT #1 0 N 6,168 049906 JOAQUIN - KEY R/S #2 0 N 2,856 049924 JOAQUIN - KEY RUSHING #1 0 N 2,856 049925 JOAQUIN - KEY TEXAS CORP 0 N 2,856 049923 JOAQUIN - REED #1 0 N 3,600 049932 JOAQUIN - SONAT O.L. GUY #1 0 N 6,192 049933 JOAQUIN - SONAT O.L GUY #2 0 N 6,192 049940 JOAQUIN - SONAT PICKERING B-7 0 N 5,544 049945 JOAQUIN - SONAT PICKERING C-8 0 N 3,312 049948 JOAQUIN - SONAT PICKERING C-9 0 N 3,360 049943 JOAQUIN - SONAT R/S #2 0 N 7,500
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 3 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- --------------- --------------- 049949 JOAQUIN - STATELINE R/S 0 N 15,000 051350 JW GATHERING-DESOTO PARISH, LA. 0 N 16,000 051400 KOCH GATEWAY - KOSCIUSKO TO SNG 1 N 100,000 051300 KOCH GATEWAY - PERRYVILLE TO SNG 1 N 195,000 740310 KOCH GATEWAY- RANKIN TO SNG (DISPLACE) 1 N 38,736 030300 KOCH GATEWAY - SHADYSIDE TO SNG 0 N 269,091 601110 KOCH GATEWAY- TANGIPAHOA TO SNG (DISPLA 0 N 27,000 705010 KOCH GATEWAY - TOCA TO SNG (DISPLACE) 0 N 75,000 602510 KOCH GATEWAY - VICKSBURG TO SNG (DISPLAC 1 N 12,000 039400 LAKE CHICOT 0 N 10,000 013600 LAKE FORTUNA #1 0 N 3,000 025600 LAKE FORTUNA #2 - NOMECO 0 N 6,000 031900 LAKE LAROSE 0 N 23,500 023300 LAKE ST. CATHERINE 0 N 10,500 036100 LAKE WASHINGTON NORTH #2 - PHILLIPS 0 N 6,000 015000 LAKE WASHINGTON SOUTH - PHILLIPS 0 N 51,000 044200 LOCKHART CROSSING - AMOCO 0 Y 17,000 050012 LOGANSPORT - ARCO A.E. WELLS #1 0 N 1,368 050013 LOGANSPORT - ARCO ALSTON FROST #2 0 N 3,336 050017 LOGANSPORT - ARCO D.B. FURLOW 0 N 5,544 050016 LOGANSPORT - ARCO D.B. LEWIS 0 N 5,544 050018 LOGANSPORT - ARCO FROST BILLINGSLEY #1 0 N 2,856 050019 LOGANSPORT - ARCO FROST BILLINGSLEY #2 0 N 3,336 050021 LOGANSPORT - ARCO FROST LUMBER IND #2 0 N 2,856 050022 LOGANSPORT - ARCO FROST LUMBER IND #3 0 N 2,856 050032 LOGANSPORT - ARCO R/S #2 0 N 5,544 050027 LOGANSPORT - ARCO R/S #3 0 N 2,856 050037 LOGANSPORT - CITIES A. W. WELLS #1 0 N 5,544 050058 LOGANSPORT - CITIES A. W. WELLS #2 0 N 5,544 050043 LOGANSPORT - CITIES STEPHENS A LEASE 0 N 1,368 050044 LOGANSPORT - CITIES W. E. STEPHEN B-1 0 N 5,544 050047 LOGANSPORT - ENSERCH #1 0 N 10,104 050066 LOGANSPORT - ENSERCH #2 0 N 6,792 050067 LOGANSPORT - MARATHON DOW A-1 0 N 5,472 050061 LOGANSPORT - MARATHON O. E. PRICE #1 0 N 2,856 050069 LOGANSPORT - MARATHON PARK CIRCLE #1 0 N 3,360 050053 LOGANSPORT - MARATHON R/S #1 0 N 4,776 050001 LOGANSPORT - MARSHALL R/S #1 0 N 12,432 050002 LOGANSPORT - MARSHALL R/S #2 0 N 6,168 050003 LOGANSPORT - MARSHALL R/S #3 0 N 2,856 050004 LOGANSPORT - MARSHALL R/S #4 0 N 5,544 050064 LOGANSPORT - OXY FULMER A-1 0 N 5,544 050056 LOGANSPORT - OXY M. E. WILLIAMS #1 0 N 3,360 050040 LOGANSPORT - OXY R/S #1 0 N 5,544 050039 LOGANSPORT - OXY R/S #2 0 N 3,336 050062 LOGANSPORT - OXY R/S #3 0 N 3,360 050041 LOGANSPORT - OXY R/S #4 0 N 5,544 050068 LOGANSPORT - OXY R/S #5 0 N 3,360
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 4 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- --------------- --------------- 604110 LRC - CARRVILLE TO SNG (DISPLACEMENT) 0 N 12,400 664000 LRC - WHITE CASTLE TO SNG 0 N 133,000 024600 LUCKY FIELD 0 N 27,384 024400 MAIN PASS 108 0 N 84,000 023800 MAIN PASS 116 - VINTAGE 0 N 51,500 028200 MAIN PASS 123 - POGO 0 N 21,000 021200 MAIN PASS 133C 0 N 66,840 026700 MAIN PASS 138 - OCEAN ENERGY 0 N 11,000 017200 MAIN PASS 140 - GRAND BAY 0 N 40,000 017800 MAIN PASS 144 - CHEVRON 0 N 27,500 517000 MAIN PASS 151 0 N 9,200 018300 MAIN PASS 153 - S.P. 65 - OCEAN ENERGY 0 N 55,000 028000 MAIN PASS 181 - VINTAGE 0 N 21,000 028300 MAIN PASS 245 - WALTER O&G 0 N 47,280 019900 MAIN PASS 288 - CONOCO 0 N 6,792 018400 MAIN PASS 289 - M.P. 290 - SHELL 0 N 86,880 020000 MAIN PASS 296 0 N 16,152 017900 MAIN PASS 298 - CHEVRON 0 N 27,500 021650 MAIN PASS 301 0 N 9,500 018500 MAIN PASS 306 0 N 55,000 022900 MAIN PASS 310 0 N 25,000 021600 MAIN PASS 311A 0 N 10,000 021700 MAIN PASS 311B 0 N 10,000 021300 MAIN PASS 313 0 N 12,000 028600 MAIN PASS 36 - GALLON 0 N 40,000 016100 MAIN PASS 46 - LL&E 0 N 10,500 651000 MAIN PASS 46 - LLOG 0 N 25,500 016000 MAIN PASS 47 0 N 54,500 023200 MAIN PASS 64 - HOWELL 0 N 11,136 016450 MAIN PASS 68 0 N 18,500 016400 MAIN PASS 69 0 N 33,432 027400 MAIN PASS 69(FEDERAL) 0 N 19,080 602300 MAIN PASS 72 0 N 37,000 036901 MAIN PASS 72 - EXCHANGE 0 N 239,000 036900 MAIN PASS 73 - M.P. 72/73/74 - MOBIL 0 N 239,000 023100 MAIN PASS 77 - CHEVRON 0 N 90,000 016550 MAIN PASS 84 - PETSEC 0 N 6,336 509000 MATAGORDA ISLAND 556 0 Y 10,000 508001 MATAGORDA ISLAND 632 0 Y 65,000 502100 MATAGORDA ISLAND 665 0 Y 30,000 508900 MATAGORDA ISLAND 696 0 Y 40,000 601600 MINDEN PLANT TO SNG 0 N 66,240 603300 MISSISSIPPI CANYON 109 - BP 0 N 22,848 022400 MISSISSIPPI CANYON 194 0 N 171,000 603700 MISSISSIPPI CANYON 20 - BP 0 N 37,400 037400 MISSISSIPPI CANYON 268A - EXXON 0 N 72,900 037000 MISSISSIPPI CANYON 311 0 N 133,560 027800 MISSISSIPPI CANYON 397 0 N 240,000
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 5 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- -------------- --------------- 663200 NGPL-ERATH TO SNG 0 N 125,000 046050 OAK GROVE #2 - BASIN 2 N 61,000 046060 OAK GROVE #3 - MCKENZIE 2 N 13,440 046070 OAK GROVE #4 - TAURUS 2 N 61,000 046040 OAK GROVE #5 - TAURUS 2 N 30,500 046080 OAK GROVE #6 - TAURUS 2 N 28,000 046000 OAK GROVE - U.S. STEEL/COAL 2 N 6,400 041600 OLDENBURG FIELD - MAIN 1 N 11,500 051340 PANENERGY - PERRYVILLE 1 N 41,600 030200 PATTERSON - PLANT OUTLET 0 N 60,552 026200 PAXTON R/S 0 N 6,000 601500 PELICO - BIENVILLE PARISH TO SNG 0 N 80,280 014100 POINTE A LA HACHE 0 N 18,500 010900 QUARANTINE BAY 0 N 47,000 051320 RELIANT- PERRYVILLE HUB TO SNG 1 N 41,090 026300 ROBINSON BEND -TORCH 2 N 66,500 016500 ROMERE PASS 0 N 127,500 605200 SABINE - SABINE TO SNG 0 N 206,208 605300 SEA ROBIN - ERATH TO SNG 0 N 206,208 033200 SECTION 28 - AMOCO 0 N 3,000 664150 SHELL - MOPS EXCHANGE - MAT IS 686 (MAT 0 Y 52,000 605400 SIA - DUNCANVILLE TO SNG 2 N 83,540 051900 SIA - MCCONNELLS TO SNG 2 N 66,984 052460 SNEADS CREEK #2 2 N 25,680 020400 SOUTH PASS 60 0 N 60,000 018200 SOUTH PASS 62 - CHEVRON 0 N 27,500 018600 SOUTH PASS 62 - SHELL 0 N 57,000 021100 SOUTH PASS 70 0 N 19,500 045501 SOUTH PASS 77 - OXY 0 Y 30,000 052400 SOUTHLAND TO SNG - MERIDIAN OIL 2 N 28,848 050101 SPIDER - MIDLAND 0 N 15,000 050300 SPIDER - PHILLIPS #1 0 N 18,000 013700 STUARD'S BLUFF 0 N 7,000 013200 STUARD'S BLUFF EAST - RANGER 0 N 11,000 601410 SUGAR BOWL #6 - TO SNG - DISPLACEMENT 0 N 80,000 601900 SUGAR BOWL #7 - BIENVILLE PARISH TO SNG 0 N 12,136 603000 SUGAR BOWL #9 - DESOTO PARISH TO SNG 0 N 4,080 041900 TALLAHALA CREEK 1 N 2,500 032500 TENN - PATTERSON TO SNG 0 N 71,000 051800 TENN - PUGH TO SNG 1 N 49,224 504002 TENN - ROSE HILL TO SNG 1 N 194,016 503802 TENN - TOCA TO SNG 0 N 251,136 600810 TEXAS EASTERN - KOSCIUSKO TO SNG(DISPLAC 1 N 90,360 046400 TRANSCO - FROST TO SNG (DISPLACEMENT) 0 N 40,920 043200 TRANSCO - JONESBORO TO SNG (DISPLACEMENT 3 N 81,850 502710 TRUNKLINE - SHADYSIDE TO SNG 0 N 182,040 824100 TRUSSVILLE LNG 2 N 25,200 028400 VENICE - SHELL 0 N 200,000
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 6 of 6 RECEIPT POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- -------------- --------------- 026900 VIOSCA KNOLL 989 - BP 0 N 89,094 027900 VIRGINIA MINE - TAURUS 2 N 7,200 018450 VKGC - MAIN PASS 289 TO SNG 0 N 440,000 017100 WEST BAY #1 0 N 10,000 017120 WEST BAY #2 - NORTHCOAST 0 N 6,363 353940 WEST BLUE CREEK 2 N 2,000 017500 WEST DELTA 105 0 N 94,272 017600 WEST DELTA 133,152 - TAYLOR 0 N 94,500 024900 WEST DELTA 152 - ORYX 0 N 79,488 015100 WEST DELTA 30 0 N 22,176 025900 WEST DELTA 62 0 N 19,824 017400 WEST DELTA 75 - AMOCO (WD 73) 0 N 52,944 026600 WEST DELTA 89 - AGIP 0 N 48,000 353923 WHITE OAK #3 - SIA 2 N 5,000 353950 WHITE OAK #4 2 N 10,000 353920 WHITE OAK - SIA 2 N 48,000 047100 WOOLBANK CREEK #1 - JUSTISS OIL 2 N 6,500 047600 WOOLBANK CREEK #2 - GERMANY 2 N 4,500
SoNet Premier Page 1 of 2 SOUTHERN NATURAL GAS COMPANY FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 EXHIBIT B
--------------------------------------- PRIMARY EVERGREEN DELIVERY POINTS SERVICE SERVICE START PRIMARY NOTICE EVERGREEN NOTICE --------------------------------------- MDDQ CONTRACT TYPE TYPE CODE DATE TERM REQUIRED TERM REQUIRED POINT CODE POINT NAME (MCF) PRESSURE - ------- --------- ---------- ---------- -------- --------- --------- ---------- ---------------------------- ------- -------- FT/FTNN 1 03/01/1995 10/31/2005 180 DAYS YEARLY 180 DAYS 7253OO MVG - DEER CREEK NATURAL GAS DISTRICT 1,825 200 726000 MVG - YAZOO CITY 6,860 350 727300 MVG - BENTON 179 50 728000 MVG - PICKENS 810 75 729000 MVG - GOODMAN 624 55 730000 MVG - DURANT 1,469 100 731100 MVG - LEXINGTON 1,791 100 734900 MVG - KOSCIUSKO 100 735100 MVG - CARTHAGE 100 300 735500 MVG - NOXAPATER 589 150 735600 MVG - NORTH CENTRAL GAS DISTRICT 3,105 350 735700 MVG - LOUISVILLE 99 250 736500 MVG - MACON LINE 2,642 450 737200 MVG - DEKALB 620 150 737500 MVG - NAVAL AIR STATION 839 175 738800 MVG - STARKVILLE 11,692 110* 739500 MVG - AMORY 250 360 741400 MVG - NATCHEZ 40 60 746400 MVG - SYSTEMWIDE FARM TAPS 16 940000 MVG - MERIDIAN AREA 100
*Pressure will be increased to 400 p.s.i.g. after completion of the relocation of the Starkville tap to the Muldon Line. SoNet Premier Page 2 of 2 SOUTHERN NATURAL GAS COMPANY FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 EXHIBIT B
--------------------------------------- PRIMARY EVERGREEN DELIVERY POINTS SERVICE SERVICE START PRIMARY NOTICE EVERGREEN NOTICE --------------------------------------- MDDQ CONTRACT TYPE TYPE CODE DATE TERM REQUIRED TERM REQUIRED POINT CODE POINT NAME (MCF) PRESSURE - ------- --------- ---------- ---------- -------- --------- --------- ---------- ---------------------------- ------- -------- FT 2 O5/01/1999 10/31/2005 180 DAYS YEARLY 180 DAYS 739200 MVG - COLUMBUS 250 200 FT 3 11/01/2000 10/31/2005 180 Days Yearly 180 Days 735600 MVG-NORTH CENTRAL GAS DISTRICT 4,000 350 738800 MVG- STARKVILLE 1,000 110* 739200 MVG-COLUMBUS 5,000 200
*Pressure will be increased to 400 p.s.i.g. after completion of the relocation of the Starkville tap to the Muldon Line. [ILLEGIBLE] [ILLEGIBLE] By: --------------------------------------- By: ______________________________ MISSISSIPPI VALLEY GAS COMPANY SOUTHERN NATURAL GAS COMPANY EFFECTIVE DATE: 11/1/00 Service Agreement No. FSNG46 EXHIBIT B-l DELIVERY POINTS All active Delivery Points on Company's contiguous pipeline system, a current list of which shall be maintained by Company on its SoNet Premier bulletin board. SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 1 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- --------------------------------------- ---- --------------- --------------- 905500 ADAIRSVILLE 3 N 5,616 850010 ADEL - SGNG 2 N 2,688 033420 AGL - ANR STORAGE INJECTIONS (100 DAY) 0 N 100,000 033410 AGL - ANR STORAGE INJECTIONS (50 DAY) 0 N 100,000 033430 AGL - ANR STORAGE INJECTIONS (VALDOSTA) 0 N 100,000 683600 AGL - ATLANTA AREA 3 N 945,288 940018 AGL - ATLANTA SUBURBS 3 N 120,240 940016 AGL - AUGUSTA AREA 3 N 250,112 917800 AGL - BARNESVILLE 3 N 14,088 931600 AGL - BLYTHE 3 N 432 940041 AGL - BRUNSWICK LINE 3 N 106,416 940026 AGL - CARROLLTON AREA 3 N 41,040 907800 AGL - CATOOSA COUNTY 3 N 888 940020 AGL - CEDARTOWN - ROCKMART AREA 3 N 25,392 907600 AGL - CHATSWORTH 3 N 18,912 940019 AGL - CHATTANOOGA LINE N. 3 N 65,728 918400 AGL - DANVILLE 3 N 888 918600 AGL - DEXTER 3 N 888 940043 AGL - EAST SOUTH MAIN ZONE 3 3 N 39,720 917200 AGL - FORSYTH 3 N 17,328 913400 AGL - GRIFFIN 3 N 43,680 918000 AGL - JACKSON 3 N 2,880 918700 AGL - LAURENS COUNTY METER STATION 3 N 103,608 911500 AGL - MACON AREA 3 N 434,628 908000 AGL - RINGGOLD 3 N 11,856 940013 AGL - ROME AREA 3 N 81,144 932500 AGL - SANDERSVILLE 3 N 26,328 911800 AGL - SAVANNAH LINE 3 N 179,544 934200 AGL - SPRINGFIELD-GUYTON 3 N 864 907000 AGL - SYSTEMWIDE FARM TAPS 3 N 100 917600 AGL - THOMASTON 3 N 25,872 930600 AGL - WARRENTON 3 N 12,912 940042 AGL - WEST SOUTH MAIN ZONE 3 3 N 54,738 917400 AGL - ZEBULON 3 N 2,208 705500 AIR PRODUCTS 0 N 66,288 659700 ALA - ANNISTON AREA 2 N 78,048 841400 ALA - ASHVILLE 2 N 1,632 838100 ALA - BARRETT COMPANY 2 N 2,496 658500 ALA - BIRMINGHAM AREA 2 N 405,072 817400 ALA - BRENT & CENTERVILLE 2 N 2,880 838300 ALA - BULLOCK 2 N 1,152 659900 ALA - DEMOPOLIS AREA 2 N 8,016 806800 ALA - ECLECTIC 2 N 530 940021 ALA - FAIRFAX-SHAWMUT AREA 2 N 11,232 654700 ALA - GADSDEN AREA 2 N 94,104 801600 ALA - GREENE COUNTY 2 N 112,000 802400 ALA - GREENSBORO 2 N 2,880
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 2 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- -------------------------------- ---- --------------- --------------- 847000 ALA - HEFLIN GATE 2 N 1,468 803900 ALA - INTERNATIONAL PAPER 2 N 39,000 940035 ALA - JASPER AREA 2 N 8,832 940005 ALA - LINCOLN AREA 2 N 2,688 809500 ALA - LOCHAPOKA TAP 2 N 12,000 803400 ALA - MARION 2 N 2,832 833400 ALA - MONTEVALLO 2 N 4,176 940022 ALA - MONTGOMERY AREA 2 N 138,072 809400 ALA - NOTASULGA TAP 2 N 696 821200 ALA - OAK GROVE 2 N 1,032 940011 ALA - OPELIKA AREA 2 N 35,088 836201 ALA - PARRISH-OAKMAN 2 N 1,152 940056 ALA - PELL CITY AREA 2 N 2,304 909700 ALA - PHENIX CITY AREA 2 N 34,248 834100 ALA - PLANT MILLER 2 N 38,088 841200 ALA - RAGLAND 2 N 576 818800 ALA - REFORM #1 2 N 888 819400 ALA - REFORM #2 2 N 1,176 844800 ALA - RIVERSIDE EAST TAP 2 N 100 806000 ALA - RUSSELL MILLS 2 N 9,600 940023 ALA - SELMA AREA 2 N 42,048 847900 ALA - SYSTEMWIDE FARM TAPS 2 N 100 940006 ALA - TALLADEGA AREA 2 N 21,696 845400 ALA - TALLADEGA RACEWAY 2 N 432 940002 ALA - TUSCALOOSA AREA 2 N 85,080 940024 ALA - TUSKEGEE AREA 2 N 18,672 802600 ALA - UNIONTOWN 2 N 2,064 843200 ALABAMA POWER COMPANY - GADSDEN 2 N 25,056 940012 ALABASTER AREA 2 N 8,976 033450 ALBANY- ANR STORAGE INJECTIONS 0 N 100,000 850020 ALBANY AREA - SGNG 2 N 53,928 831900 ALLIED LIME CO 2 N 3,336 800500 AMERICAN CAN JAMES RIVERS 2 N 27,360 850030 AMERICUS AREA - SGNG 2 N 12,672 850041 ANDERSONVILLE #1 - SGNG 2 N 288 850040 ANDERSONVILLE/MULCOA AREA - SGNG 2 N 10,848 033400 ANR - SHADYSIDE TO ANR 0 N 231,888 037204 ANR EXCHANGE - EUGENE ISLAND 341 0 Y 3,650 932400 ARCADIAN 3 N 87,960 935500 ARCADIAN - SAVANNAH 3 N 21,042 916100 ARKWRIGHT 3 N 100,000 738300 ARTESIA 1 N 217 850050 ASHBURN - SGNG 2 N 2,688 850390 ATLANTA GAS LIGHT - SGNG 2 N 24,024 659000 AUSTELLAREA 3 N 60,576 782700 AVONDALE MILLS 3 N 18,258 850060 BAINBRIDGE AREA - SGNG 2 N 4,032
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 3 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ----------------------------------------------- ---- --------------- --------------- 741200 BAY SPRINGS 1 N 480 400310 BAYOU MONGOULOIS - BUY BACK 0 N 1,000 503970 BEAR CREEK - DELIVERIES TO TENNESSEE 0 Y 262,500 604810 BENSON #2 - SABINE-TEXICAN TO S-T (DISPLACEMENT) 0 N 4,500 740200 BERRY FARM TAP 1 N 0 850070 BLAKELY AREA - SGNG 2 N 3,360 832900 BLUE CIRCLE 2 N 20,904 909300 BOAZ AREA 2 N 4,824 811700 BRICKYARD - BORAL BRICK 2 N 4,488 821900 BROOKSIDE 2 N 888 820300 BROWN WOOD PRESERVING 2 N 480 731900 BUNGE CORPORATION 1 N 2,736 850080 CAIRO - SGNG 2 N 2,304 833200 CALERA 2 N 6,480 833300 CALERA #2 2 N 1,200 907400 CALHOUN, CITY OF 3 N 13,920 850090 CAMILLA - SGNG 2 N 1,728 808500 CAMP HILL 2 N 1,392 740500 CANTON 1 N 5,304 940039 CARTERSV1LLE AREA 3 N 34,752 022810 CARTHAGE - TO ETGS (DISPLACEMENT) 0 N 36,000 656801 CHANNEL INDUSTRIES EXCHANGE - MOPS TIVOL 0 Y 50,000 790200 CHATTANOOGA 3 N 67,968 832100 CHENEY LIME 2 N 3,096 844400 CHILDERSBURG #1 2 N 3,648 844500 CHILDERSBURG #2 2 N 21,456 934400 CLAXTON 3 N 2,736 915001 COCHRAN 3 N 23,904 850100 COLQUITT - SGNG 2 N 864 605510 COLUMBIA GULF - SHADYSIDE TO CG (DISPLACEMENT) 0 N 186,888 689300 COLUMBIA GULF EXCHANGE - EAST CAMERON 23 0 Y 5,000 832600 COLUMBIANA 2 N 2,376 850110 CORDELE AREA - SGNG 2 N 8,136 940027 CORDOVA AREA 2 N 3,480 705000 CREOLE PIPELINE - TOCA TO CREOLE 0 N 86,568 039510 CREOLE RECEIVING STATION (DISPLACEMENT) 0 N 62,500 940040 CULLMAN-JEFFERSON AREA 2 N 27,952 850120 CUTHBERT - SGNG 2 N 6,216 808400 DADEVILLE 2 N 4,440 940017 DALTON AREA 3 N 60,960 850130 DAWSON - SGNG 2 N 2,544 843800 DECATUR 2 N 42,122 850140 DECATUR COUNTY - SGNG 2 N 2,688 843400 DEKALB-CHEROKEE #1 2 N 10,128 843500 DEKALB-CHEROKEE #2 2 N 8,000 605910 DESTIN - ENTERPRISE TO DESTIN (DISPLACE) 1 N 769,000 014510 DIAMOND SOUTH - REDELIVERY 0 N 2,400
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 4 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- --------------- --------------- 780500 DIXIE CLAY 3 N 1,056 811500 DIXIELAND - BORAL BRICK 2 N 4,224 850150 DOERUN - SGNG 2 N 720 850160 DONALSONV1LLE - SGNG 2 N 864 834800 DORA 2 N 1,032 850170 DOUGLAS - SGNG 2 N 8,376 832300 DRAVO - LONGVIEW LIME 2 N 7,704 916800 DUBLIN #3 3 N 28,880 940028 DUBLIN AREA 3 N 24,768 790300 EAST TENN - CLEVELAND TO ETNG #1 3 N 67,626 790400 EAST TENN - CLEVELAND TO ETNG #2 3 N 20,860 916400 EATONTON-GRAY 3 N 10,344 850180 EDISON - SGNG 2 N 864 935200 ELBA ISLAND REDELIVERY TO SOUTHERN ENERG 3 N 1,000 850410 ENGELHARD - SGNG 2 N 16,104 740301 ENTEX RANKIN 1 N 38,736 732300 ERGON REFINING 1 N 11,064 814400 FAIRFAX MILLS - WEST POINT STEVENS 2 N 3,192 742500 FAYETTE, MISSISSIPPI 1 N 3,312 601000 FGT - FRANKLINTON - TO FGT 0 N 204,000 605600 FGT - FRANKLINTON WEST TO FGT 0 N 162,480 656900 FGT EXCHANGE - BRAZOS 367 0 Y 1,000 656100 FGT EXCHANGE - ESCAMBIA COUNTY, ALABAMA 2 Y 500 501200 FGT EXCHANGE - ESCAMBIA COUNTY, ALABAMA 2 Y 500 656802 FGT EXCHANGE - MOPS TIVOLI 0 Y 50,000 850190 FITZGERALD - SGNG 2 N 5,953 850425 FLORIDA POWER #2 - SGNG 2 N 38,880 850420 FLORIDA POWER - SGNG 2 N 34,368 850430 FLORIDIN - SGNG 2 N 6,048 705700 FMP SULPHUR - MAIN PASS 299 0 N 28,848 850200 FORT GAINES - SGNG 2 N 864 914800 FORT VALLEY 3 N 12,384 940029 FULTONDALE AREA 2 N 16,464 850450 GEORGIA PACIFIC CORPORATION - SGNG 2 N 7,296 850440 GOLDKIST - SGNG 2 N 2,688 819600 GORDO 2 N 948 902200 GRANTVILLE 2 N 888 940030 GRAYSVILLE AREA 2 N 14,736 601951 GULF STATES - TO GSP (DISPLACEMENT) 0 N 99,576 801000 GULF STATES PAPER COMPANY 2 N 16,488 733200 HASSIE HUNT - JOHNSON & FAIR 1 N 72 850210 HAVANA - SGNG 2 N 1,920 915002 HAWK1NSVILLE 3 N 23,904 830600 HELENA 2 N 744 902000 HOGANSVILLE 2 N 4,560 816800 HUNT REFINING COMPANY 2 N 11,424 843700 HUNTSVILLE 2 N 63,183
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 5 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ----------------------------------------------- ---- --------------- --------------- 850530 JACKSONVILLE - SGNG 2 N 81,456 846200 JACKSONVILLE, ALABAMA 2 N 8,136 850220 JASPER - SGNG 2 N 840 742700 JOHN W. MCGOWAN - FRANKLIN CO 1 N 2,304 915000 JOINTLY OWNED BOARD #1 3 N 23,904 915200 JOINTLY OWNED BOARD #2 3 N 15,000 733100 JONES & O'BRIEN - STEVENS TAP 1 N 336 781200 KENTUCKY-TENNESSEE CLAY #1 3 N 864 782400 KIMBERLY-CLARK 3 N 20,000 051410 KOCH GATEWAY - KOSCIUSKO TO KOCH 1 N 90,000 051310 KOCH GATEWAY - PERRYVILLE TO KOCH (DISPLACEMENT) 1 N 195,000 740300 KOCH GATEWAY - RANKIN TO KOCH 1 N 38,736 030320 KOCH GATEWAY - SHADYSIDE TO KOCH (DISPLACEMENT) 0 N 269,091 601100 KOCH GATEWAY - TANGIPAHOA TO KOCH 0 N 27,000 602500 KOCH GATEWAY - VICKSBURG TO KOCH 1 N 12,000 690900 KOCH GATEWAY EXCHANGE - LOCKHART CROSSIN 0 Y 16,000 905800 LAFAYETTE 3 N 12,336 814200 LAFAYETTE - CHAMBERS COUNTY, ALABAMA 2 N 4,704 901100 LAGRANGE #2 2 N 16,320 033440 LAGRANGE - ANR STORAGE INJECTIONS 0 N 100,000 707200 LAKE FORTUNA - GAS LIFT - O'MEARA 0 N 3,936 741100 LAKE ST. JOHN - INTERNATIONAL PAPER 1 N 20,400 815500 LANETT 2 N 3,336 815600 LANETT MILLS - WEST POINT STEVENS 2 N 1,392 814800 LANGDALE MILLS - JOHNSTON INDUSTRIES 2 N 1,104 815700 LANTUCK - JOHNSTON INDUSTRIES 2 N 480 826700 LEHIGH PORTLAND CEMENT 2 N 9,840 800800 LIVINGSTON 2 N 9,600 932800 LOUISVILLE 3 N 8,472 604100 LRC - CARRVILLE TO LRC 0 N 12,400 664010 LRC - WHITE CASTLE TO LRC (DISPLACEMENT) 0 N 133,000 850230 LUMPKIN-SGNG 2 N 784 014610 MAGNOLIA #2 - BUY BACK 0 N 5,000 028210 MAIN PASS 123 - REDELIVERY 0 N 2,000 021211 MAIN PASS 133A - REDELIVERY 0 N 4,500 017810 MAIN PASS 144 - REDELIVERY 0 N 2,544 017910 MAIN PASS 298 - REDELIVERY 0 N 2,544 022910 MAIN PASS 310 - REDELIVERY 0 N 2,544 021610 MAIN PASS 311 A - REDELIVERY 0 N 25,000 021750 MAIN PASS 311 B - REDELIVERY 0 N 2,544 021310 MAIN PASS 313 - REDELIVERY 0 N 2,544 028710 MAIN PASS 69 - EQUILON (REDELIVERY) 0 N 10,000 016410 MAIN PASS 69 - REDELIVERY 0 N 2,544 914200 MANCHESTER 3 N 2,880 825400 MARSHALL COUNTY #1 2 N 27,264 825500 MARSHALL COUNTY #2 2 N 31,248 666100 MATAGORDA ISLAND 526 - TEJAS POWER EXCHANGE 0 Y 10,000
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 6 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ---------------------------------------- ---- --------------- --------------- 508002 MATAGORDA ISLAND 632 - EXCHANGE TO FGT/M 0 Y 65,000 508003 MATAGORDA ISLAND 632 - EXCHANGE TO NNG/M 0 Y 65,000 508902 MATAGORDA ISLAND 696 - EXCHANGE TO FGT/M 0 Y 31,000 508903 MATAGORDA ISLAND 696 - EXCHANGE TO NNG/M 0 Y 40,000 790600 MAYTAG CLEVELAND COOKING PRODUCTS 3 N 6,500 734000 MCGOWAN #1 1 N 120 734300 MCGOWAN #2 1 N 96 802900 MCMILLAN-BLOEDEL 2 N 69,840 850240 MEIGS AREA -SGNG 2 N 2,616 850460 MERCK & COMPANY - SGNG 2 N 5,328 933200 MILLEN 3 N 2,304 850470 MILWHITE - SGNG 2 N 1,248 601610 MINDEN PLANT TO SNG (DISPLACEMENT) 0 N 66,240 726900 MISSISSIPPI CHEMICAL 1 N 52,750 850250 MONTEZUMA - SGNG 2 N 3,840 916200 MONTICELLO 3 N 4,704 850260 MOULTRIE AREA -SGNG 2 N 13,344 807900 MOUNT VERNON MILLS, INC, 2 N 696 821400 MULGA 2 N 2,064 739500 MVG - AMORY 1 N 25,416 727300 MVG - BENTON 1 N 336 735100 MVG - CARTHAGE 1 N 3,744 738600 MVG - CLAYTON VILLAGE 1 N 432 739200 MVG - COLUMBUS 1 N 20,400 725300 MVG - DEER CREEK NATURAL GAS DISTRICT 1 N 3,648 737200 MVG - DEKALB 1 N 960 730000 MVG - DURANT 1 N 1,776 729000 MVG - GOODMAN 1 N 624 734900 MVG - KOSCIUSKO 1 N 8,208 731100 MVG - LEXINGTON 1 N 5,424 736500 MVG - MACON LINE 1 N 8,208 940000 MVG - MERIDIAN AREA 1 N 62,160 741400 MVG - NATCHEZ 1 N 55 737500 MVG - NAVAL AIR STATION 1 N 1,320 735600 MVG - NORTH CENTRAL GAS DISTRICT 1 N 26,880 735500 MVG - NOXAPATER 1 N 696 728000 MVG - PICKENS 1 N 1,488 738800 MVG - STARKVILLE 1 N 12,816 746400 MVG - SYSTEMWIDE FARM TAPS 1 N 100 739600 MVG - WEST POINT 1 N 5,904 726000 MVG - YAZOO CITY 1 N 31,248 850270 NASHVILLE - SGNG 2 N 2,688 840800 NATIONAL CEMENT 2 N 10,536 663210 NGPL - ERATH TO NGPL (DISPLACEMENT) 0 N 125,000 519001 NGPL EXCHANGE - TRANSCO MARKHAM PLANT 0 Y 10,000 656800 NNG EXCHANGE - MOPS TIVOLI 0 Y 50,000 692300 NNG EXCHANGE - ROBERTS COUNTY, TEXAS 0 Y 5,000
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 7 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- -------------------------------------------------- ---- --------------- --------------- 603500 NOPSI - SNG TO NOPSI (NEW ORLEANS EAST) 0 N 114,600 819800 NORTHWEST ALABAMA GAS 2 N 12,384 656600 NUECES COUNTY, TEXAS 0 Y 1,000 046071 OAK GROVE #4 - FUEL GAS 2 N 3,768 046041 OAK GROVE #5 - FUEL GAS 2 N 3,648 046081 OAK GROVE #6 - FUEL GAS 2 N 3,768 046042 OAK GROVE -LICK CREEK 2 N 4,152 850280 OCILLA - SGNG 2 N 1,008 850500 OIL DRI OF GEORGIA - SGNG 2 N 5,376 823400 ONEONTA 2 N 5,400 935900 OWENS CORNING FIBERGLAS 3 N 984 850510 PACKAGING CORP - SGNG 2 N 7,008 850290 PELHAM - SGNG 2 N 2,424 601510 PELICO - BIENVILLE PARISH TO PELICO (DISPLACEMENT) 0 N 80,280 732700 PENNZOIL - MILNER 1 N 96 733900 PENNZOIL - MITCH PAYNE 1 N 432 733800 PENNZOIL - NAN BERRY 1 N 1,032 733600 PENNZOIL - PERRY & CHILDRESS TAP 1 N 288 733400 PENNZOIL - PERRY TAP 1 N 840 732600 PENNZOIL - POWELL & TWINER TAP 1 N 696 732900 PENNZOIL - STEVENS 1 N 336 733300 PENNZOIL - WOODRUFF & FRILEY 1 N 288 850590 PEOPLES - BAKER COUNTY - SGNG 2 N 4,800 915003 PERRY 3 N 23,904 819000 PICKENS COUNTY GAS DISTRICT 2 N 2,640 846400 PIEDMONT 2 N 9,504 790750 PLANT MARGLEN 3 N 1,000 935000 PLANT MCINTOSH 3 N 329,712 744700 PLANT SWEATT - MISSISSIPPI POWER 1 N 30,000 710200 POLARIS 0 N 1,968 850300 QUINCY-SGNG 2 N 5,304 850310 QUITMAN-SGNG 2 N 2,688 840400 RAGLAND CLAY PRODUCTS, LLC 2 N 696 740800 RALEIGH 1 N 1,440 740700 RANKIN COUNTY - PENNZOIL 1 N 600 051330 RELIANT PERRYVILLE HUB (DISPLACEMENT) 1 N 41,090 850320 RICHLAND - SGNG 2 N 624 814700 RIVERVIEW MILLS - WEST POINT STEVENS 2 N 576 742900 ROXIE 1 N 1,008 605210 SABINE - SNG TO SABINE 0 N 125,804 935300 SAVANNAH SUGAR 3 N 12,936 842600 SCOTTSBORO 2 N 8,112 782500 SCPL - AIKEN 3 N 373,872 780600 SCPL - BATH 3 N 3,648 780800 SCPL - DEL WEBB TAP 3 N 12,240 781600 SCPL - GRANITEVILLE 3 N 4,080 780200 SCPL - NORTH AUGUSTA 3 N 81,336
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 8 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- ------------------------------------------------- ---- --------------- --------------- 605310 SEA ROBIN - ERATH TO SEA ROBIN (DISPLACEMENT) 0 N 206,208 914500 SEWELL CREEK 3 N 150,000 094601 SHELL PVR REPLACEMENT GAS 0 N 1,200,000 850330 SHELLMAN - SGNG 2 N 576 605410 SIA - DUNCANVILLE TO SIA (DISPLACEMENT) 2 N 83,540 051950 SIA - MCCONNELLS TO SIA (DISPLACEMENT) 2 N 66,984 917300 SMARR 3 N 181,632 746600 SMC - SYSTEMWIDE FARM TAPS 1 N 2,000 672600 SNG - TRANSCO EXCHANGE - WHARTON COUNTY, 0 Y 10,000 732800 SOHIO PUMPING STATION 1 N 168 811400 SOUTH EASTERN ELECTRIC DEVELOPMENT CORP. 2 N 72,000 018210 SOUTH PASS 62 - REDELIVERY 0 N 2,424 021110 SOUTH PASS 70 - REDELIVERY 0 N 5,280 801900 SOUTHDOWN, INC. 2 N 1,368 940031 SOUTHEAST ALABAMA GAS DISTRICT AREA 2 N 75,264 783500 SOUTHEASTERN CLAY 3 N 744 052410 SOUTHLAND TO SOUTHLAND - DISPLACEMENT 2 N 28,848 850600 SOWEGA POWER - SGNG 2 N 41,800 930200 SPARTA 3 N 1,488 933600 STATESBORO 3 N 10,128 601400 SUGAR BOWL #6 - TO ACADIAN - CARRVILLE 0 N 80,000 601910 SUGAR BOWL #7 - BIENVILLE PH TO SB - DISPLACEMENT 0 N 12,136 603010 SUGAR BOWL #9 - DESOTO PH TO SB - DISPLACEMENT 0 N 4,080 834600 SUMITON 2 N 1,440 905400 SUMMERVILLE 3 N 17,856 848000 SYLACAUGA 2 N 15,192 933800 SYLVANIA 3 N 6,576 850340 SYLVESTER - SGNG 2 N 2,088 914000 TALBOTTON 3 N 816 850350 TALLAHASSEE - SGNG 2 N 12,000 903400 TALLAPOOSA 2 N 2,064 940032 TALLASSEE AREA 2 N 4,752 731000 TCHULA 1 N 912 840600 TEMCO METALS ASBESTOS 2 N 312 032510 TENN - PATTERSON TO TENN (DISPLACMENT) 0 N 71,000 051810 TENN - PUGH TO TENN 1 N 80,496 504001 TENN - ROSE HILL TO TENN 1 N 194,352 503803 TENN - TOCA TO TENN 0 N 90,648 032508 TENN EXCHANGE - EAST CAMERON 46 0 Y 20,000 694700 TENN EXCHANGE - SOUTH PASS 77 (SP 78) 0 Y 30,000 600800 TEXAS EASTERN - KOSCIUSKO TO TETCO 1 N 90,360 850360 THOMASVILLE - SGNG 2 N 9,744 931000 THOMSON, GEORGIA 3 N 7,440 850378 TIFTON AREA -SGNG 2 N 15,896 703500 TRANS LOUISIANA GAS COMPANY 0 N 528 603100 TRANSCO - FROST TO TRANSCO 0 N 38,448 043201 TRANSCO - JONESBORO TO TRANSCO 3 N 81,850
SoNet Premier SOUTHERN NATURAL GAS COMPANY Page 9 of 9 DELIVERY POINTS AS OF: 07/10/00
MAXIMUM POINT CODE POINT NAME ZONE OFFSYSTEM POINT VOLUME CAPACITY - ---------- --------------------------------------------- ---- --------------- ---------------- 673500 TRANSCO EXCHANGE - EUGENE ISLAND 129 0 Y 15,000 519000 TRANSCO MARKHAM PLANT - CENTRAL TEXAS LO 0 Y 10,000 906000 TRION 3 N 18,504 502711 TRUNKLINE - SHADYSIDE TO TRUNK (DISPLACEMENT) 0 N 182,040 912900 TRUSSVILLE AREA 2 N 55,128 940037 U.S. STEEL FAIRFIELD AREA 2 N 115,608 850380 UNADILLA AREA - SGNG 2 N 1,032 936300 UNION CAMP CORP. #1 3 N 38,736 936400 UNION CAMP CORP. #2 3 N 60,440 809200 UNION SPRINGS 2 N 4,392 698200 UNITED CITIES - COLUMBUS AREA 2 N 208,944 746200 VICKSBURG AREA FARM TAPS 1 N 100 850400 VIENNA - SGNG 2 N 3,240 725100 WALTHALL NATURAL GAS COMPANY 1 N 1,800 915100 WARNER ROBINS #2 3 N 19,296 915700 WARNER ROBINS #3 - MGAG 3 N 113,328 656200 WASHINGTON PARISH AREA 1 N 2,064 850520 WAVERLY MINERAL - SGNG 2 N 7,872 933000 WAYNESBORO 3 N 2,880 916300 WEST GEORGIA GENERATING 3 N 130,000 834400 WEST JEFFERSON 2 N 888 742600 WEST LINCOLN 1 N 1,728 900800 WEST POINT, GEORGIA 2 N 3,888 727600 WESTLAND RESOURCES - CMW OIL 1 N 96 740400 WESTLAND RESOURCES - MADISON 1 N 72 850540 WHITE SPRINGS NEW - SGNG 2 N 25,000 802800 WILCOX COUNTY 2 N 43,728 833800 WILTON 2 N 288 914400 WOODLAND 3 N 336 931200 WRENS 3 N 7,440 931300 WRENS #2 3 N 9,264 800200 YORK 2 N 1,176 060110 Z2-BALANCING (ACCOUNTING USE ONLY) 2 N 060100 Z3-BALANCING (ACCOUNTING USE ONLY) 3 N
SoNet Premier SOUTHERN NATURAL GAS COMPANY PAGE 1 FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 NOTICES EXHIBIT D PIPELINE MISSISSIPPI VALLEY GAS COMPANY NOTICES AND GENERAL CORRESPONDENCE SOUTHERN NATURAL GAS COMPANY MISSISSIPPI VALLEY GAS COMPANY PO BOX 2563 PO BOX 3348 BIRMINGAM, AL 35202-2563 JACKSON, MS 39203-0000 ATTENTION: SANDY NOVICK ATTENTION: PIPELINE CUSTOMER SERVICES MISSISSIPPI VALLEY GAS COMPANY TELEPHONE NO.: (205) 325-3854 TELEPHONE NO.: (601) 961-6838 FACSIMILE MACHINE NO.: (205) 326-2038 FACSIMILE MACHINE NO.: (601) 973-7055 MISSISSIPPI VALLEY GAS COMPANY PO BOX 3348 JACKSON, MS 39203-0000 ATTENTION: TONY RICHARD MISSISSIPPI VALLEY GAS COMPANY TELEPHONE NO.: (601) 961-6846 PAGER NO.: (800) 254-5491 FACSIMILE MACHINE NO.: (601) 973-7055 DISPATCHING NOTICES - NOMINATIONS ATTENTION: PIPELINE CUSTOMER SERVICES ATTENTION: TONY RICHARD TELEPHONE NO.: (205) 325-7638 MISSISSIPPI VALLEY GAS COMPANY FACSIMILE MACHINE NO.: (205) 325-7303 TELEPHONE NO.: (601) 961-6846 PAGER NO.: (800) 254-5491 FACSIMILE MACHINE NO.: (601) 973-7055 DISPATCHING NOTICES - OPERATIONAL FLOW ORDER ATTENTION: PIPELINE CUSTOMER SERVICES ATTENTION: CHARLES HEAD TELEPHONE NO.: (205) 325-3854 MISSISSIPPI VALLEY GAS COMPANY FACSIMILE MACHINE NO.: (205) 326-2038 TELEPHONE NO.: (601) 961-6848 FACSIMILE MACHINE NO.: ( ) SoNet Premier SOUTHERN NATURAL GAS COMPANY PAGE 2 FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 NOTICES EXHIBIT D PIPELINE MISSISSIPPI VALLEY GAS COMPANY ATTENTION: SANDY NOVICK MISSISSIPPI VALLEY GAS COMPANY TELEPHONE NO.: (601) 961-6838 FACSIMILE MACHINE NO.: (601) 973-7055 ATTENTION: TONY RICHARD MISSISSIPPI VALLEY GAS COMPANY TELEPHONE NO.: (601) 961-6846 PAGER NO. : (800) 254-5491 FACSIMILE MACHINE NO.: (601) 973-7055 ATTENTION: CUSTOMER SERVICE MISSISSIPPI VALLEY GAS COMPANY TELEPHONE NO.: (601) 961-6900 FACSIMILE MACHINE NO.: ( ) - 24 HOUR EMERGENCY ATTENTION: OPERATION SERVICES SEE GENERAL CORRESPONDENCE CONTACT TELEPHONE NO.: (205) 325-7223 FACSIMILE MACHINE NO.: (205) 325-7375 (1) ALTERNATE CONTACT ATTENTION: OPERATION SERVICES SEE GENERAL CORRESPONDENCE CONTACT TELEPHONE NO.: (205) 325-7305 FACSIMILE MACHINE NO.: (205) 325-7375 (2) ALTERNATE CONTACT ATTENTION: OPERATION SERVICES SEE GENERAL CORRESPONDENCE CONTACT TELEPHONE NO.: (205) 325-7308 FACSIMILE MACHINE NO.: (205) 325-7375 SoNet Premier SOUTHERN NATURAL GAS COMPANY PAGE 3 FORM OF FIRM TRANSPORTATION SERVICE AGREEMENT CONTRACT CODE: FSNG46 NOTICES EXHIBIT D PIPELINE MISSISSIPPI VALLEY GAS COMPANY PAYMENTS INVOICES BY MAIL: SOUTHERN NATURAL GAS COMPANY MISSISSIPPI VALLEY GAS COMPANY PO BOX 102502 PO BOX 3348 ATLANTA, GA 30368-0000 JACKSON, MS 39203-0000 ATTENTION: BECKY COX BY WIRE: SUN TRUST BANK MISSISSIPPI VALLEY GAS COMPANY ATLANTA TELEPHONE NO.: (601) 961-6946 ABA# 061000104 FACSIMILE MACHINE NO.: (601) 973-7055 A/C# 8800598453 EX-10.13(C) 12 d10753exv10w13xcy.txt SERVICE AGREEMENT UNDER RATE SCHEDULE CSS S10230 EXHIBIT 10.13(c) Service Agreement No. S10230 Authorization: Blanket (Reservation Charge) SERVICE AGREEMENT UNDER RATE SCHEDULE CSS THIS AGREEMENT, made and entered into as of this 1ST day of NOVEMBER, 1993, by and between Southern Natural Gas Company, a Delaware corporation, hereinafter referred to as "Company", and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Shipper". WITNESSETH WHEREAS, Company has undertaken to provide a firm storage service under Part 284 of the Federal Energy Regulatory Commission's (Commission) Regulations; and WHEREAS, Shipper has requested storage service on a firm basis pursuant to Rate Schedule CSS and has submitted to Company a request for such storage service in compliance with Section 7 of Company's Rate Schedule CSS; and WHEREAS, Company is willing to render firm storage service to Shipper pursuant to the provisions of Rate Schedule CSS, this Agreement and Subpart G of Part 284 of the Commission's Regulations. NOW, THEREFORE, the parties hereby agree as follows: ARTICLE I QUANTITY OF SERVICE 1.1 Subject to the terms and provisions of this Agreement and Company's Rate Schedule CSS and the General Terms and Conditions applicable thereto, Shipper has the right to maintain in Company's Storage fields under the terms of this Agreement an aggregate quantity of up to 990,472 Mcf (Maximum Storage Quantity). Company's obligation to accept gas at the Storage Point specified on Exhibit A hereto for injection into Storage on any day is limited to the available Maximum Daily Injection Quantity (MDIQ) specified on Exhibit A hereto. Service Agreement No. S10230 Authorization: Blanket 1.2 Company shall redeliver a thermally equivalent quantity of gas, less the applicable fuel charge as set forth in Rate Schedule CSS, to Shipper at the Storage Point described on Exhibit A hereto. Company's obligation to withdraw gas from Storage for delivery at the Storage Point on any day is limited to the available Maximum Daily Withdrawal Quantity (MDWQ) specified on Exhibit A hereto. ARTICLE II CONDITIONS OF SERVICE 2.1 It is recognized that the storage service hereunder is provided on a firm basis pursuant to, in accordance with and subject to the provisions of Company's Rate Schedule CSS, and the General Terms and Conditions thereto, which are contained in Company's FERC Gas Tariff, as in effect from time to time, and which are hereby incorporated by reference. In the event of any conflict between this Agreement and Rate Schedule CSS, the terms of Rate Schedule CSS shall govern as to the point of conflict. Any limitation of storage service hereunder shall be in accordance with the priorities set out in Rate Schedule CSS. 2.2 This Agreement shall be subject to all provisions of the General Terms and Conditions specifically made applicable to Company's Rate Schedule CSS, as such conditions may be revised from time to time. Unless Shipper requests otherwise, Company shall provide to Shipper the filings Company makes at the Commission of such provisions of the General Terms and Conditions or other matters relating to Rate Schedule CSS. 2.3 Company shall have the right to discontinue service under this Agreement in accordance with Section 15.3 of the General Terms and Conditions contained in Company's FERC Gas Tariff. 2.4 The parties hereto agree that neither party shall be liable to the other party for any special, indirect, or consequential damages (including, without limitation, loss of profits or business interruptions) arising out of or in any manner related to this Agreement. 2 Service Agreement No. S10230 Authorization: Blanket 2.5 This Agreement is subject to the provisions of Subpart G of Part 284 of the Commission's Regulations. Upon termination of this Agreement, Company and Shipper shall be relieved of further obligation to the other party except to complete the storage activities underway on the day of termination, to comply with the provisions of Section 7(f) of Rate Schedule CSS with respect to any of Shipper's gas remaining in Storage upon termination of this Agreement, to render reports, and to make payment for storage services rendered. ARTICLE III NOTICES 3.1 Except as provided in Section 6.6 herein, notices hereunder shall be given pursuant to the provisions of Section 18 of the General Terms and Conditions to the respective party at the applicable address, telephone number or facsimile machine number stated below or such other addresses, telephone numbers or facsimile machine numbers as the parties shall respectively hereafter designate in writing from time to time: 3 Service Agreement No. S10230 Authorization: Blanket Company: Notices and General Correspondence Southern Natural Gas Company Post Office Box 2563 Birmingham, Alabama 35202-2563 Attention: Transportation Services Department Telephone No.: (205) 325-7223 Facsimile Machine No.: (205) 325-7303 Dispatching Notices - Nominations/Confirmations/Scheduling Southern Natural Gas Company Post Office Box 2563 Birmingham, Alabama 35202-2563 Attention: Transportation Services Department Telephone No.: (205) 325-7223 Facsimile Machine No.: (205) 325-7303 Emergencies/24-Hour Dispatching/ Limitation and Penalty Notices Southern Natural Gas Company Post Office Box 2563 Birmingham, Alabama 35202-2563 Attention: Gas Operations Department Telephone No.: (205) 325-7308 Facsimile Machine No.: (205) 325-7375 Alternative Contact: (1) Attention: Gas Operations Department Telephone No.: (205) 325-7305 Facsimile Machine No.: (205) 325-7375 (2) Attention: Gas Operations Department Telephone No.: (205) 325-7309 Facsimile Machine No.: (205) 325-7375 Payments Southern Natural Gas Company Post Office Box 102502 68 Annex Atlanta, Georgia 30368 4 Service Agreement No. S10230 Authorization: Blanket Shipper: Notices and General Correspondence ATTN: RATES & GAS SUPPLY DEPT. P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6901 Facsimile Machine No.: (601) 961-6995 Dispatching Notices - Nominations/Confirmations TONY RICHARD, GAS CONTROL, P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6846 Facsimile Machine No.: (601) 961-6995 Dispatching Notices - Limitations TONY RICHARD, GAS CONTROL, P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6846 Facsimile Machine No.: (601) 961-6995 Emergencies and 24-Hour Dispatching Contact CHARLES A. HEAD P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6848 Facsimile Machine No.: (601) 961-6995 Alternative Contact: (1) JOHNNIE BUTLER P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6901 Facsimile Machine No.: (601) 961-6995 (2) TONY S. RICHARD P. O. BOX 3348 JACKSON, MS 39207 Telephone No.: (601) 961-6846 Facsimile Machine No.: (601) 961-6995 Invoices ATTN: RATES & GAS SUPPLY DEPT. P. O. BOX 3348 JACKSON, MS 39207 5 Service Agreement No. S10230 Authorization: Blanket ARTICLE IV TERM [AMENDED] ARTICLE V REMUNERATION 5.1 Shipper shall pay Company monthly the charges specified in Rate Schedule CSS for the storage services rendered hereunder. Company shall notify Shipper as soon as practicable of the date service will commence hereunder, and if said date is not the first day of the month, the Deliverability Charge and Capacity Charge for the first month of service hereunder shall be adjusted to reflect only the actual number of days during said month that storage service is available. Company may agree from time to time to discount the rates charged Shipper for services provided hereunder in accordance with the provisions of Rate Schedule CSS. Said discounted rates shall be set forth on Exhibit C hereto. 5.2 The rates and charges provided for under Rate Schedule CSS shall be subject to increase or decrease pursuant to any order issued by the Commission in any proceeding initiated by Company or applicable to the services performed hereunder. Shipper agrees that Company shall, without any further agreement by Shipper have the right to change from time to time, all or any part of Rate Schedule CSS or the General Terms and Conditions applicable thereto, including without limitation the right to change the rates and charges in effect hereunder, pursuant to Section 4(d) of the Natural Gas Act as may be deemed necessary by Company, in its reasonable judgment, to assure just and reasonable terms of service and rates under the Natural Gas Act. Nothing contained herein shall prejudice the rights of Shipper to contest at any time the changes made pursuant to this Section 5.2, including the right to contest the rates or charges for the services provided under this Agreement, from time to time, in any rate proceedings by Company under Section 4 of the Natural Gas Act or to file a complaint under Section 5 of the Natural Gas Act with respect to such rates or charges. 6 Service Agreement No. S10230 Authorization: Blanket ARTICLE VI MISCELLANEOUS 6.1 This Agreement constitutes the entire Agreement between the parties and no waiver by Company or Shipper of any default of either party under this Agreement shall operate as a waiver of any subsequent default whether of a like or different character. 6.2 The laws of the State of Alabama shall govern the validity, construction, interpretation, and effect of this Agreement. 6.3 No modification of or supplement to the terms and provisions hereof shall be or become effective except by execution of a supplementary written agreement between the parties. 6.4 This Agreement shall bind and benefit the successors and assigns of the respective parties hereto. Subject to the provisions of Section 22 of the General Terms and Conditions applicable hereto, neither party may assign this Agreement without the prior written consent of the other party, which consent shall not be unreasonably withheld; provided, however, that either party may assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture or similar instrument. 6.5 Exhibit A, Exhibit B (if applicable) and Exhibit C (if applicable) attached to this Agreement constitutes a part of this Agreement and is incorporated herein. 6.6 This Agreement is subject to all present and future valid laws and orders, rules, and regulations of any regulatory body of the federal or state government having or asserting jurisdiction herein. After the execution of this Agreement, each party shall make and diligently prosecute, all necessary filings with federal or other governmental bodies, or both, as may be required for the initiation and continuation of the storage service which is the subject of this Agreement. Each party shall have the right to seek such governmental authorizations, as it deems necessary, including the right to prosecute its requests or applications for such authorization in the manner it deems appropriate. Upon either party's request, the other party shall timely provide or cause to be provided to the requesting party such information and material not within the requesting party's control and/or possession that may be required for such filings. Each party shall promptly inform the other party of any changes in the representations made by such party herein and/or in the information provided pursuant to this paragraph. Each party shall promptly provide the other party with a copy of all 7 Service Agreement No. S10230 Authorization: Blanket filings, notices, approvals, and authorizations in the course of the prosecution of its filings. In the event all such necessary regulatory approvals have not been issued or have not been issued on terms and conditions acceptable to Company or Shipper within twelve (12) months from the date of the initial application therefor, then Company or Shipper may terminate this Agreement without further liability or obligation to the other party by giving written notice thereof at any time subsequent to the end of such twelve-month period, but prior to the receipt of all such acceptable approvals. Such notice will be effective as of the date it is delivered to the U.S. mail for delivery by certified mail, return receipt requested. IN WITNESS WHEREOF, this Agreement has been executed as of the date first written above by the parties' respective duly authorized officers. Attest: SOUTHERN NATURAL GAS COMPANY - -s- [ILLEGIBLE] By -s- [ILLEGIBLE] - -------------------------- ----------------------------- Its VICE PRESIDENT Attest: MISSISSIPPI VALLEY GAS COMPANY - -s- [ILLEGIBLE] By -s- WARREN K. ROGERS - -------------------------- ----------------------------- Its Senior Vice President 8 Service Agreement No. S10230 Authorization: Blanket SERVICE AGREEMENT UNDER RATE SCHEDULE CSS EXHIBIT A Maximum Daily Injection Storage Points Quantity in Mcf (1) For injection, Company's 7,619 Muldon Storage Field located in Monroe County, Mississippi, and/or the Bear Creek Storage Field located in Bienville Parish, Louisiana. (1) Shipper's MDIQ shall be subject to adjustment each day based on the quantity of gas Shipper has in Storage as follows:
Quantity in Storage Available MDIQ 0 TO 198,094 7,619 198,095 TO 396,188 7,161 396,189 TO 594,283 6,704 594,284 TO 792,377 6,171 792,378 TO 990,472 5,714
9 Service Agreement No. S10230 Authorization: Blanket SERVICE AGREEMENT UNDER RATE SCHEDULE CSS Maximum Daily Withdrawal Quantity in Mcf (2) For withdrawal, Company's 20,000 Muldon Storage Field located in Monroe County, Mississippi, and/or the Bear Creek Storage Field located in Bienville Parish, Louisiana. (2) Shipper's MDWQ shall be subject to adjustment each day based on the quantity of gas Shipper has in Storage as follows:
Quantity in Storage Available MDWQ 594,283 TO 990,472 20,000 495,236 TO 594,282 17,600 247,618 TO 495,235 15,600 0 TO 247,617 11,200
10 EX-10.13(D) 13 d10753exv10w13xdy.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(d) T-018170 GAS TRANSPORTATION AGREEMENT CONTRACT NUMBER T018170 BETWEEN TEXAS GAS TRANSMISSION CORPORATION AND MISSISSIPPI VALLEY GAS COMPANY DATED OCTOBER 29, 2001 INDEX
PAGE NO. ------- ARTICLE I Definitions 1 ARTICLE II Transportation Service 1 ARTICLE III Scheduling 2 ARTICLE IV Points of Receipt and Delivery 2 ARTICLE V Term of Agreement 3 ARTICLE VI Point(s) of Measurement 3 ARTICLE VII Facilities 3 ARTICLE VIII Rates and Charges 3 ARTICLE IX Miscellaneous 4
EXHIBIT "A" FIRM POINT(S) OF RECEIPT EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT EXHIBIT "B" FIRM POINT(S) OF DELIVERY EXHIBIT "C" SUPPLY LATERAL CAPACITY STANDARD FACILITIES KEY FIRM TRANSPORTATION AGREEMENT THIS AGREEMENT, made and entered into this 29th day of October, 2001, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Customer," WITNESSETH: WHEREAS, Customer has natural gas which it desires Texas Gas to move through its existing facilities; and WHEREAS, Texas Gas has the ability in its pipeline system to move natural gas for the account of Customer; and WHEREAS, Customer desires that Texas Gas transport such natural gas for the account of Customer; and WHEREAS, Customer and Texas Gas are of the opinion that the transaction referred to above falls within the provisions of Section 284.223 of Subpart G of Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and can be accomplished without the prior approval of the Commission; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I Definitions 1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's FERC Gas Tariff on file with the Commission is hereby incorporated by reference and made a part of this Agreement. ARTICLE II Transportation Service 2.1 Subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in Exhibit "A" hereunder, gas for transportation, and Texas Gas agrees to receive, transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder, equivalent quantities of gas to Customer or for the account of Customer, in accordance with Section 3 of Texas Gas's effective FT Rate Schedule and the terms and conditions contained herein, up to 20,476 MMBtu per day, which shall be Customer's Firm Transportation Contract Demand. 2.2 Customer shall reimburse Texas Gas for the quantity of gas required for fuel, company use, and unaccounted for associated with the transportation service hereunder in accordance with Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days' written notice before changing such percentage. 2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of the Transportation Contract Demand. 2.4 In order to protect its system, the delivery of gas to its customers and/or the safety of its operations, Texas Gas shall have the right to vent excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s) in that part of its system utilized to transport gas received hereunder. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier(s) in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's supplier(s) in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 2.5 Any gas imbalance between receipts and deliveries of gas, less fuel and PVR adjustments, if applicable, shall be cleared each month in accordance with Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff. Any imbalance remaining at the termination of this Agreement shall also be cashed-out as provided herein. ARTICLE III Scheduling 3.1 Customer shall be obligated four (4) working days prior to the end of each month to furnish Texas Gas with a schedule of the estimated daily quantity(ies) of gas it desires to be received, transported, and redelivered for the following month. Such schedules will show the quantity(ies) of gas Texas Gas will receive from Customer at the Point(s) of Receipt, along with the identity of the supplier(s) that is delivering or causing to be delivered to Texas Gas quantities for Customer's account at each Point of Receipt for which a nomination has been made. 3.2 Customer shall give Texas Gas, after the first of the month, at least twenty-four (24) hours' notice prior to the commencement of any day in which Customer desires to change the quantity(ies) of gas it has scheduled to be delivered to Texas Gas at the Point(s) of Receipt. Texas Gas agrees to waive this 24-hour prior notice and implement nomination changes requested by Customer to commence in such lesser time frame subject to Texas Gas's being able to confirm and verify such nomination change at both Receipt and Delivery Points, and receive PDAs reflecting this nomination change at both Receipt and Delivery Points. Texas Gas will use its best efforts to make the nomination change effective at the time requested by Customer; however, if Texas Gas is unable to do so, the nomination change will be implemented as soon as confirmation is received. ARTICLE IV Points of Receipt, Delivery, and Supply Lateral Allocation 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 2 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V Term of Agreement 5.1 This Agreement shall become effective November 1, 2001, and remain in full force and effect for a primary term beginning November 1, 2001, (with the rates and charges described in Article VIII becoming effective on that date) and extending for a period of one year(s) from that date, or through October 31, 2002; with extensions of one year at the end of the primary term and each additional term thereafter unless written notice is given at least three hundred sixty-five (365) days prior to the end of such term by either party. ARTICLE VI Point(s) of Measurement 6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder. 6.2 The gas shall be measured or caused to be measured by Customer and/or Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits "A", "A-I", and "B" herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE VII Facilities 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be installed, owned, and operated as specified in Exhibits "A", "A-I", and "B" herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3, 1.4, and 1.5 of Texas Gas's FT Rate Schedule and Section 30 of the General Terms and Conditions. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII Rates and Charges 8.1 Each month, Customer shall pay Texas Gas for the service hereunder an amount determined in accordance with Section 5 of Texas Gas's FT Rate Schedule contained in Texas Gas's FERC Gas Tariff, which Rate Schedule is by reference made a part of this Agreement. The maximum rates for such service consist of a monthly reservation charge multiplied by Customer's firm transportation demand as specified in Section 2.1 herein. The reservation charge shall be billed as of the effective date of this Agreement. In addition to the monthly reservation charge, Customer agrees to pay Texas Gas each month the maximum commodity charge up to Customer's transportation contract demand. For any quantities delivered by Texas Gas in excess of Customer's transportation contract 3 demand, Customer agrees to pay the maximum FT overrun commodity charge. In addition, Customer agrees to pay: (a) Texas Gas's Fuel Retention percentage(s). (b) The currently effective GRI funding unit, if applicable, the currently effective FERC Annual Charge Adjustment unit charge (ACA), the currently effective Take-or-Pay surcharge, or any other then currently effective surcharges, including but not limited to Order 636 Transition Costs. If Texas Gas declares force majeure which renders it unable to perform service herein, then Customer shall be relieved of its obligation to pay demand charges for that part of its FT contract demand affected by such force majeure event until the force majeure event is remedied. Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 10 of Texas Gas's FERC Gas Tariff. If Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or Delivery for transportation service herein, Customer will continue to pay the monthly reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is received and redelivered up to Customer's transportation contract demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's winter season or summer season transportation contract demand. Customer also agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Rate Schedule FT, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE IX Miscellaneous 9.1 Texas Gas's transportation service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties 4 agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 9.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: Texas Gas Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 20008 Owensboro, Kentucky 42304 Attention: Gas Revenue Accounting (Billings and Statements) Marketing Administration (Other Matters) Scheduling and Imbalances (Nominations) Fax (270) 688-6817 Customer Mississippi Valley Gas Company 711 West Capitol Street Jackson, Mississippi 39207-4438 Attention: Mr. Sanford Novick The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's FERC Gas Tariff. 9.3 This Agreement shall be governed by the laws of the Commonwealth of Kentucky. 9.4 Each party agrees to file timely all statements, notices, and petitions required under the Commission's regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this transportation Agreement. 9.5 All terms and conditions of Rate Schedule FT and the attached Exhibits "A", "A-I", "B", and "C" are hereby incorporated to and made a part of this Agreement. 9.6 This Agreement shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 9.7 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party and subject to the requirements of Section 25.7 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of 5 the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 9.8 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations, and orders of all governmental authorities having jurisdiction. 9.9 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXAS GAS TRANSMISSION CORPORATION - -s- SHERRY L. RICE By -s- H. DEAN JAMES II - -------------------------------- ------------------------------- Assist. Secretary Vice President WITNESSES: MISSISSIPPI VALLEY GAS COMPANY ________________________________ By -s- SANFORD NOVICK ------------------------------- ________________________________ Attest: [ILLEGIBLE] -------------------------- Secretary Date of Execution by Customer: November 19, 2001 6 CONTRACT NO. T018170 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY FIRM TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE NO. NAME WINTER SUMMER - --------------------------------------------------------------------------------------------------------------------- BEGIN LIST OF FIRM RECEIPT POINTS: NORTH LOUISIANA LEG Carthage - Haughton 1 2102 Champlin 3,461 3,517 Sharon - East 1 8760N Lonewa (NLA) 1,993 0 EAST LEG Bosco - Eunice SL 2740 Superior-Pure 443 489 SOUTHEAST LEG Blk. 8 - Morgan City SL 2460 Peltex Deep Saline #1 278 305 SL 2463 Toce Oil 15 16 SL 2638 Coon Point 210 232 SL 2755 Texaco-Bay Junop 73 80 Henry - Lafayette SL 2790 Henry Hub 9,571 10,199 Morgan City - Lafayette SL 2454 FMP/Bayou Postillion 393 433 SL 9173 ANR-Calumet (Rec.) 15 16 SOUTH LEG Egan - Eunice SL 9003 Egan 3,496 3,856 SOUTHWEST LEG Lowry - Eunice SL 2437 ENOGEX/NGPL Tap Washita 245 467 SL 9170 Transok/ NGPL Inter #2 Custer 2,692 4,123 SL 9843 Mobil - Lowry 1,225 0 WEST LEG Mallard Bay - Woodlawn SL 2207 Franks Petroleum-Chalkley 179 198 MAINLINE Eunice - Zone SL/1 Line SL 9035 ANR-Eunice 3,479 3,839
EFFECTIVE DATE: November 1, 2001 CONTRACT NO. T018170 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY FIRM TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE NO. NAME WINTER SUMMER - ---------------------------------------------------------------------------------------------------------------------------- WC-294 (AT ANR-EUNICE) INCLUDED UNDER MAINLINE HIOS (AT ANR-EUNICE) INCLUDED UNDER MAINLINE END LIST OF FIRM RECEIPT POINTS.
EFFECTIVE DATE: November 1, 2001 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - ---------------------------------------------------------------------------------------------------------------------- EAST Bosco-Eunice SL 2015 6512 Amerada Hess SL 2016 6513 Amerada Hess-South Lewisburg SL 2385 6517 D.B. McClinton #1 SL 2288 6508 Great Southern-Mowata #2 SL 9804 6545 Great Southern-Mowata #3 SL 9551 236094 Great Southern-So. Bayou Mallet SL 8142 6549 Ritchie SL 2740 6499 Superior-Pure SOUTHEAST Blk. 8-Morgan City SL 2198 10590 Bois D'Arc SL 9142 140570 Bois D'Arc-Pelican Lake SL 2109 31917 Chevron-Block 8 SL 2638 31567 Coon Point SL 2845 10588 Lake Pagie SL 2460 43557 Peltex Deep Saline #1 SL 9888 38406 Phillips-Bay Junop SL 9552 242183 S.S.20 SL 2480 31554 S.S. 41 SL 9471 43569 Sohio SL 2755 10587 Texaco-Bay Junop SL 9836 10595 Texaco-Dog Lake SL 2463 43572 Toce Oil SL 9883 10591 Zeit-Lake Pagie Henry-Lafayette SL 8190 10902 Faustina-Henry SL 2790 42612 Henry Hub SL 9597 299417 St. Mary Land-Parc Perdue Lafayette-Eunice SL 2125 8741 California Co.-North Duson SL 2138 6500 California Co.-South Bosco #2 SL 2389 8737 Duson SL 9837 43488 Excel-Judice SL 2601 8732 Fina Oil-Anslem Coulee SL 8040 6525 Florida SL 9906 38741 Quintana-South Bosco SL 9005 6538 Rayne-Columbia Gulf SL 8067 8736 South Scott SL 2810 8738 Tidewater-North Duson SL 8051 8727 Youngsville Maurice-Freshwater SL 9501 204880 Araxas-Abbeville SL 2147 10898 CNG-Hell Hole Bayou SL 2203 10890 Deck Oil-Perry/Hope SL 9160 140571 LLOG-Abbeville SL 2394 10906 LRC-Theall SL 9800 43550 May Petroleum SL 2748 127418 Parc Perdue
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------------------------------------------------------------------------------------------------------------------- SOUTHEAST (CONT.) SL 2749 10896 Parc Perdue 2 SL 9434 171296 Southwestern-Perry SL 2706 40933 Sun Ray SL 9422 160243 UNOCAL-Freshwater Bayou SL 2840 10900 UNOCAL-N. Freshwater Bayou Morgan City-Lafayette SL 2064 43425 Amoco-Charenton SL 9173 10277 ANR-Calumet (Rec.) SL 9803 38341 Atlantic SL 9809 43733 B.H. Petroleum-S.E. Avery SL 9881 80583 Bridgeline-Berwick SL 9598 299410 Burlington- Wyandotte SL 9412 185979 Equitable-Lake Peigneur SL 9047 8223 Florida Gas-E.B. Pigeon SL 2454 8215 FMP/Bayou Postillion SL 8059 10279 Franklin SL 9437 171297 Hunt Oil-Taylor Point SL 9502 211243 Hunt Oil-East Taylor Point SL 9854 43546 Linder Oil-Bayou Penchant SL 9853 60164 Linder Oil-Garden City SL 9544 225037 Nautilus-Garden City SL 2189 43561 Rutledge Deas SL 2636 8240 Shell-Bayou Pigeon SL 8149 8235 SONAT-East Bayou Pigeon SL 2035 10264 Southwest-Jeanerette SL 9895 59632 Texaco-Bayou Sale SL 8205 10272 Transco-Myette Point SL 9829 10263 Trunkline-Centerville Thibodaux-Morgan City SL 2250 33435 A. Glassell-Chacahoula SL 2335 186009 Amoco-North Rousseau SL 2835 6912 Lake Palourde SL 9873 8875 Linder Oil-Chacahoula SL 9175 124990 LLOG-Chacahoula SL 9847 43636 LRC-Choctaw SL 2445 8878 Magna-St. John #2 SL 2470 60191 Patterson-Chacahoula SL 2135 10145 Simon Pass SL 9481 144064 Transco-Thibodaux SOUTH Egan-Eunice SL 9003 38233 Egan SL 9415 171298 Tejas Power-Egan SOUTHWEST East Cameron-Lowry SL 9872 30078 E.C. 9A SL 2581 30074 E.C. 14 SL 2033 43548 Little Cheniere-Arco SL 2034 43549 Little Cheniere-Linder SL 9841 299414 LLOG-Lake Arthur SL 2392 7561 LRC-Grand Cheniere Lowry-Eunice SL 9843 156905 Mobil-Lowry SL 9446 7580 NGPL-Lowry SL 2437 149325 ENOGEX/NGPL Tap Washita
A-I-2
TGT Meter Lateral Segment Zone No. DRN Supply Point - -------------------------------------------------------------------------------------------------------------------------------- SOUTHWEST (CONT.) SL 9169 149326 TEX SW/NGPL Washita SL 9171 149313 Transok/NGPL Inter #2 Beckham SL 9170 149321 Transok/NGPL Inter #2 Custer SL 9172 149329 Transok/NGPL Waggs Wheeler WEST Iowa-Eunice SL 9507 21777 Camex-China SL 8170 8613 Iowa SL 9445 8617 Kilroy Riseden-Woodlawn Mallard Bay-Woodlawn SL 2140 8610 California Co.-South Thornwell SL 2615 7585 Caroline Hunt Sands-S. Thornwell SL 2008 299411 Cima-North Chalkley SL 2207 60169 Franks Petroleum-Chalkley SL 9028 43506 Gas Energy Development-Hayes SL 9565 299412 HS Resources- Welsh SL 2355 81054 Humble-Chalkley SL 2383 7567 IMC Wintershall-Chalkley SL 8071 7571 LRC-Mallard Bay SL 9828 8585 Riverside-Lake Arthur SL 2635 107453 Shell-Chalkley SL 2822 7586 Superior-S. Thornwell SL 2885 8603 Union Texas-Welsh MAINLINE Eunice-Zone SL/1 Line SL 9035 6519 ANR-Eunice SL 9084 105453 Bayou Pompey SL 8107 8120 Evangeline SL 9536 225010 Louisiana Chalk-Eunice SL 8046 8121 Mamou SL 3800 124803 Pooling Receipt-Zone SL SL 3900 154805 SL Lateral Terminus
A-I-3 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - ----------------------------------------------------------------------------------------------------------------- NORTH LOUISIANA Carthage-Haughton 1 2102 152451 Champlin 1 9805 43386 Delhi 1 9051 7148 Grigsby 1 9575 299431 Reliant-Oakland 1 8116 42473 Texas Eastern-Sligo 1 9884 49099 Valero-Carthage Haughton-Sharon 1 8003 43390 Barksdale 1 2455 38387 Beacon 1 9866 44088 Cornerstone-Ada 1 2340 7787 F.E. Hargraves-Minden 1 2186 7790 LGI # 1 1 9539 226834 Marathon-Cotton Valley 1 2456 7046 McCormick 1 2457 7788 Minden-Hunt 1 2459 11259 Minden Pan-Am #1 1 9819 43554 Nelson-Sibley 1 9461 43555 Olin-McGoldrick 1 2760 38250 Sligo Plant 1 9834 49082 Texaco-Athens Sharon 1 2145 38281 Claiborne 1 9439 185980 Energy Management-Antioch 1 2010 7795 Fina Oil-HICO 1 9818 7789 PGC-Bodcaw 1 2757 7792 Texas Eastern-Sharon Sharon-East 1 9418 171295 Associated-Calhoun 1 2631 38310 Calhoun Plant 1 2632 38300 Dubach 1 9554 241523 Duke Energy-Hico Knowles 1 2202 144066 Ergon-Monroe 1 8760 9334 Lonewa 1 8020 9217 MRT-Bastrop 1 9302 9335 Munce 1 9812 43556 Par Minerals/Downsville 1 9823 43559 Reliance-Bernice 1 2612 10799 Reliance-West Monroe 1 2634 9339 Southwest-Guthrie MAINLINE Bastrop-North 1 9871 132993 Entergy-Helena 1 9303 1484 Helena #2 1 1600 132977 Memphis Light, Gas and Water Division 1 3801 134577 Pooling Receipt-Zone 1 1 9563 299418 Union Pacific-Bastrop
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - ---------------------------------------------------------------------------------------------------------- MAINLINE (CONT.) Zone SL/1 Line-Bastrop 1 2020 44085 Arkla-Perryville 1 9870 44087 Channel Explo.-Chicksaw Creek 1 9826 9332 Delhi-Ewing 1 9581 273515 Entergy 1 2361 9321 Guffey-Millhaven 1 9814 43538 Hogan-Davis Lake 1 9535 227944 PanEnergy-Perryville 1 8063 9670 Pineville (L1G) 1 2648 9214 Spears 1 9832 43414 Wintershall-Clarks
A-I-2 CONTRACT NO. T018170 Contract Demand 20,476 MMBtu/D EXHIBIT "B" POINT(S) OF DELIVERY ZONE 1
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ------------------------------------------------------------------------------------------------------------- 1631 60206 Mississippi Valley Gas Company BENOIT-S12, T20N, R8W, Bolivar County, MS (1) 600 300 BOLIVAR DISTRICT - S4, T22N, R6W, Bolivar (1) 810 300 County, MS CLARKSDALE - S30, T27N, R3W, Coahoma (1) 560 250 County, MS CLARKSDALE AIR BASE-S16, T28N, R3W, (1) 560 150 Coahoma County, MS CLEVELAND - S10, T22N, R6W, Bolivar County, MS (1) 640 325 DELTA BLUFFS - S27, T1S, R9W, DeSoto County, MS 486 50 DESOTO DISTRICT - S23, T1S, R8W, DeSoto (1) 674 400 County, MS DUNCAN - S11, T25N, R5W, Bolivar County, MS (1) 840 150 FEDERAL COMPRESS-S9, T5S, R11W, Tunica (1) 486 200 County, MS GAY HILL - S29, T1S, R8W, DeSoto County, MS (1) 840 100 GREENBROOK - S24, TIS, R8W, DeSoto County, MS (1) 674 300 JONESTOWN - S4, T28N, R3W, Coahoma County, MS (1) 560 250 LAKE CORMORANT - S13, T2S, R10W, DeSoto (1) 500 150 County, MS LAKE CORMORANT #2-S31, T2S, R9W, DeSoto (1) 810 400 County, MS LULA - S25, T30N, R3W, Coahoma County, MS (1) 500 150 LYNCHBURG - S36, T1S, R9W, DeSoto County, MS (1) 840 100 LYON - S17, T27N, R3W, Coahoma County, MS (1) 640 325 MERIGOLD NO. 1 - S9, T23N, R5W, Bolivar (1) 640 150 County, MS MERIGOLD NO. 2 - S9, T23N, R5W, Bolivar (1) 640 250 County, MS MVG-GREENVILLE AIR BASE - S22, T19N, R8W (1) 600 300 Washington County, MS MVG-GREENVILLE #1-S12, T18N, R8W, (1) 640 300 Washington County, MS MVG-GREENVILLE #3 - S24, T18N, R8W, (1) 840 575 Washington County, MS MVG-GREENVILLE #4 - S14, T17N, R9W, (1) 672 250 Washington County, MS MVG-HARDY SPRINGS - Grenada County, MS (1) NATIONAL PACKING - S14, T17N, R9W, (1) 672 150 Washington County, MS NORTH TUNICA - S27, T4S, R11W, Tunica (1) 325 County, MS REFUGE PLANTING - S11, T18N, R8W, Washington (1) 672 150 County, MS
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-1
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ------------------------------------------------------------------------------------------------------------- ROBINSONVILLE - S18, T3S, R10W, Tunica (1) 486 325 County, MS RURAL-MS-MVG 50 SCOTT - S26, T20N, R8W, Bolivar County, MS (1) 600 150 SHELBY - S8, T24N, R5W, Bolivar County, MS (1) 840 150 TUNICA - S4, T5S, R11W, Tunica County, MS (1) 500 150 VINEY RIDGE ROAD - S10, T26N, R4W, Coahoma County, MS WALLS - S33, T1S, R9W, DeSoto County, MS (1) 417 150
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-2 CONTRACT NO. T018170 FIRM TRANSPORTATION AGREEMENT EXHIBIT C SUPPLY LATERAL CAPACITY MISSISSIPPI VALLEY GAS COMPANY
PREFERENTIAL RIGHTS MMBtu/d SUPPLY LATERAL WINTER SUMMER ------ ------ Zone 1 Supply Lateral(s) North Louisiana Leg: 5,454 3,517 -------------------------- Total Zone 1: 5,454 3,517 Zone SL Supply Lateral(s) East Leg: 443 489 Southeast Leg: 10,555 11,281 South Leg: 3,496 3,856 Southwest Leg: 4,162 4,590 West Leg: 179 198 WC-294 (at ANR-Eunice 900 994 HIOS (at ANR-Eunice) 2,579 2,845 --------------------------- Total Zone SL: 22,314 24,253 --------------------------- Grand Total: 27,768 27,770 ===========================
EFFECTIVE DATE: November 1, 2001 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Reliant Energy-Arkla. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Koch Midstream Services Company. (7) Measurement facilities are owned, operated, and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by CMS Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Energen Resources MAQ, Inc. and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by Reliant Energy Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. (47) Measurement facilities are owned by Forest Oil Corporation, et al., and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by PG&E Texas Pipeline, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. (62) Measurement facilities are owned by Egan Hub Partners, L. P., and operated and maintained by Texas Gas Transmission Corporation. (63) Measurement facilities are owned and maintained by Louisiana Chalk Gathering System and operated by Texas Gas Transmission Corporation. (64) Measurement facilities are owned, operated, and .maintained by Nautilus Pipeline Company. EX-10.13(E) 14 d10753exv10w13xey.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(e) T-018171 GAS TRANSPORTATION AGREEMENT CONTRACT NUMBER T018171 BETWEEN TEXAS GAS TRANSMISSION CORPORATION AND MISSISSIPPI VALLEY GAS COMPANY DATED OCTOBER 29, 2001 INDEX
PAGE NO. -------- ARTICLE I Definitions 1 ARTICLE II Transportation Service 1 ARTICLE III Scheduling 2 ARTICLE IV Points of Receipt and Delivery 2 ARTICLE V Term of Agreement 2 ARTICLE VI Point(s) of Measurement 3 ARTICLE VII Facilities 3 ARTICLE VIII Rates and Charges 3 ARTICLE IX Miscellaneous 4 EXHIBIT "A" FIRM POINT(S) OF RECEIPT EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT EXHIBIT "B" FIRM POINT(S) OF DELIVERY EXHIBIT "C" SUPPLY LATERAL CAPACITY STANDARD FACILITIES KEY
SHORT TERM FIRM TRANSPORTATION AGREEMENT THIS AGREEMENT, made and entered into this 29th day of October, 2001, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Customer," WITNESSETH: WHEREAS, Customer has natural gas which it desires Texas Gas to move through its existing facilities; and WHEREAS, Texas Gas has the ability in its pipeline system to move natural gas for the account of Customer; and WHEREAS, Customer desires that Texas Gas transport such natural gas for the account of Customer; and WHEREAS, Customer and Texas Gas are of the opinion that the transaction referred to above falls within the provisions of Section 284.223 of Subpart G of Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and can be accomplished without the prior approval of the Commission; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I Definitions 1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's FERC Gas Tariff on file with the Commission is hereby incorporated by reference and made a part of this Agreement. ARTICLE II Transportation Service 2.1 Subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in Exhibit "A" hereunder, gas for transportation, and Texas Gas agrees to receive, transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder, equivalent quantities of gas to Customer or for the account of Customer, in accordance with Section 3 of Texas Gas's effective STF Rate Schedule and the terms and conditions contained herein, up to Customer's applicable STF daily contract demand, during the periods(s) described below:
STF Daily Contract Demand Time Period (MMBtu/day) ----------- ----------- November 1, 2001 through March 31, 2002 18,595 April 1, 2002 through October 31, 2002 0
Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days' written notice before changing such percentage. 2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of the Transportation Contract Demand received hereunder. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier(s) in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's supplier(s) in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 2.4 Any gas imbalance between receipts and deliveries of gas, less fuel and PVR adjustments, if applicable, shall be cleared each month in accordance with Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff. Any imbalance remaining at the termination of this Agreement shall also be cashed-out as provided herein. ARTICLE III Scheduling 3.1 Nomination and Scheduling shall be performed consistent with Section 26 of the General Terms and Conditions. ARTICLE IV Points of Receipt, Delivery, and Supply Lateral Allocation 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V Term of Agreement 5.1 This Agreement shall become effective November 1, 2001, and remain in full force and effect for a primary term beginning November 1, 2001, (with the rates and charges described in Article VIII becoming effective on that date) and extending for a period ending October 31, 2002, with extensions of one year at the end of the primary term and each additional term thereafter unless written notice is given at least three hundred sixty-five (365) days prior to the end of such term by either party. 2 ARTICLE VI Point(s) of Measurement 6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder. 6.2 The gas shall be measured or caused to be measured by Customer and / or Texas Gas at the Point(s) of Measurement, which shall be as specified in Exhibits "A", "A-I", and "B" herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE VII Facilities 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be installed, owned, and operated as specified in Exhibits "A", "A-I", and "B" herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3 and 1.4 of Texas Gas's STF Rate Schedule and Section 30 of the General Terms and Conditions. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII Rates and Charges 8.1 Each month, Customer shall pay Texas Gas for the service hereunder, an amount determined in accordance with Section 5 of Texas Gas's STF Rate Schedule contained in Texas Gas's FERC Gas Tariff and as indicated on Exhibit "A" and Exhibit "C" herein, which Rate Schedule is by reference made a part of this Agreement. The maximum rates for such service consist of the applicable reservation charge multiplied by Customer's applicable STF daily contract demand as specified in Section 2.1 herein. The reservation charge shall be billed as of the effective date of this Agreement. In addition to the reservation charge, Customer agrees to pay Texas Gas each month the maximum commodity charge up to Customer's transportation contract demand. For any quantities delivered by Texas Gas in excess of Customer's transportation contract demand, Customer agrees to pay the maximum STF overrun commodity charge. In addition, Customer agrees to pay: (a) Texas Gas's Fuel Retention percentage(s). (b) The currently effective GRI funding unit, if applicable, the currently effective FERC Annual Charge Adjustment unit charge (ACA), the currently effective Take-or-Pay surcharge, or any other then currently effective surcharges, including but not limited to Order 636 Transition Costs. If Texas Gas declares force majeure which renders it unable to perform service herein, then Customer shall be relieved of its obligation to pay demand charges for that part of its STF contract demand affected by such force majeure event until the force majeure event is remedied. Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor 3 shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 11 D of Texas Gas's FERC Gas Tariff. If Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or Delivery for transportation service herein, Customer will continue to pay the applicable reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is received and redelivered up to Customer's STF daily contract demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's winter season or summer season transportation contract demand. Customer also agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Rate Schedule STF, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE IX Miscellaneous 9.1 Texas Gas's transportation service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 9.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: Texas Gas Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 20008 Owensboro, Kentucky 42304 Attention: Gas Revenue Accounting (Billings and Statements) Marketing Administration (Other Matters) 4 Scheduling and Imbalances (Nominations) Fax(270)688-6817 Customer Mississippi Valley Gas Company 711 West Capitol Street Jackson, Mississippi 39207-4438 Attention: Mr. Sanford Novick The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's FERC Gas Tariff. 9.3 Customer shall have fifteen (15) days from the date of receipt of this Agreement in which to execute such Agreement or Customer's request may be deemed null and void. 9.4 This Agreement shall be governed by the laws of the Commonwealth of Kentucky. 9.5 Each party agrees to file timely all statements, notices, and petitions required under the Commission's regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this transportation Agreement. 9.6 All terms and conditions of Rate Schedule STF and the attached Exhibits "A", "A-I", "B", and "C" are hereby incorporated to and made a part of this Agreement. 9.7 This contract shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 9.8 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party and subject to the requirements of Section 25.7 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 9.9 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations, and orders of all governmental authorities having jurisdiction. 9.10 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. 5 IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXAS GAS TRANSMISSION CORPORATION - -s- SHERRY L. RICE By -s- H. DEAN JAMES II - ------------------------- ---------------------------- Asst. Secretary Vice President WITNESSES: MISSISSIPPI VALLEY GAS COMPANY By -s- SANFORD NOVICK _________________________________ ----------------------------- _________________________________ Attest: [ILLEGIBLE] ----------------------------- Secretary Date of Execution by Customer: November 19, 2001 6 CONTRACT NO. T018171 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY SHORT-TERM FIRM TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE No. NAME WINTER SUMMER - -------------------------------------------------------------------------------------------------------- BEGIN LIST OF FIRM RECEIPT POINTS: NORTH LOUISIANA LEG Carthage - Haughton 1 2102 Champlin 3,144 0 Sharon - East 1 8760N Lonewa (NLA) 1,809 0 EAST LEG Bosco - Eunice SL 2740 Superior-Pure 403 0 SOUTHEAST LEG Blk. 8 - Morgan City SL 2460 Peltex Deep Saline #1 252 0 SL 2463 Toce Oil 13 0 SL 2638 Coon Point 190 0 SL 2755 Texaco-Bay Junop 67 0 Henry - Lafayette SL 2790 Henry Hub 8,694 0 Morgan City - Lafayette SL 2454 FMP/Bayou Postillion 357 0 SL 9173 ANR-Calumet(Rec.) 13 0 SOUTH LEG Egan - Eunice SL 9003 Egan 3,174 0 SOUTHWEST LEG Lowry - Eunice SL 2437 ENOGEX/NGPL Tap Washita 222 0 SL 9170 Transok/ NGPL Inter #2 Custer 2,445 0 SL 9843 Mobil - Lowry 1,113 0 WEST LEG Mallard Bay - Woodlawn SL 2207 Franks Petroleum-Chalkley 163 0 MAINLINE Eunice - Zone SL/1 Line SL 9035 ANR-Eunice 3,160 0
EFFECTIVE DATE: November 1, 2001 CONTRACT NO. T018171 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY SHORT-TERM FIRM TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE NO. NAME WINTER SUMMER - ---------------------------------------------------------------------------------------------------------- WC-294 (AT ANR-EUNICE) INCLUDED UNDER MAINLINE HIOS (AT ANR-EUNICE) INCLUDED UNDER MAINLINE END LIST OF FIRM RECEIPT POINTS.
EFFECTIVE DATE: November 1, 2001 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------------------------------------------------------------------------------------------------------------ EAST Bosco-Eunice SL 2015 6512 Amerada Hess SL 2016 6513 Amerada Hess-South Lewisburg SL 2385 6517 D.B. McClinton #l SL 2288 6508 Great Southern-Mowata #2 SL 9804 6545 Great Southern-Mowata #3 SL 9551 236094 Great Southern-So. Bayou Mallet SL 8142 6549 Ritchie SL 2740 6499 Superior-Pure SOUTHEAST Blk. 8-Morgan City SL 2198 10590 Bois D'Arc SL 9142 140570 Bois D'Arc-Pelican Lake SL 2109 31917 Chevron-Block 8 SL 2638 31567 Coon Point SL 2845 10588 Lake Pagie SL 2460 43557 Peltex Deep Saline #1 SL 9888 38406 Phillips-Bay Junop SL 9552 242183 S.S.20 SL 2480 31554 S.S.41 SL 9471 43569 Sohio SL 2755 10587 Texaco-Bay Junop SL 9836 10595 Texaco-Dog Lake SL 2463 43572 Toce Oil SL 9883 10591 Zeit-Lake Pagie Henry-Lafayette SL 8190 10902 Faustina-Henry SL 2790 42612 Henry Hub SL 9597 299417 St. Mary Land-Parc Perdue Lafayette-Eunice SL 2125 8741 California Co.-North Duson SL 2138 6500 California Co.-South Bosco #2 SL 2389 8737 Duson SL 9837 43488 Excel-Judice SL 2601 8732 Fina Oil-Anslem Coulee SL 8040 6525 Florida SL 9906 38741 Quintana-South Bosco SL 9005 6538 Rayne-Columbia Gulf SL 8067 8736 South Scott SL 2810 8738 Tidewater-North Duson SL 8051 8727 Youngsville Maurice-Freshwater SL 9501 204880 Araxas-Abbeville SL 2147 10898 CNG-Hell Hole Bayou SL 2203 10890 Deck Oil-Perry/Hope SL 9160 140571 LLOG-Abbeville SL 2394 10906 LRC-Theall SL 9800 43550 May Petroleum SL 2748 127418 Parc Perdue
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------------------------------------------------------------------------------------------------------------ SOUTHEAST (CONT.) SL 2749 10896 Parc Perdue 2 SL 9434 171296 Southwestern-Perry SL 2706 40933 Sun Ray SL 9422 160243 UNOCAL-Freshwater Bayou SL 2840 10900 UNOCAL-N. Freshwater Bayou Morgan City-Lafayette SL 2064 43425 Amoco-Charenton SL 9173 10277 ANR-Calumet (Rec.) SL 9803 38341 Atlantic SL 9809 43733 B.H. Petroleum-S.E. Avery SL 9881 80583 Bridgeline-Berwick SL 9598 299410 Burlington-Wyandotte SL 9412 185979 Equitable-Lake Peigneur SL 9047 8223 Florida Gas-E.B. Pigeon SL 2454 8215 FMP/Bayou Postillion SL 8059 10279 Franklin SL 9437 171297 Hunt Oil-Taylor Point SL 9502 211243 Hunt Oil-East Taylor Point SL 9854 43546 Linder Oil-Bayou Penchant SL 9853 60164 Linder Oil-Garden City SL 9544 225037 Nautilus-Garden City SL 2189 43561 Rutledge Deas SL 2636 8240 Shell-Bayou Pigeon SL 8149 8235 SONAT-East Bayou Pigeon SL 2035 10264 Southwest-Jeanerette SL 9895 59632 Texaco-Bayou Sale SL 8205 10272 Transco-Myette Point SL 9829 10263 Trunkline-Centerville Thibodaux-Morgan City SL 2250 33435 A. Glassell-Chacahoula SL 2335 186009 Amoco-North Rousseau SL 2835 6912 Lake Palourde SL 9873 8875 Linder Oil-Chacahoula SL 9175 124990 LLOG-Chacahoula SL 9847 43636 LRC-Choctaw SL 2445 8878 Magna-St. John #2 SL 2470 60191 Patterson-Chacahoula SL 2135 10145 Simon Pass SL 9481 144064 Transco-Thibodaux SOUTH Egan-Eunice SL 9003 38233 Egan SL 9415 171298 Tejas Power-Egan SOUTHWEST East Cameron-Lowry SL 9872 30078 E.C. 9A SL 2581 30074 E.C. 14 SL 2033 43548 Little Cheniere-Arco SL 2034 43549 Little Cheniere-Linder SL 9841 299414 LLOG-Lake Arthur SL 2392 7561 LRC-Grand Cheniere Lowry-Eunice SL 9843 156905 Mobil-Lowry SL 9446 7580 NGPL-Lowry SL 2437 149325 ENOGEX/NGPL Tap Washita
A-I-2
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------------------------------------------------------------------------------------------------------------- SOUTHWEST (CONT.) SL 9169 149326 TEX SW/NGPL Washita SL 9171 149313 Transok/NGPL Inter #2 Beckham SL 9170 149321 Transok/NGPL Inter #2 Custer SL 9172 149329 Transok/NGPL Waggs Wheeler WEST Iowa-Eunice SL 9507 21777 Camex-China SL 8170 8613 Iowa SL 9445 8617 Kilroy Riseden-Woodlawn Mallard Bay-Woodlawn SL 2140 8610 California Co.-South Thornwell SL 2615 7585 Caroline Hunt Sands-S. Thornwell SL 2008 299411 Cima-North Chalkley SL 2207 60169 Franks Petroleum-Chalkley SL 9028 43506 Gas Energy Development-Hayes SL 9565 299412 HS Resources-Welsh SL 2355 81054 Humble-Chalkley SL 2383 7567 IMC Wintershall-Chalkley SL 8071 7571 LRC-Mallard Bay SL 9828 8585 Riverside-Lake Arthur SL 2635 107453 Shell-Chalkley SL 2822 7586 Superior-S. Thornwell SL 2885 8603 Union Texas-Welsh MAINLINE Eunice-Zone SL/1 Line SL 9035 6519 ANR-Eunice SL 9084 105453 Bayou Pompey SL 8107 8120 Evangeline SL 9536 225010 Louisiana Chalk-Eunice SL 8046 8121 Mamou SL 3800 124803 Pooling Receipt-Zone SL SL 3900 154805 SL Lateral Terminus
A-I-3 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - ---------------------------------------------------------------------------------------------------------------- NORTH LOUISIANA Carthage-Hauahton 1 2102 152451 Champlin 1 9805 43386 Delhi 1 9051 7148 Grigsby 1 9575 299431 Reliant-Oakland 1 8116 42473 Texas Eastern-Sligo 1 9884 49099 Valero-Carthage Haughton-Sharon 1 8003 43390 Barksdale 1 2455 38387 Beacon 1 9866 44088 Cornerstone-Ada 1 2340 7787 F.E. Hargraves-Minden 1 2186 7790 LGI #1 1 9539 226834 Marathon-Cotton Valley 1 2456 7046 McCormick 1 2457 7788 Minden-Hunt 1 2459 11259 Minden Pan-Am #1 1 9819 43554 Nelson-Sibley 1 9461 43555 Olin-McGoldrick 1 2760 38250 Sligo Plant 1 9834 49082 Texaco-Athens Sharon 1 2145 38281 Claiborne 1 9439 185980 Energy Management- Antioch 1 2010 7795 Fina Oil-HICO 1 9818 7789 PGC-Bodcaw 1 2757 7792 Texas Eastern-Sharon Sharon-East 1 9418 171295 Associated-Calhoun 1 2631 38310 Calhoun Plant 1 2632 38300 Dubach 1 9554 241523 Duke Energy-Hico Knowles 1 2202 144066 Ergon-Monroe 1 8760 9334 Lonewa 1 8020 9217 MRT-Bastrop 1 9302 9335 Munce 1 9812 43556 Par Minerals/Downsville 1 9823 43559 Reliance-Bernice 1 2612 10799 Reliance-West Monroe 1 2634 9339 Southwest-Guthrie MAINLINE Bastrop-North 1 9871 132993 Entergy-Helena 1 9303 1484 Helena #2 1 1600 132977 Memphis Light, Gas and Water Division 1 3801 134577 Pooling Receipt-Zone 1 1 9563 299418 Union Pacific-Bastrop
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - ---------------------------------------------------------------------------------------------------------------- MAINLINE (CONT.) Zone SL/1 Line-Bastrop 1 2020 44085 Arkla-Perryville 1 9870 44087 Channel Explo.-Chicksaw Creek 1 9826 9332 Delhi-Ewing 1 9581 273515 Entergy 1 2361 9321 Guffey-Millhaven 1 9814 43538 Hogan-Davis Lake 1 9535 227944 PanEnergy-Perryville 1 8063 9670 Pineville (LIG) 1 2648 9214 Spears 1 9832 43414 Wintershall-Clarks
A-I-2 CONTRACT NO. T018171 Contract Demand 18,595 MMBtu/D Winter Only EXHIBIT "B" POINT(S) OF DELIVERY ZONE 1
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----- ----- ----------------------------------------------- ---------- ------ ------ 1631 60206 Mississippi Valley Gas Company BENOIT - S12, T20N, R8W, Bolivar County, MS (1) 600 300 BOLIVAR DISTRICT - S4, T22N, R6W, Bolivar (1) 810 300 County, MS CLARKSDALE - S30, T27N, R3W, Coahoma (1) 560 250 County, MS CLARKSDALE AIR BASE - S16, T28N, R3W, (1) 560 150 Coahoma County, MS CLEVELAND - S10, T22N, R6W, Bolivar County, MS (1) 640 325 DELTA BLUFFS - S27, T1S, R9W, DeSoto County, MS 486 50 DESOTO DISTRICT - S23, T1S, R8W, DeSoto (1) 674 400 County, MS DUNCAN - S11, T25N, R5W, Bolivar County, MS (1) 840 150 FEDERAL COMPRESS - S9, T5S, R11W, Tunica (1) 486 200 County, MS GAY HILL - S29, T1S, R8W, DeSoto County, MS (1) 840 100 GREENBROOK - S24, T1S, R8W, DeSoto County, MS (1) 674 300 JONESTOWN - S4, T28N, R3W, Coahoma County, MS (1) 560 250 LAKE CORMORANT - S13, T2S, R10W, DeSoto (1) 500 150 County, MS LAKE' CORMORANT #2 - S3i, T2S, R9w, DeSoto (1) 810 400 County, MS LULA - S25, T30N, R3W, Coahoma County, MS (1) 500 150 LYNCHBURG - S36, T1S, R9W, DeSoto County, MS (1) 840 100 LYON - S17, T27N, R3W, Coahoma County, MS (1) 640 325 MERIGOLD NO. 1 - S9, T23N, R5W, Bolivar (1) 640 150 County, MS MERIGOLD NO. 2 - S9, T23N, R5W, Bolivar (1) 640 250 County, MS MVG-GREENVILLE AIR BASE - S22, T19N, R8W (1) 600 300 Washington County, MS MVG-GREENVILLE #1 - S12, T18N, R8W, (1) 640 300 Washington County, MS MVG-GREENVILLE #3 - S24, T18N, R8W, (1) 840 575 Washington County, MS MVG-GREENVILLE #4 - S14, T17N, R9W, (1) 672 250 Washington County, MS MVG-HARDY SPRINGS - Grenada County, MS (1) NATIONAL PACKING - S14, T17N, R9W, (1) 672 150 Washington County, MS NORTH TUNICA - S27, T4S, R11 W, Tunica (1) 325 County, MS REFUGE PLANTING - S11, T18N, R8W, Washington (1) 672 150
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-1
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----- ----- ----------------------------------------------- ---------- ------ ------ County, MS ROBINSONVILLE - S18, T3S, R10W, Tunica (1) 486 325 County, MS RURAL-MS-MVG 50 SCOTT - S26, T20N, R8W, Bolivar County, MS (1) 600 150 SHELBY - S8, T24N, R5W, Bolivar County, MS (1) 840 150 TUNICA - S4, T5S, R11W, Tunica County, MS (1) 500 150 VINEY RIDGE ROAD - S10, T26N, R4W, Coahoma County, MS WALLS - S33, T1S, R9W, DeSoto County, MS (1) 417 150
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-2 CONTRACT NO. T018171 SHORT-TERM FIRM TRANSPORTATION AGREEMENT EXHIBIT C SUPPLY LATERAL CAPACITY MISSISSIPPI VALLEY GAS COMPANY
PREFERENTIAL RIGHTS MMBtu/d SUPPLY LATERAL WINTER SUMMER ------ ------ Zone 1 Supply Lateral(s) North Louisiana Leg: 4,953 0 ------------------- Total Zone 1: 4,953 0 Zone SL Supply Lateral(s) East Leg: 403 0 Southeast Leg: 9,586 0 South Leg: 3,174 0 Southwest Leg: 3,780 0 West Leg: 163 0 WC-294 (at ANR-Eunice 818 0 HIOS(at ANR-Eunice) 2,342 0 ------------------- Total Zone SL: 20,266 0 ------------------- Grand Total: 25,219 0 ===================
EFFECTIVE DATE: November 1, 2001 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Reliant Energy-Arkla. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Koch Midstream Services Company. (7) Measurement facilities are owned, operated, and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by CMS Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Energen Resources MAQ, Inc. and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by Reliant Energy Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. (47) Measurement facilities are owned by Forest Oil Corporation, et al. and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by PG&E Texas Pipeline, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. (62) Measurement facilities are owned by Egan Hub Partners, L. P., and operated and maintained by Texas Gas Transmission Corporation. (63) Measurement facilities are owned and maintained by Louisiana Chalk Gathering System and operated by Texas Gas Transmission Corporation. (64) Measurement facilities are owned, operated, and maintained by Nautilus Pipeline Company. EX-10.13(F) 15 d10753exv10w13xfy.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(f) T-15793 GAS TRANSPORTATION AGREEMENT BETWEEN TEXAS GAS TRANSMISSION CORPORATION AND MISSISSIPPI VALLEY GAS COMPANY DATED NOVEMBER 5, 1999 INDEX
PAGE NO. -------- ARTICLE I Definitions 1 ARTICLE II Transportation Service 1 ARTICLE III Scheduling 2 ARTICLE IV Points of Receipt and Delivery 2 ARTICLE V Term of Agreement 3 ARTICLE VI Point(s) of Measurement 3 ARTICLE VII Facilities 3 ARTICLE VIII Rates and Charges 3 ARTICLE IX Miscellaneous 4 EXHIBIT "A" FIRM POINT(S) OF RECEIPT EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT EXHIBIT "B" FIRM POINT(S) OF DELIVERY EXHIBIT "C" SUPPLY LATERAL CAPACITY STANDARD FACILITIES KEY
FIRM TRANSPORTATION AGREEMENT THIS AGREEMENT, made and entered into this 5th day of November, 1999, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Customer," WITNESSETH: WHEREAS, Customer, has natural gas which it desires Texas Gas to move through its existing facilities; and WHEREAS, Texas Gas has the ability in its pipeline system to move natural gas for the account of Customer; and WHEREAS, Customer desires that Texas Gas transport such natural gas for the account of Customer; and WHEREAS, Customer and Texas Gas are of the opinion that the transaction referred to above falls within the provisions of Section 284.223 of Subpart G of Part 284 of the Federal Energy Regulatory Commission's (Commission) regulations and the blanket certificate issued to Texas Gas in Docket No. CP88-686-000, and can be accomplished without the prior approval of the Commission; NOW, THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I Definitions 1.1 Definition of Terms of the General Terms and Conditions of Texas Gas's FERC Gas Tariff on file with the Commission is hereby incorporated by reference and made a part of this Agreement. ARTICLE II Transportation Service 2.1 Subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas, at the Point(s) of Receipt in Exhibit "A" hereunder, Gas for Transportation, and Texas Gas agrees to receive, transport, and redeliver, at the Point(s) of Delivery in Exhibit "B" hereunder, Equivalent Quantities of Gas to Customer or for the account of Customer, in accordance with Section 3 of Texas Gas's effective FT Rate Schedule and the terms and conditions contained herein, up to 10,000 MMBtu per day, which shall be Customer's Firm Transportation Contract Demand, and up to 1,510,000 MMBtu during the winter season, and up to 2,140,000 MMBtu during the summer season, which shall be Customer's Seasonal Quantity Levels. 2.2 Customer shall reimburse Texas Gas for the Quantity of Gas required for fuel, company use, and unaccounted for associated with the transportation service hereunder in accordance with Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. The applicable fuel retention percentage(s) is shown on Exhibit "A". Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days written notice before changing such percentage. 2.3 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of the Transportation Contract Demand, 2.4 In order to protect its system, the delivery of gas to its customers and/or the safety of its operations, Texas Gas shall have the right to vent excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s) in that part of its system utilized to transport gas received here-under. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier(s) in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's supplier(s) in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 2.5 Any gas imbalance between receipts and deliveries of gas, less fuel and PVR adjustments, if applicable, shall be cleared each month in accordance with Section 17 of the General Terms and Conditions in Texas Gas's FERC Gas Tariff. Any imbalance remaining at the termination of this Agreement shall also be cashed-out as provided herein. ARTICLE III Scheduling 3.1 Customer shall be obligated four (4) working days prior to the end of each month to furnish Texas Gas with a schedule of the estimated daily quantity(ies) of gas it desires to be received, transported, and redelivered for the following month. Such schedules will show the quantity(ies) of gas Texas Gas will receive from Customer at the Point(s) of Receipt, along with the identity of the supplier(s) that is delivering or causing to be delivered to Texas Gas quantities for Customer's account at each Point of Receipt for which a nomination has been made. 3.2 Customer shall give Texas Gas, after the first of the month, at least twenty-four (24) hours notice prior to the commencement of any day in which Customer desires to change the quantity(ies) of gas it has scheduled to be delivered to Texas Gas at the Point(s) of Receipt. Texas Gas agrees to waive this 24-hour prior notice and implement nomination changes requested by Customer to commence in such lesser time frame subject to Texas Gas's being able to confirm and verify such nomination change at both Receipt and Delivery Points, and receive PDAs reflecting this nomination change at both Receipt and Delivery Points. Texas Gas will use its best efforts to make the nomination change effective at the time requested by Customer; however, if Texas Gas is unable to do so, the nomination change will be implemented as soon as confirmation is received. ARTICLE IV Points of Receipt, Delivery, and Supply Lateral Allocation 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 2 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V Term of Agreement 5.1 This Agreement shall become effective December 1, 1999, and remain in full force and effect for a primary term beginning December 1, 1999, (with the rates and charges described in Article VIII becoming effective on that date) and extending for a period of six years from that date, or through October 31, 2005; with extensions of one year at the end of the primary term and each additional term thereafter unless written notice is given at least three hundred sixty-five (365) days prior to the end of such term by either party. ARTICLE VI Point(s) of Measurement 6.1 The gas shall be delivered by Customer to Texas Gas and redelivered by Texas Gas to Customer at the Point(s) of Receipt and Delivery hereunder. 6.2 The gas shall be measured or caused to be measured by Customer and/or Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits "A", "A-I", and "B" herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described contained in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of First Revised Volume No. 1 of Texas Gas's FERC Gas Tariff. ARTICLE VII Facilities 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement shall be installed, owned, and operated as specified hi Exhibits "A", "A-I", and "B" herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3, 1.4, and 1.5 of Texas Gas's FT Rate Schedule. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII Rates and Charges 8.1 Each month, Customer shall pay Texas Gas for the service hereunder an amount determined in accordance with Section 5 of Texas Gas's FT Rate Schedule contained in Texas Gas's FERC Gas Tariff, which Rate Schedule is by reference made a part of this Agreement. The maximum rates for such service consist of a monthly reservation charge multiplied by Customer's firm transportation demand as specified in Section 2.1 herein. The reservation charge shall be billed as of the effective date of this Agreement. In addition to the monthly reservation charge, Customer agrees to pay Texas Gas each month the maximum commodity charge up to Customer's Transportation Contract Demand. For any quantities delivered by Texas Gas in excess of Customer's Transportation Contract 3 Demand, Customer agrees to pay the maximum FT overrun commodity charge. In addition, Customer agrees to pay: (a) Texas Gas's Fuel Retention percentage(s). (b) The currently effective GRI funding unit, if applicable, the currently effective FERC Annual Charge Adjustment unit charge (ACA), the currently effective Take-or-Pay surcharge, or any other then currently effective surcharges, including but not limited to Order 636 Transition Costs. If Texas Gas declares force majeure which renders it unable to perform service herein, then Customer shall be relieved of its obligation to pay demand charges for that part of its FT Contract Demand affected by such force majeure event until the force majeure event is remedied. Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 10 of this Tariff. If Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Receipt or Delivery for transportation service herein, Customer will continue to pay the monthly reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is received and redelivered up to Customer's Transportation Contract Demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's winter season or summer season Transportation Contract Demand. Customer also agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Rate Schedule FT, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all filing fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE IX Miscellaneous 9.1 Texas Gas's Transportation Service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties 4 agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 9.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: Texas Gas Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 20008 Owensboro, Kentucky 42304 Attention: Gas Revenue Accounting (Billings and Statements) Marketing Administration (Other Matters) Gas Transportation and Capacity Allocation (Nominations) Fax (270) 688-6817 Customer Mississippi Valley Gas Company 711 West Capitol Street Jackson, MS 39204-3348 Attention: Mr. Sanford Novick The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's tariff. 9.3 This Agreement shall be governed by the laws of the State of Kentucky. 9.4 Each party agrees to file timely all statements, notices, and petitions required under the Commission's Regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this Transportation Agreement. 9.5 All terms and conditions of Rate Schedule FT and the attached Exhibits "A", "A-I", "B", and "C" are hereby incorporated to and made a part of this Agreement. 9.6 This contract shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 9.7 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do 5 business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 9.8 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations, and orders of all governmental authorities having jurisdiction. 9.9 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXAS GAS TRANSMISSION CORPORATION -s- Sherry L. Rice By -s- [ILLEGIBLE] - ----------------------------- ---------------------------------- Assist. Secretary Vice President WITNESSES: MISSISSIPPI VALLEY GAS COMPANY _____________________________ By -s- San fort Novick ---------------------------------- _____________________________ Attest: [ILLEGIBLE] ---------------------------------- Secretary Date of Execution by Customer: 10 NOVEMBER 99 6 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - --------------------------------------------------------------------------------------------------------------------- EAST Bosco-Eunice SL 2015 6512 Amerada Hess SL 2016 6513 Amerada Hess-South Lewisburg SL 2385 6517 D.B. McClinton #1 SL 2288 6508 Great Southern-Mowata #2 SL 9804 6545 Great Southern-Mowata #3 SL 9551 236094 Great Southern-So. Bayou Mallet SL 8142 6549 Ritchie SL 2740 6499 Superior-Pure SOUTHEAST Blk. 8-Morgan City SL 2198 10590 Bois D'Arc SL 9142 140570 Bois D' Arc-Pelican Lake SL 2109 31917 Chevron-Block 8 SL 2638 31567 Coon Point SL 2845 10588 Lake Pagie SL 2460 43557 Peltex Deep Saline #1 SL 9888 38406 Phillips-Bay Junop SL 9552 242183 S.S.20 SL 2480 31554 S.S. 41 SL 9471 43569 Sohio SL 2755 10587 Texaco-Bay Junop SL 9836 10595 Texaco-Dog Lake SL 2463 43572 Toce Oil SL 9883 10591 Zeit-Lake Pagie Henry-Lafayette SL 8190 10902 Faustina-Henry SL 2790 42612 Henry Hub Lafayette-Eunice SL 2125 8741 California Co.-North Duson SL 2138 6500 California Co.-South Bosco #2 SL 2389 8737 Duson SL 9837 43488 Excel-Judice SL 2601 8732 Fina Oil-Anslem Coulee SL 8040 6525 Florida SL 9906 38741 Quintana-South Bosco SL 9005 6538 Rayne-Columbia Gulf SL 8067 8736 South Scott SL 2810 8738 Tidewater-North Duson SL 8051 8727 Youngsville Maurice-Freshwater SL 9501 204880 Araxas-Abbeville SL 2147 10898 CNG-Hell Hole Bayou SL 2203 10890 Deck Oil-Perry/Hope SL 9160 140571 LLOG-Abbeville SL 2394 10906 LRC-Theall SL 9800 43550 May Petroleum SL 2748 127418 Parc Perdue SL 2749 10896 Parc Perdue 2
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - --------------------------------------------------------------------------------------------------------------------- SOUTHEAST (CONT.) SL 9434 171296 Southwestern-Perry SL 2706 40933 Sun Ray SL 9422 160243 UNOCAL-Freshwater Bayou SL 2840 10900 UNOCAL-N, Freshwater Bayou Morgan City-Lafayette SL 2064 43425 Amoco-Charenton SL 9173 10277 ANR-Calumet (Rec.) SL 9803 38341 Atlantic SL 9809 43733 B.H. Petroleum-S.E. Avery SL 9881 80583 Bridgeline-Berwick SL 9412 185979 Equitable-Lake Peigneur SL 9047 8223 Florida Gas-E.B. Pigeon SL 2454 8215 FMP/Bayou Postillion SL 8059 10279 Franklin SL 9437 171297 Hunt Oil-Taylor Point SL 9502 211243 Hunt Oil-East Taylor Point SL 9854 43546 Linder Oil-Bayou Penchant SL 9853 60164 Linder Oil-Garden City SL 9544 225037 Nautilus-Garden City SL 2189 43561 Rutledge Deas SL 2636 8240 Shell-Bayou Pigeon SL 8149 8235 SONAT-East Bayou Pigeon SL 2035 10264 Southwest- Jeanerette SL 9895 59632 Texaco-Bayou Sale SL 8205 10272 Transco-Myette Point SL 9829 10263 Trunkline-Centerville Thibodaux-Morgan City SL 2250 33435 A. Glassell-Chacahoula SL 2335 186009 Amoco-North Rousseau SL 2835 6912 Lake Palourde SL 9873 8875 Linder Oil-Chacahoula SL 9175 124990 LLOG-Chacahoula SL 9847 43636 LRC-Choctaw SL 2440 8877 Magna-Chacahoula #1 SL 2445 8878 Magna-St. John #2 SL 2470 60191 Patterson-Chacahoula SL 2135 10145 Simon Pass SL 9481 144064 Transco-Thibodaux SOUTH Egan-Eunice SL 9003 38233 Egan SL 9415 171298 Tejas Power-Egan SOUTHWEST East Cameron-Lowry SL 9872 30078 E.C. 9A SL 2581 30074 E.C. 14 SL 2033 43548 Little Cheniere-Arco SL 2034 43549 Little Cheniere-Linder SL 2392 7561 LRC-Grand Cheniere Lowry-Eunice SL 9843 156905 Mobil-Lowry SL 9446 7580 NGPL-Lowry SL 2437 149325 ENOGEX/NGPL Tap Washita SL 9169 149326 TEX SW/NGPL Washita SL 9171 149313 Transok/NGPL Inter #2 Beckham
A-I-2
TGT Meter Lateral Segment Zone No. DRN Supply Point - ---------------------------------------------------------------------------------------------------------------------- SOUTHWEST (CONT.) SL 9170 149321 Transok/NGPL Inter #2 Custer SL 9172 149329 Transok/NGPL Waggs Wheeler WEST Iowa-Eunice SL 9507 21777 Camex-China SL 8170 8613 Iowa SL 9445 8617 Kilroy Riseden-Woodlawn Mallard Bay-Woodlawn SL 2140 8610 California Co.-South Thornwell SL 2615 7585 Caroline Hunt Sands-S. Thornwell SL 2207 60169 Franks Petroleum-Chalkley SL 9028 43506 Gas Energy Development-Hayes SL 9565 HS Resources-Welsh SL 2355 81054 Humble-Chalkley SL 2383 7567 IMC Wintershall-Chalkley SL 8071 7571 LRC-Mallard Bay SL 9828 8585 Riverside-Lake Arthur SL 2635 107453 Shell-Chalkley SL 2822 7586 Superior-S. Thorwell SL 2885 8603 Union Texas-Welsh W.C. 294 Entering at ANR- SL 2868 33213 H.I. A-247/A-244A/A-231 Eunice SL 9176 154807 H.I. A-247/A-245 SL 9135 41343 W.C. 167/HIOS Mainline SL 9136 55151 W.C. 167/Near Shore SL 9026 29497 W.C. 167/132 SL 9440 186036 W.C. 293/306A SL 9396 60204 W.C. 293/H.I. 120/H.I. 120-128 SL 9383 43734 W.C.293/H.I. 167/H.I. 167-166 SL 2838 29693 W.C. 294 MAINLINE Eunice-Zone SL/1 Line SL 9035 6519 ANR-Eunice SL 9084 105453 Bayou Pompey SL 8107 8120 Evangeline SL 9536 225010 Louisiana Chalk-Eunice SL 8046 8121 Mamou SL 3800 124803 Pooling Receipt-Zone SL SL 3900 154805 SL Lateral Terminus
A-I-3 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT Meter Lateral Segment Zone No. DRN Supply Point - --------------------------------------------------------------------------------------------------------------------------- NORTH LOUISIANA Carthage-Haughton 1 2102 152451 Champlin 1 9805 43386 Delhi 1 9051 7148 Grigsby 1 9575 Reliant-Oakland 1 8116 42473 Texas Eastern-Sligo 1 9884 49099 Valero-Carthage Haughton-Sharon 1 8003 43390 Barksdale 1 2455 38387 Beacon 1 9866 44088 Cornerstone- Ada 1 2340 7787 F.E. Hargraves-Minden 1 2186 7790 LGI#1 1 9539 226834 Marathon-Cotton Valley 1 2456 7046 McCormick 1 2457 7788 Minden-Hunt 1 2459 11259 Minden Pan- Am #1 1 9819 43554 Nelson-Sibley 1 9461 43555 Olin-McGoldrick 1 2760 38250 Sligo Plant 1 9834 49082 Texaco-Athens Sharon 1 2145 38281 Claiborne 1 9439 185980 Energy Management-Antioch 1 2010 7795 Fina Oil-HICO 1 9818 7789 PGC-Bodcaw 1 2757 7792 Texas Eastern-Sharon Sharon-East 1 9418 171295 Associated-Calhoun 1 2631 38310 Calhoun Plant 1 2632 38300 Dubach 1 9554 241523 Duke Energy-Hico Knowles 1 2202 144066 Ergon-Monroe 1 8760 9334 Lonewa 1 8020 9217 MRT-Bastrop 1 9302 9335 Munce 1 9812 43556 Par Minerals/Downsville 1 9823 43559 Reliance-Bernice 1 2612 10799 Reliance-West Monroe 1 2634 9339 Southwest-Guthrie MAINLINE Bastrop-North 1 9871 132993 Entergy-Helena 1 9303 1484 Helena #2 1 1600 132977 Memphis Light, Gas and Water Division 1 3801 134577 Pooling Receipt-Zone 1 1 9563 Union Pacific-Bastrop
A-I-1
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------------------------------------------------------------------------------------------------------------------ MAINLINE (CONT.) Zone SL/1 Line-Bastrop 1 2020 44085 Arkla-Perryville 1 9870 44087 Channel Explo.-Chicksaw Creek 1 9826 9332 Delhi-Ewing 1 9581 Entergy 1 2361 9321 Guffey-Millhaven 1 9814 43538 Hogan-Davis Lake 1 9535 227944 PanEnergy-Perryville 1 8063 9670 Pineville (LIG) 1 2648 9214 Spears 1 9832 43414 Wintershall-Clarks
A-I-2 CONTRACT NO. T15793 Contract Demand 10,000 MMBtu/D EXHIBIT "B" POINT(S) OF DELIVERY ZONE 1
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----------------------------------------------------------------------------------------------------------------------- 1631 60206 Mississippi Valley Gas Company BENOIT - S12, T20N, R8W, Bolivar County, MS (1) 600 300 BOLIVAR DISTRICT - S4, T22N, R6W, Bolivar (1) 810 300 County, MS CLARKSDALE - S30, T27N, R3W, Coahoma (1) 560 250 County, MS CLARKSDALE AIR BASE - S16, T28N, R3W, (1) 560 150 Coahoma County, MS CLEVELAND - S10, T22N, R6W, Bolivar County, MS (1) 640 325 DESOTO DISTRICT - S23, T1S, R8W, DeSoto (1) 674 400 County, MS DUNCAN - Sll , T25N, R5W, Bolivar County, MS (1) 840 150 FEDERAL COMPRESS - S9, T5S, R11W, Tunica (1) 486 200 County, MS GAY HILL - S29, T1S, R8W, DeSoto County, MS (1) 840 100 GREENBROOK - S24, T1S, R8W, DeSoto County, MS (1) 674 300 JONESTOWN - S4, T28N, R3W, Coahoma County, MS (1) 560 250 LAKE CORMORANT - S13, T2S, R10W, DeSoto (1) 500 150 County, MS LAKE CORMORANT #2 - S31, T2S, R9W, DeSoto (1) 810 400 County, MS LULA - S25, T30N, R3W, Coahoma County, MS (1) 500 150 LYNCHBURG - S36, T1S, R9W, DeSoto County, MS (1) 840 100 LYON - S17, T27N, R3W, Coahoma County, MS (1) 640 325 MERIGOLD NO. 1 - S9, T23N, R5W, Bolivar (1) 640 150 County, MS MERIGOLD NO. 2 - S9, T23N, R5W, Bolivar (1) 640 250 County, MS MVG-GREENVILLE AIR BASE - S22, T19N, R8W (1) 600 300 Washington County, MS MVG-GREENVILLE #1 - S12, T18N, R8W, (1) 640 300 Washington County, MS MVG-GREENVILLE #3 - S24, T18N, R8W, (1) 840 575 Washington County, MS MVG-GREENVILLE #4 - S14, T17N, R9W, (1) 672 250 Washington County, MS MVG-HARDY SPRINGS - Grenada County, MS (1) NATIONAL PACKING - S14, T17N, R9W, (1) 672 150 Washington County, MS NORTH TUNICA - S27, T4S, R11W, Tunica (1) 325 County, MS REFUGE PLANTING - S11, T18N, R8W, Washington (1) 672 150 County, MS ROBINSONVILLE - S18, T3S, R10W, Tunica (1) 486 325 County, MS
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-l
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----------------------------------------------------------------------------------------------------------------------- RURAL-MS-MVG 50 SCOTT- S26, T20N, R8W, Bolivar County, MS (1) 600 150 SHELBY - S8, T24N, R5W, Bolivar County, MS (1) 840 150 TUNICA - S4, T5S, R11W, Tunica County, MS (1) 500 150 VINEY RIDGE ROAD - S10, T26N, R4W, Coahoma County, MS WALLS - S33, T1S, R9W, DeSoto County, MS (1) 417 150
NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE B-2 CONTRACT NO. T015793 FIRM TRANSPORTATION AGREEMENT EXHIBIT C SUPPLY LATERAL CAPACITY MISSISSIPPI VALLEY GAS COMPANY
PREFERENTIAL RIGHTS MMBtu/d SUPPLY LATERAL WINTER SUMMER ------ ------ Zone 1 Supply Lateral(s) North Louisiana Leg: 0 3,567 ---------------------------- Total Zone 1 : 0 3,567 Zone SL Supply Lateral(s) East Leg: 221 185 Southeast Leg: 5,338 3,560 South Leg: 3,514 1,380 Southwest Leg: 1,178 1,024 West Leg: 1,794 584 WC-294: 355 0 HIOS(atANR-Eunice): 0 0 ---------------------------- Total Zone SL: 12,400 6,733 ---------------------------- Grand Total: 12,400 10,300 ============================
NOTE: THIS IS A ZONE SL TO ZONE 1 FT. EFFECTIVE DATE: December 1, 1999 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Reliant Energy-Arkla. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Koch Midstream Services Company. (7) Measurement facilities are owned, operated, and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by CMS Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Energen Resources MAQ, Inc. and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by Reliant Energy Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. (47) Measurement facilities are owned by Forest Oil Corporation, et al., and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by PG&E Texas Pipeline, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. (62) Measurement facilities are owned by Egan Hub Partners, L. P., and operated and maintained by Texas Gas Transmission Corporation. (63) Measurement facilities are owned and maintained by Louisiana Chalk Gathering System and operated by Texas Gas Transmission Corporation. (64) Measurement facilities are owned, operated, and maintained by Nautilus Pipeline Company. EX-10.13(G) 16 d10753exv10w13xgy.txt FIRM NO-NOTICE TRANSPORTATION AGREEMENT EXHIBIT 10.13(g) FIRM NO-NOTICE TRANSPORTATION AGREEMENT between TEXAS GAS TRANSMISSION CORPORATION and MISSISSIPPI VALLEY GAS COMPANY Dated NOVEMBER 1, 1997 FIRM NO-NOTICE TRANSPORTATION AGREEMENT Rate Schedule NNS THIS AGREEMENT, made and entered into this 1st day of November, 1997, by and between Texas Gas Transmission Corporation, a Delaware corporation, hereinafter referred to as "Texas Gas," and Mississippi Valley Gas Company, a Mississippi corporation, hereinafter referred to as "Customer," WITNESSETH: WHEREAS, Customer was receiving a firm, bundled city gate sales service from Texas Gas on May 18, 1992, under provisions of a sales service agreement dated November 1, 1997; and WHEREAS, Customer desires to continue receiving the equivalent transportation service formerly embedded in its bundled sales service, or portion thereof, as no-notice service; and WHEREAS, Texas Gas desires to provide and Customer desires to receive such no-notice service under its NNS Rate Schedule on the terms and conditions set forth herein; NOW THEREFORE, in consideration of the premises and of the mutual covenants herein contained, the parties hereto covenant and agree as follows: ARTICLE I. DEFINITIONS 1.1 The definitions in Section 3 of Rate Schedule NNS, as well as Section 1 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff, are hereby incorporated by reference and made a part of this Agreement. ARTICLE II. QUANTITY 2.1 Pursuant to Texas Gas's Rate Schedule NNS and subject to the terms and provisions of this Agreement, Customer agrees to deliver or cause to be delivered to Texas Gas at the Point(s) of Receipt in Exhibit "A" hereunder, gas for transportation and Texas Gas agrees to receive, transport, and redeliver to Customer at the Point(s) of Delivery in Exhibit "B" hereunder, the daily and seasonal quantities of gas set forth herein. The parties agree that the transportation service provided hereunder shall be a firm service provided by combining pipeline capacity (the "Nominated" portion of the service) and storage capacity (the "Unnominated" portion of the service) into a single transportation service. 2.2 The maximum daily quantity of gas which Texas Gas shall be obligated to transport and redeliver to Customer, and which Customer shall be obligated to receive, is Customer's applicable Contract Demand expressed on a seasonal basis as set forth below:
Daily Contract Demand MMBtu/D --------------- ------- Winter 50,429 Summer 5,000
2.3 The above Contact Demands consist of a Nominated Daily Quantity, for which Customer is responsible for scheduling the delivery of gas supplies into Texas Gas's system, and an Unnominated Daily Quantity, which is 2 automatically delivered from storage by Texas Gas to meet Customer's requirements. Those quantities, expressed on a seasonal basis, are set forth below:
Nominated Daily Quantity MMBtu/D ------------------------ ------- Winter 5,000 Summer 5,000
Unnominated Daily Quantity MMBtu/D -------------------------- ------- Winter 45,429
2.4 Customer's Excess Unnominated Daily Quantity shall be 5,043 MMBtu per day, which is ten percent (10%) of its Winter Contract Demand. 2.5 The maximum seasonal quantities of gas which Texas Gas shall be obligated to transport and deliver to Customer, and which Customer shall be obligated to receive, are Customer's Seasonal Quantity Entitlements as set forth below:
Seasonal Quantity Entitlement MMBtu -------------------- --------- Winter 1,785,797 Summer 1,070,000
2.6 A portion of Customer's Winter Quantity Entitlement consists of unnominated quantities of gas delivered by Texas Gas from storage. The maximum net quantity of gas Texas Gas is obligated to deliver to Customer from storage during any Winter Season is Customer's Unnominated Seasonal Quantity, which is 1,030,797 MMBtu. In addition to scheduling the receipt of Customer's Summer Quantity Entitlement, Customer is also responsible for the redelivery each summer of that portion of Customer's Unnominated Seasonal Quantity actually used the prior winter, as more fully set forth herein. 2.7 Customer shall reimburse Texas Gas for the Quantity of Gas required for fuel, company use, and unaccounted for associated with the transportation service hereunder in accordance with Section 16 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. Texas Gas may adjust the fuel retention percentage as operating circumstances warrant; however, such change shall not be retroactive. Texas Gas agrees to give Customer thirty (30) days written notice before changing such percentage. 2.8 Texas Gas, at its sole option, may, if tendered by Customer, transport daily quantities in excess of Customer's Contract Demand. 2.9 In order to protect its system, the delivery of gas to its customers and/or the safety of its operations, Texas Gas shall have the right to vent excess natural gas delivered to Texas Gas by Customer or Customer's supplier(s) in that part of its system utilized to transport gas received hereunder. Prior to venting excess gas, Texas Gas will use its best efforts to contact Customer or Customer's supplier in an attempt to correct such excess deliveries to Texas Gas. Texas Gas may vent such excess gas solely within its reasonable judgment and discretion without liability to Customer, and a pro rata share of any gas so vented shall be allocated to Customer. Customer's pro rata share shall be determined by a fraction, the numerator of which shall be the quantity of gas delivered to Texas Gas at the Point of Receipt by Customer or Customer's suppliers in excess of Customer's confirmed nomination and the denominator of which shall be the total quantity of gas in excess of total confirmed nominations flowing in that part of Texas Gas's system utilized to transport gas, multiplied by the total quantity of gas vented or lost hereunder. 3 ARTICLE III. SCHEDULING OF CUSTOMER'S NOMINATED DAILY QUANTITY 3.1 This Article III only applies to the scheduling of the Nominated Daily Quantity portion of Customer's Contract Demand and not to the Unnominated Daily Quantity of Unnominated Seasonal Quantity delivered from storage. 3.2 Customer shall be obligated four (4) working days prior to the end of each month to furnish Texas Gas with a schedule of the estimated daily quantity(ies) of gas it desires to be received, transported, and redelivered for the following month. Such schedules will show the quantity(ies) of gas Texas Gas will receive from Customer at the Point(s) of Receipt, along with the identity of the supplier(s) that is delivering or causing to be delivered to Texas Gas quantities for Customer's account at each Point of Receipt for which a nomination has been made. 3.3 Customer shall give Texas Gas, after the first of the month, twenty-four (24) hours notice prior to the commencement of any day in which Customer desires to change the quantity(ies) of gas it has scheduled to be delivered to Texas Gas at the Point(s) of Receipt. If Customer's nomination change does not require Texas Gas to interrupt service to another customer, Texas Gas will agree to waive this 24-hour prior notice and implement nomination changes requested by customer to commence in such lesser time frame subject to Texas Gas's being able to confirm and verify such nomination change at both receipt and delivery points, and receive PDA's reflecting this nomination change at both receipt and delivery points. Texas Gas will use its best efforts to make the nomination change effective at the time requested by customer; however, if Texas Gas is unable to do so, the nomination change will be implemented as soon as confirmation is received. ARTICLE IV. POINTS OF RECEIPT AND DELIVERY AND SUPPLY LATERAL ALLOCATION 4.1 Customer shall deliver or cause to be delivered natural gas to Texas Gas at the Point(s) of Receipt specified in Exhibit "A" attached hereto and Texas Gas shall redeliver gas to Customer or for the account of Customer at the Point(s) of Delivery specified in Exhibit "B" attached hereto, in accordance with Sections 7 and 15 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 4.2 Customer's preferential capacity rights on each of Texas Gas's supply laterals shall be as set forth in Exhibit "C" attached hereto, in accordance with Section 34 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. ARTICLE V. TERM OF AGREEMENT 5.1 This Agreement shall become effective November 1, 1997, and shall remain in full force and effect for a primary term of five (5) years ending October 31, 2002. At the end of such primary term, or any subsequent rollover term, this Agreement shall automatically be extended for an additional rollover term of five (5) years, unless Customer terminates this Agreement at the end of such primary or rollover term by giving Texas Gas at least 365 days advance written notice prior to the expiration of the primary term or any subsequent rollover term. ARTICLE VI. POINT OF MEASUREMENT 6.1 The gas shall be measured or caused to be measured by Customer and/or Texas Gas at the Point(s) of Measurement which shall be as specified in Exhibits A, A-I, and B herein. In the event of a line loss or leak between the Point of Measurement and the Point of Receipt, the loss shall be determined in accordance with the methods described in Section 3, "Measuring and Measuring Equipment," contained in the General Terms and Conditions of First Revised Volume No. 1 of Texas Gas's FERC Gas Tariff. 4 ARTICLE VII. FACILITIES 7.1 Texas Gas and Customer agree that any facilities required at the Point(s) of Receipt, Point(s) of Delivery, and Point(s) of Measurement, shall be installed, owned, and operated as specified in Exhibits A, A-I, and B herein. Customer may be required to pay or cause Texas Gas to be paid for the installed cost of any new facilities required as contained in Sections 1.3, 1.4 and 1.5 of Texas Gas's FT Rate Schedule. Customer shall only be responsible for the installed cost of any new facilities described in this Section if agreed to in writing between Texas Gas and Customer. ARTICLE VIII. RATES AND CHARGES 8.1 Unless otherwise agreed to in writing by Texas Gas and Customer, Customer shall pay to Texas Gas each month a Reservation Charge which shall consist of the applicable Contract Demand as specified in this Agreement multiplied by the applicable demand rate per MMBtu. The Reservation Charge shall be billed as of the effective date of this Agreement. Unless otherwise agreed to in writing by Texas Gas and Customer, Customer shall also pay Texas Gas the Maximum Commodity Rate per MMBtu of gas delivered by Texas Gas for no-notice transportation services rendered to Customer up to Customer's applicable Contract Demand. For all gas quantities delivered in excess of Customer's applicable Contract Demand on any day, Customer shall pay the NNS Overrun Rate per MMBtu, as described in the NNS Rate Schedule. In addition, Customer shall pay any and all currently effective demand or commodity surcharges, including but not limited to, the GRI Funding Unit, the FERC ACA Unit Charge, Texas Gas's Take-or-Pay surcharge, and Order 636 Transition Costs surcharge. If Texas Gas declares force majeure which renders it unable to perform service for Customer under this Agreement either in whole or part, then Customer shall be relieved of its obligation to pay NNS demand charges for that part of its NNS contract demand affected by such force majeure event until the force majeure event is remedied. Unless otherwise agreed to in writing by Texas Gas and Customer, Texas Gas may, from time to time, and at any time selectively after negotiation, adjust the rate(s) applicable to any individual Customer; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth in the currently effective Sheet No. 10 of Texas Gas's FERC Gas Tariff. If Texas Gas so adjusts any rates to any Customer, Texas Gas shall file with the Commission any and all required reports respecting such adjusted rate. 8.2 In the event Customer utilizes a Secondary Point(s) of Delivery for transportation service herein, Customer will continue to pay the monthly reservation charges as described in Section 8.1 above. In addition, Customer will pay the maximum commodity charge applicable to the zone in which gas is delivered up to Customer's applicable Contract Demand and the maximum overrun commodity charge for any quantities delivered by Texas Gas in excess of Customer's Seasonal Quantity Entitlement. Customer also agrees to pay the ACA, Take-or-Pay Surcharge, GRI charges, fuel retention charge, and any other effective surcharges, if applicable, as described in Section 8.1 above. 8.3 It is further agreed that Texas Gas may seek authorization from the Commission and/or other appropriate body for such changes to any rate(s) and terms set forth herein or in Texas Gas's tariff, as may be found necessary to assure Texas Gas just and reasonable rates. Nothing herein contained shall be construed to deny Customer any rights it may have under the Natural Gas Act, as amended, including the right to participate fully in rate proceedings by intervention or otherwise to contest increased rates in whole or in part. 8.4 Customer agrees to fully reimburse Texas Gas for all fees, if any, associated with the service contemplated herein which Texas Gas is required to pay to the Commission or any agency having or assuming jurisdiction of the transactions contemplated herein. 8.5 Customer agrees to execute or cause its supplier or processor to execute a separate agreement with Texas Gas providing for the transportation of any liquids and/or liquefiables, and agrees to pay or reimburse Texas Gas, or cause Texas Gas to be paid or reimbursed, for any applicable rates or charges associated with the transportation of such liquids and/or liquefiables, as specified in Section 24 of the General Terms and Conditions of Texas Gas's FERC Gas Tariff. 5 ARTICLE IX. WINTER SERVICE 9.1 Customer will only be required to nominate into Texas Gas's system a quantity of gas up to the Nominated Daily Quantity. 9.2 In addition to the Nominated Daily Quantity actually scheduled by Customer, Texas Gas will adjust deliveries from storage up to Customer's Unnominated Daily Quantity to meet Customer's city gate requirements up to Customer's Winter Contract Demand. 9.3 In addition, Customer may exceed its Unnominated Daily Quantity by a quantity equal to its Excess Unnominated Daily Quantity (i.e. 10% of its Winter Contract Demand) for up to two consecutive gas days without a penalty; however, total deliveries to the Customer may not exceed the Customer's Winter Contract Demand. Texas Gas will notify the Customer within four (4) hours of the end of the gas day in which Customer has exceeded its Unnominated Daily Quantity. If the Customer does not cease taking such Excess Unnominated Daily Quantity from Texas Gas's storage after two consecutive gas days, then pipeline may assess a penalty of $15 per MMBtu of such excess gas taken and may issue an operational flow order requiring Customer to immediately inject additional gas supply and/or reduce city gate deliveries so that the customer is no longer exceeding his Unnominated Daily Quantity. 9.4 Monthly Maximum Withdrawal: No more than 50% of Customer's Unnominated Seasonal Quantity shall be withdrawn in any consecutive thirty (30) day period. 9.5 Seasonal Minimum and Maximum Withdrawal: No more than 105% of Customer's Unnominated Seasonal Quantity shall be withdrawn by March 1; provided further, that no less than 68% and no more than 100% of Customer's Unnominated Seasonal Quantity shall be withdrawn by April 1 (the end of the Winter Season). 9.6 Adjusted Unnominated Daily Quantity: As Customer's Unnominated Seasonal Quantity (USQ) is withdrawn, that portion of Customer's Unnominated Daily Quantity (UDQ) available to Customer shall be adjusted. Customer's Adjusted Unnominated Daily Quantity (UDQ) shall be equal to the greater of its average winter daily unnominated quantity (i.e., Customer's USQ divided by the total number of Winter days the UDQ is available) or the applicable percentage of its Unnominated Daily Quantity (UDQ) as set forth in the following table:
% USQ Withdrawn % UDQ Available --------------- --------------- 75% 90% 80% 85% 85% 80% 90% 75%
9.7 During the Winter Season, Texas Gas will also inject gas into storage on a best efforts basis as part of NNS service. Although such injections will be done on a best efforts basis, Texas Gas will be presumed, unless it gives notice to the contrary, to be able to inject into storage such quantities of gas as to take into account routine variations in no-notice deliveries. If Texas Gas is unable to make such best efforts injections, it will advise Customer by posting on its electronic bulletin board. However, no presumption will exist for nonroutine situations (e.g. injections in excess of 15% of Customer's Winter Contract Demand or sustained injections of more than five days) and Customer must give 24 hours advance written notice to Texas Gas of quantities it desires to inject into storage, so that Texas Gas can determine the extent to which it can make such injections and adjust its operations accordingly. ARTICLE X. SUMMER SERVICE 10.1 Texas Gas shall deliver to Customer at the city gate during each Summer Season up to the Customer's Summer Contract Demand and Summer Quantity Entitlement as nominated by Customer. 6 10.2 Pursuant to the provisions set forth below, Customer shall deliver in kind to Texas Gas during each Summer Season a quantity of gas equal to that portion of Customer's Unnominated Seasonal Quantity actually utilized by Customer (including any infield transfers pursuant to Section 25.8(c) of the General Terms and Conditions of this tariff) during the prior Winter Season. Customer shall reserve and utilize such portion of its Summer Contract Demand as necessary to redeliver such volumes into storage. 10.3 Maximum Daily Injection Quantity: To protect the storage formations and allow uniform filling of the storage reservoirs, Customer will be required to adhere to certain injection limits (calculated as a percentage of the Unnominated Seasonal Quantity), throughout the summer injection period. During the Summer Season Customer may, on a daily basis, inject according to the following table:
% of Unnominated Maximum Available Seasonal Quantity Injection Rate Injected (% of USQ) ---------------- ----------------- 0%- 65% 1.3% 65%-90% 1.1% >90% 0.6%
10.4 Inventory verification tests will be conducted on a semiannual basis. These tests require the temporary suspension of individual storage field activities (injections and withdrawals) for a period of approximately two weeks. If conditions will not permit the full maximum daily injection or withdrawal quantity, Texas Gas may temporarily adjust the limit and allow makeup quantities on succeeding days. Texas Gas will provide at least 45 days prior notice in regard to the scheduling of these shut-in periods. 10.5 During the Summer Season, Texas Gas will also withdraw gas from storage on a best efforts basis as part of the NNS service. Although such withdrawals will be done on a best efforts basis, Texas Gas will be presumed, unless it gives notice to the contrary, to be able to withdraw from storage such quantities of gas as to take into account routine variations in no-notice services. If Texas Gas is unable to make such best efforts withdrawals, it will advise Customer by posting on its electronic bulletin board. However, no presumption will exist for nonroutine situations (e.g. withdrawals in excess of 10% of Customer's Winter Contact Demand or sustained withdrawals of more than five days) and Customer must give 24 hours advance written notice to Texas Gas of quantities it desires to withdraw from storage, so that Texas Gas can determine the extent to which it can make such withdrawals and adjust its operations accordingly. 10.6 To assist Texas Gas's operational and maintenance scheduling through the Summer Season, Customer will notify Texas Gas by March 15 of each year, with updates monthly, of the quantities it intends to inject monthly during the immediately upcoming Summer Season; such injection schedule provided by Customer is a best efforts estimate and may be revised as necessary. Texas Gas will use its reasonable efforts to coordinate its test, maintenance, alteration and repair activities during such Summer Season to accommodate Customer's request. ARTICLE XI. MISCELLANEOUS 11. 1 Texas Gas's Transportation Service hereunder shall be subject to receipt of all requisite regulatory authorizations from the Commission, or any successor regulatory authority, and any other necessary governmental authorizations, in a manner and form acceptable to Texas Gas. The parties agree to furnish each other with any and all information necessary to comply with any laws, orders, rules, or regulations. 11.2 Except as may be otherwise provided, any notice, request, demand, statement, or bill provided for in this Agreement or any notice which a party may desire to give the other shall be in writing and mailed by regular mail, or by postpaid registered mail, effective as of the postmark date, to the post office address of the party intended to receive the same, as the case may be, or by facsimile transmission, as follows: 7 Texas Gas Texas Gas Transmission Corporation 3800 Frederica Street Post Office Box 20008 Owensboro, Kentucky 42304 Attention: Gas Revenue Accounting (Billings and Statements) Marketing Administration (Other Matters) Gas Transportation and Capacity Allocation (Nominations) Fax (502) 688-6817 Customer Mississippi Valley Gas Company 711 West Capitol Street Jackson, Mississippi 39203 Attention: Ms. Sheri W. Rowe The address of either party may, from time to time, be changed by a party mailing, by certified or registered mail, appropriate notice thereof to the other party. Furthermore, if applicable, certain notices shall be considered duly delivered when posted to Texas Gas's Electronic Bulletin Board, as specified in Texas Gas's Tariff. 11.3 Customer shall have fifteen (15) days from the date of receipt of this Agreement in which to execute such Agreement or Customer's request may be deemed null and void. 11.4 This Agreement shall be governed by the laws of the State of Kentucky. 11.5 Each party agrees to file timely all statements, notices, and petitions required under the Commission's Regulations or any other applicable rules or regulations of any governmental authority having jurisdiction hereunder and to exercise due diligence to obtain all necessary governmental approvals required for the implementation of this Transportation Agreement. 11.6 All terms and conditions of Rate Schedule NNS and the attached Exhibits A, A-I, B, and C are hereby incorporated to and made a part of this Agreement. 11.7 This contract shall be binding upon and inure to the benefit of the successors, assigns, and legal representatives of the parties hereto. 11.8 Neither party hereto shall assign this Agreement or any of its rights or obligations hereunder without the consent in writing of the other party and subject to the requirements of Section 25.7 of the General Terms and Conditions of Texas Gas's tariff. Notwithstanding the foregoing, either party may assign its right, title and interest in, to and by virtue of this Agreement including any and all extensions, renewals, amendments, and supplements thereto, to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities, without such trustee or trustees assuming or becoming in any respect obligated to perform any of the obligations of the assignor and, if any such trustee be a corporation, without its being required by the parties hereto to qualify to do business in the state in which the performance of this Agreement may occur, nothing contained herein shall require consent to transfer this Agreement by virtue of merger or consolidation of a party hereto or a sale of all or substantially all of the assets of a party hereto, or any other corporate reorganization of a party hereto. 11.9 This Agreement insofar as it is affected thereby, is subject to all valid rules, regulations, and orders of all governmental authorities having jurisdiction. 8 11.10 No waiver by either party of any one or more defaults by the other in the performance of any provisions hereunder shall operate or be construed as a waiver of any future default or defaults whether of a like or a different character. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective representatives thereunto duly authorized, on the day and year first above written. ATTEST: TEXAS GAS TRANSMISSION CORPORATION /s/ SHERRY L. RICE By /s/ (ILLEGIBLE) - ---------------------------- ----------------------------------------- Asst. Secretary Vice President WITNESSES: MISSISSIPPI VALLEY GAS COMPANY By /s/ (ILLEGIBLE) - ---------------------------- ----------------------------------------- Attest /s/ (ILLEGIBLE) - ---------------------------- ------------------------------------- _____ Secretary Date of Execution by Customer: 30 Oct 97 - ---------------------------- 9 CONTRACT NO. N000120 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY FIRM NO-NOTICE TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE NO. NAME WINTER SUMMER - ------- ------- ---- ----- ---- ------ ------ BEGIN LIST OF FIRM RECEIPT POINTS NORTH LOUISIANA LEG Carthage - Haughton 1 2102 Champlin 0 2,500 Sharon - East 1 8760N Lonewa (NLA) 0 0 EAST LEG Bosco - Eunice SL 2740 Superior-Pure 0 0 SOUTHEAST LEG B1k. 8 - Morgan City SL 2460 Peltex Deep Saline #1 0 0 SL 2463 Toce Oil 0 0 SL 2638 Coon Point 0 0 SL 2755 Texaco-Bay Junop 0 0 Henry - Lafayette SL 2790 Henry Hub 6,782 4,282 Morgan City - Lafayette SL 2454 FMP/Bayou Postillion 0 0 SL 9173 ANR-Calumet (Rec.) 0 0 SOUTH LEG Egan - Eunice SL 9003 Egan 0 0 SOUTHWEST LEG Lowry - Eunice SL 2437 ENOGEX/NGPL Tap Washita 0 0 SL 9170 Transok/NGPL Inter #2 Custer 0 0 SL 9843 Mobil - Lowry 0 0 WEST LEG Mallard Bay - Woodlawn SL 2207 Franks Petroleum-Chalkley 0 0 MAINLINE Bastrop - North 1 1631 MVG Allocation Point 5,000 5,000
EFFECTIVE DATE: July 1, 2000 CONTRACT NO. N000120 EXHIBIT A FIRM POINT(S) OF RECEIPT MISSISSIPPI VALLEY GAS COMPANY FIRM NO-NOTICE TRANSPORTATION AGREEMENT
DAILY FIRM METER CAPACITY (MMBtu) LATERAL SEGMENT ZONE NO. NAME WINTER SUMMER - ------- ------- ---- ----- ---- ------ ------ WC-294 (at ANR-Eunice) Included under Mainline HIOS (at ANR-Eunice) Included under Mainline End List of Firm Receipt Points.
Note: 199 MMBtu/D at Henry (Meter No. 2790) available to Duck Hill (N015853), until 10/30/2002. EFFECTIVE DATE: July 1, 2000 EXHIBIT "A-I" SECONDARY POINT(S) OF RECEIPT
TGT METER LATERAL SEGMENT ZONE NO. DRN SUPPLY POINT - ------- ------- ---- ----- --- ------------ NORTH LOUISIANA Carthage-Haughton 1 2102 152451 Champlin 1 9805 43336 Delhi 1 9051 7148 Grigsby 1 8116 42473 Texas Eastern-Sligo 1 9884 49099 Valero-Carthage Haughton-Sharon 1 8003 43390 Barksdale 1 2455 38387 Beacon 1 9866 44088 Cornerstone-Ada 1 2340 7787 F.E. Hargraves-Minden 1 2186 7790 LGI#1 1 2456 7046 McCormick 1 2457 7788 Minden-Hunt 1 2459 11259 Minden Pan-Am #1 1 9819 43554 Nelson-Sibley 1 9461 43555 Olin-McGoldrick 1 2760 38250 Sligo Plant 1 9834 49082 Texaco-Athens Sharon 1 2145 38281 Claiborne 1 9439 185980 Energy Management-Antioch 1 2010 7795 Fina Oil-HICO 1 9818 7739 PGC-Bodcaw 1 2757 7792 Texas Eastern-Sharon Sharon-East 1 9418 171295 Associated-Calhoun 1 2631 38310 Calhoun Plant 1 2632 38300 Dubach 1 2202 144066 Ergon-Monroe 1 8760 9334 Lonewa 1 8020 9217 MRT-Bastrop 1 9302 9335 Munce 1 9812 43556 Par Minerals/Downsville 1 9823 43559 Reliance-Bernice 1 2612 10799 Reliance-West Monroe 1 2634 9339 Southwest-Guthrie EAST Bosco-Eunice SL 2015 6512 Amerada Hess SL 2016 6513 Amerada Hess-South Lewisburg SL 2385 6517 D.B. McClinton #1 SL 2288 6508 Great Southern-Mowata #2 SL 9804 6545 Great Southern-Mowata #3 SL 8142 6549 Ritchie SL 2740 6499 Superior-Pure
A-I-1
TGT METER LATERAL SEGMENT ZONE NO. DRN SUPPLY POINT - ------- ------- ---- ----- --- ------------ SOUTHEAST Blk. 8-Morgan City SL 2198 10590 Bois D'Arc SL 9142 140570 Bois D'Arc-Pelican Lake SL 2109 31917 Chevron-Block 8 SL 2638 31567 Coon Point SL 2845 10533 Lake Pagie SL 2460 43557 Peltex Deep Saline #1 SL 2480 31554 S.S. 41 SL 9471 43569 Sohio SL 2755 10587 Texaco-Bay Junop SL 9836 10595 Texaco-Dog Lake SL 2463 43572 Toce Oil SL 9883 10591 Zeit-Lake Pagie Henry-Lafayette SL 3190 10902 Faustina-Henry SL 2790 42612 Henry Hub Lafayette-Eunice SL 2125 8741 California Co.-North Duson SL 2138 6500 California Co.-South Bosco #2 SL 2339 8737 Duson SL 9837 43488 Excel-Judice SL 2601 8732 Fina Oil-Anslem Coulee SL 8040 6525 Florida SL 2290 6544 Gulf Transport-Church Pt. SL 9906 38741 Quintana-South Bosco SL 9005 6538 Rayne-Columbia Gulf SL 3067 8736 South Scott SL 2810 8738 Tidewater-North Duson SL 8051 8727 Youngsville Maurice-Freshwater SL 9501 204880 Araxas-Abbeville SL 2147 10898 CNG-Hell Hole Bayou SL 2203 10890 Deck Oil-Perry/Hope SL 9160 140571 LLOG-Abbeville SL 2394 10906 LRC-Theall SL 9800 43550 May Petroleum SL 2748 127418 Parc Perdue SL 2749 10896 Parc Perdue 2 SL 9830 43558 R&R Res-Abbeville SL 9434 171296 Southwestern-Perry SL 2706 40933 Sun Ray SL 9422 160243 UNOCAL-Freshwater Bayou SL 2840 10900 UNOCAL-N. Freshwater Bayou Morgan City-Lafayette SL 2064 43425 Amoco-Charenton SL 9173 10277 ANR-Calumet (Rec.) SL 9803 38341 Atlantic SL 9809 43733 B.H. Petroleum-S.E. Avery SL 9881 80583 Bridgeline-Berwick SL 2085 10270 British American-Ramos SL 9412 185979 Equitable-Lake Peigneur SL 9047 8223 Florida Gas-E.B. Pigeon SL 2454 8215 FMP/Bayou Postillion
A-I-2
TGT METER LATERAL SEGMENT ZONE NO. DRN SUPPLY POINT - ------- ------- ---- ----- --- ------------ SOUTHEAST (CONT.) SL 8059 10279 Franklin SL 9437 171297 Hunt Oil-Taylor Point SL 9502 211243 Hunt Oil-East Taylor Point SL 9854 43546 Linder Oil-Bayou Penchant SL 9853 60164 Linder Oil-Garden City SL 2189 43561 Rutledge Deas SL 2636 8240 Shell-Bayou Pigeon SL 8149 8235 SONAT-East Bayou Pigeon SL 2035 10264 Southwest-Jeanerette SL 9895 59632 Texaco-Bayou Sale SL 8205 10272 Transco-Myette Point SL 9829 10263 Trunkline-Centerville Thibodaux-Morgan City SL 2250 33435 A. Glassell-Chacahoula SL 2335 186009 Amoco-North Rousseau SL 2835 6912 Lake Palourde SL 9873 8875 Linder Oil-Chacahoula SL 9175 124990 LLOG-Chacahoula SL 9847 43636 LRC-Choctaw SL 2440 8877 Magna-Chacahoula #1 SL 2445 8878 Magna-St. John #2 SL 2470 60191 Patterson-Chacahoula SL 2135 10145 Simon Pass SL 9431 144064 Transco-Thibodaux SOUTH Egan-Eunice SL 9003 38233 Egan SL 9415 171298 Tejas Power-Egan SOUTHWEST East Cameron-Lowry SL 2581 30074 E.C. 14 SL 2033 43548 Little Cheniere-Arco SL 2034 43549 Little Cheniere-Linder SL 2392 7561 LRC-Grand Cheniere Lowry-Eunice SL 9843 156905 Mobil-Lowry SL 9446 7530 NGPL-Lowry SL 2437 149325 ENOGEX/NGPL Tap Washita SL 9169 149326 TEX SW/NGPL Washita SL 9171 149313 Transok/NGPL Inter #2 Beckham SL 9170 149321 Transok/NGPL Inter #2 Custer SL 9172 149329 Transok/NGPL Waggs Wheeler WEST Iowa-Eunice SL 9507 21777 Camex-China SL 8170 8613 Iowa SL 9445 8617 Kilroy Riseden-Woodlawn Mallard Bay-Woodlawn SL 2140 8610 California Co.-South Thornwell SL 2615 7585 Caroline Hunt Sands-S. Thornwell SL 2207 60169 Franks Petroleum-Chalkley SL 9028 43506 Gas Energy Development-Hayes SL 2355 81054 Humble-Chalkley SL 2383 7567 IMC Wintershall-Chalkley
A-I-3
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------- ------- ---- ----- --- ------------ WEST (CONT.) SL 8071 7571 LRC-Mallard Bay SL 9828 8585 Riverside-Lake Arthur SL 2635 107453 Shell-Chalkley SL 2822 7586 Superior-S. Thornwell SL 2885 8603 Union Texas-Welsh W.C. 294 Entering at ANR- SL 9026 29497 W.C. 167/132 Eunice SL 9136 55151 W.C. 167/Near Shore SL 9440 186036 W.C. 293/306A SL 9396 60204 W.C. 293/H.I. 120/H.I. 120-128 SL 9383 43734 W.C. 293/H.I. 167/H.I. 167-166 SL 2838 29693 W.C. 294 HIOS Offshore Points H.I. 247 entering at ANR-Eunice SL 2868 33213 H.I. A-247/A-244A/A-231 SL 9176 154807 H.I. A-247/A-245 SL 9135 41343 W.C. 167/HIOS Mainline H.I. 283 SL 9894 49103 H.I. A-283/A-283A SL 9487 197839 H.I. A-283/A-443 SL 2855 33296 H.I. A-285/A-282 H.I. 303 SL 2858 43524 H.I. A-302A/A-303 H.I. 323 SL 9468 21334 H.I. A-323 H.I. 343 SL 9467 21339 H.I. A-343/A-355 H.I. A-345 SL 2863 33293 H.I. A-334A/A-335 SL 9327 43529 H.I. A-345/A-325A H.I. A-498 SL 2529 197837 H.I. A-498/A-451 SL 2536 197838 H.I. A-498/A-462/Various SL 2534 60171 H.I. A-498/A-489 SL 2533 60173 H.I. A-498/A-489/A-474 SL 2535 60174 H.I. A-498/A-489/A-499 SL 9371 60175 H.I. A-498/A-490 SL 2856 43723 H.I. A-498/A-517 H.I. A-539 SL 2537 60177 H.I. A-539/A-480 SL 9365 60178 H.I. A-539/A-511 SL 9508 216653 H.I. A-539/A-528 SL 9376 54856 H.I. A-539/A-532 SL 9328 60179 H.I. A-539/A-550
A-I-4
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------- ------- ---- ----- --- ------------ HIOS (CONT.) SL 9901 81051 H.I. A-539/A-552/A-551 SL 9889 49104 H.I. A-539/A-552/A-553 SL 2539 60181 H.I. A-539/A-567 SL 9380 60182 H.I. A-539/A-568 H.I. 546 SL 9466 21336 H.I. A-546/A-548/A-545 H.I. A-555 SL 2857 36875 H.I. A-531A SL 2861 43122 H.I. A-536C SL 2862 43123 H.I. A-537B SL 9127 54854 H.I. A-537B/A-537D/A-556 SL 9308 60183 H.I. A-555 SL 9125 54858 H.I. A-555/A-537D/A-556 SL 9887 49105 H.I. A-555/A-557A/A-556 H.I. A-573 SL 9909 60369 H.I. A-573/A-384/G B 224 SL 2859 43531 H.I. A-573B Complex SL 2542 43721 H.I. A-595CF Complex H.I. A-582 SL 9165 111967 H.I. A-582/A-561A SL 9469 221329 H.I. A-582/A-563/A-564 SL 9470 221328 H.I. A-582/A-582C SL 9133 49106 H.I. A-582/E.B. 110 SL 9377 49107 H.I. A-582/E.B. 160/Various SL 9134 81052 H.I. A-582/E.B. 165 MAINLLNE Bastrop-North 3 8082 6463 ANR-Slaughters 3 2061 4308 Bee-Hunter 3 2072 6385 Blair 4 1229 108797 Cincinnati Gas and Electric Co. 3 1367 132995 Citizens Gas & Coke Utility 2 8124 41187 Dyersburg 1 9871 132993 Entergy-Helena 3 9459 186011 Gibbs-Henderson 3 9432 186010 Har-Ken/Austin Jennings #1 3 9530 6461 Har-Ken/Murray 1 9303 1484 Helena #2 3 1440 108798 Indiana Gas Company, Inc. 4 1433 140534 Indiana Utilities Corporation 4 9522 223429 Indiana Utilities-New Albany Shale 4 1489 132837 Lawrenceburg Gas Company 4 1715 16281 Lebanon-Columbia 4 1247 16283 Lebanon-Congas 4 1859 16284 Lebanon-Texas Eastern 3 9527 44100 Liberty-South Hill 1 1600 132977 Memphis Light, Gas and Water Division 3 8073 6134 Midwestern-Whitesville 1 3801 134577 Pooling Receipt-Zone 1
A-I-5
TGT Meter Lateral Segment Zone No. DRN Supply Point - ------- ------- ---- ----- --- ------------ MAINLINE (CONT.) 3 9525 6447 Pride Energy No. 1 3 9141 107451 Reynolds-Narge Creek 3 5800 128355 Slaughters-Storage Complex (Withdraw) 3 1810 132845 Southern Indiana Gas and Electric Co. 4 1872 125662 Union Light, Heat and Power Co. 3 9404 40221 United Cities-Barnsley 2 1885 132856 Western Kentucky Gas Company 3 1906 108800 Western Kentucky Gas Company 3 1912 21773 Western Kentucky Gas Company 4 1981 132852 Western Kentucky Gas Company Eunice-Zone SL/1 Line SL 9035 6519 ANR-Eunice SL 9084 105453 Bayou Pompey SL 8107 8120 Evangeline SL 9536 225010 Louisiana Chalk-Eunice SL 8046 8121 Mamou SL 3800 124803 Pooling Receipt-Zone SL SL 3900 154805 SL Lateral Terminus Zone SL/1 Line-Bastrop 1 2020 44085 Arkla-Perryville 1 9870 44087 Channel Explo.-Chicksaw Creek 1 9826 9332 Delhi-Ewing 1 9882 60205 Entergy-Andrus Plant 1 9785 12088 Entergy-Delta Plant 1 2361 9321 Guffey-Millhaven 1 9814 43538 Hogan-Davis Lake 1 8063 9670 Pineville (LIG) 1 2648 9214 Spears 1 9832 43414 Wintershall-Clarks
A-I-6 CONTRACT NO. N0120 Winter Contract Demand - 50,429 MMBtu/D Summer Contract Demand - 5,000 MMBtu/D EXHIBIT "B" POINT(S) OF DELIVERY ZONE I
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----- ----- -------------------- ---------- ------ ------ 1631 60206 Mississippi Valley Gas Company BENOIT - S12, T20N, R8W, Bolivar County, MS (1) 600 300 BOLIVAR DISTRICT - S4, T22N, R6W, Bolivar County, MS (1) 810 300 CLARKSDALE - S30, T27N, R3W, Coahoma County, MS (1) 560 250 CLARKSDALE AIR BASE - S16, T28N, R3W, Coahoma County, MS (1) 560 150 CLEVELAND - S10 T22N, R6W, Bolivar County, MS (1) 640 325 DESOTO DISTRICT - S23, T1S, R8W, DeSoto County, MS (1) 674 400 DUNCAN - S11, T25N, R5W, Bolivar County, MS (1) 840 150 FEDERAL COMPRESS - S9, T5S, R11W, Tunica County, MS (1) 486 200 GAY HILL - S29, T1S, R8W, DeSoto County, MS (1) 840 100 GREENBROOK - S24, T1S, R8W, DeSoto County, MS (1) 674 300 JONESTOWN - S4, T28N, R3W, Coahoma County, MS (1) 560 250 LAKE CORMORANT - S13, T25, R10W, DeSoto County, MS (1) 500 150 LAKE CORMORANT #2 - S31, T2S, R9W, DeSoto County, MS (1) 810 400 LULA - S25, T30N, R3W, Coahoma County, MS (1) 500 150 LYNCHBURG - S36, T1S, R9W, DeSoto County. MS (1) 840 100 LYON - S17, T27N, R3W, Coahoma County, MS (1) 640 325 MERIGOLD NO. 1 - S9, T23N, R5W, Bolivar County, MS (1) 640 150 MERIGOLD NO. 2 - S9, T23N, R5W, Bolivar County, MS (1) 640 250 MVG-GREENVILLE AIR BASE - S22, T19N, R8W Washington County, MS (1) 600 300 MVG-GREENVILLE #1 - S12, T18N, R8W, Washington County, MS (1) 640 300 MVG-GREENVILLE #3 - S24, T18N, R8W, Washington County, MS (1) 840 575 MVG-GREENVILLE #4 - S14, T17N, R9W, Washington County, MS (1) 672 250 MVG-HARDY SPRINGS - Grenada County, MS (1) NATIONAL PACKING - S14, T17N, R9W, (1) 672 150
B-1 NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE
Meter MAOP MDP* No. DRN Name and Description Facilities (psig) (psig) - ----- ----- -------------------- ---------- ------ ------ Washington County, MS NORTH TUNICA - S27, T4S, R11W, Tunica County, MS (1) 325 REFUGE PLANTING - S11, T18N, R8W, Washington County, MS (1) 672 150 ROBINSONVILLE - S18, T3S, R10W, Tunica County, MS (1) 486 325 RURAL-MS-MVG 50 SCOTT - S26, T20N, R8W, Bolivar County, MS (1) 600 150 SHELBY - S8, T24N, R5W, Bolivar County, MS (1) 840 150 TUNICA - S4, T5S, R11W, Tunica County, MS (1) 500 150 VINEY RIDGE ROAD - S10, T26N, R4W, Coahoma County, MS WALLS - S33, T1S, R9W, DeSoto County, MS (1) 417 150
B-2 NOTE: SEE ATTACHED STANDARD FACILITIES KEY FOR EXPLANATION OF FACILITIES. *MINIMUM DELIVERY PRESSURE ----------------------------- CONTRACT NO. N000120 ----------------------------- FIRM NO-NOTICE TRANSPORTATION AGREEMENT EXHIBIT C SUPPLY LATERAL CAPACITY MISSISSIPPI VALLEY GAS COMPANY
PREFERENTIAL RIGHTS MMBTU/D SUPPLY LATERAL WINTER SUMMER ------ ------ Zone 1 Supply Lateral(s) North Louisiana Leg: 0 2,500 ------ ------ Total Zone 1: 0 2,500 Zone SL Supply Lateral(s) East Leg: 0 0 Southeast Leg: 6,782 4,282 South Leg: 0 0 Southwest Leg: 0 0 West Leg: 0 0 WC-294 (at ANR-Eunice): 0 0 HIOS (at ANR-Eunice): 0 0 ------ ------ Total Zone SL: 6,782 4,282 ------ ------ Grand Total: 6,782 6,782 ====== ======
NOTE: QUANTITIES SHOWN INCLUDE 199 MMBTU/D ON THE SOUTHEAST LATERAL RELEASED TO DUCK HILL (N15853) UNTIL 10/30/2002. EFFECTIVE DATE: July 1, 2000 STANDARD FACILITIES KEY (1) Measurement facilities are owned, operated, and maintained by Texas Gas Transmission Corporation. (2) Measurement facilities are owned, operated, and maintained by ANR Pipeline Company. (3) Measurement facilities are owned, operated, and maintained by Arkansas Louisiana Gas Company. (4) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Kerr-McGee Corporation. (5) Measurement facilities are owned, operated, and maintained by Koch Gateway Pipeline Company. (6) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Delhi Gas Pipeline Corporation. (7) Measurement facilities are owned, operated, and maintained by Kerr-McGee Corporation. (8) Measurement facilities are owned, operated, and maintained by Louisiana Intrastate Gas Corporation. (9) Measurement facilities are owned, operated, and maintained by Trunkline Gas Company. (10) Measurement facilities are owned, operated, and maintained by Columbia Gulf Transmission Company. (11) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Columbia Gulf Transmission Company. (12) Measurement facilities are owned, operated, and maintained by Florida Gas Transmission Company. (13) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by ANR Pipeline Company. (14) Measurement facilities are owned by Champlin Petroleum Company and operated and maintained by ANR Pipeline Company. (15) Measurement facilities are owned by Transcontinental Gas Pipe Line Corporation and operated and maintained by ANR Pipeline Company. (16) Measurement facilities are jointly owned by others and operated and maintained by ANR Pipeline Company. (17) Measurement facilities are owned by Koch Gateway Pipeline Company and operated and maintained by ANR Pipeline Company. (18) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Texas Eastern Transmission Corporation. (19) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Natural Gas Pipeline Company of America. (20) Measurement facilities are owned by Louisiana Intrastate Gas Corporation and operated and maintained by Texas Gas Transmission Corporation. (21) Measurement facilities are owned, operated, and maintained by Texas Eastern Transmission Corporation. (22) Measurement facilities are owned by Kerr-McGee Corporation and operated and maintained by ANR Pipeline Company. (23) Measurement facilities are operated and maintained by ANR Pipeline Company. (24) Measurement facilities are owned, operated, and maintained by Transcontinental Gas Pipe Line Corporation. (25) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Tennessee Gas Pipeline Company. (26) Measurement facilities are owned, operated, and maintained by Northern Natural Gas Company. (27) Measurement facilities are owned and maintained by Faustina Pipeline Company and operated by Texas Gas Transmission Corporation. (28) Measurement facilities are owned by Samedan and operated and maintained by ANR Pipeline Company. (29) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by CNG Producing. (30) Measurement facilities are owned, operated, and maintained by Devon Energy Corporation. (31) Measurement facilities are owned by Total Minatome Corporation and operated and maintained by Texas Gas Transmission Corporation. (32) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Trunkline Gas Company. (33) Measurement facilities are owned by Linder Oil Company and operated and maintained by Texas Gas Transmission Corporation. (34) Measurement facilities are owned, operated, and maintained by Mississippi River Transmission Corporation. (35) Measurement facilities are owned, operated, and maintained by Texaco Inc. (36) Measurement facilities are owned by Texas Gas Transmission Corporation and operated and maintained by Louisiana Resources Company. (37) Measurement facilities are owned, operated, and maintained by Louisiana Resources Company. (38) Measurement facilities are owned by Oklahoma Gas Pipeline Company and operated and maintained by ANR Pipeline Company. (39) Measurement and interconnecting pipeline facilities are owned and maintained by Louisiana Resources Company. The measurement facilities are operated and flow controlled by Texas Gas Transmission Corporation. (40) Measurement facilities are owned by Hall-Houston and operated and maintained by ANR Pipeline Company. (41) Measurement facilities are owned, operated, and maintained as specified in Exhibit "B". (42) Measurement facilities are owned by Enron Corporation and operated and maintained by Texas Gas Transmission Corporation. (43) Measurement facilities are owned by United Cities Gas Company and operated and maintained by TXG Engineering, Inc. (44) Measurement facilities are owned, operated, and maintained by NorAm Gas Transmission Company. (45) Measurement facilities are owned by Falcon Seaboard Gas Company and operated and maintained by Texas Gas Transmission Corporation. (46) Measurement facilities are owned by ANR Pipeline Company and operated and maintained by High Island Offshore System. (47) Measurement facilities are owned by Forest Oil Corporation, et al., and operated and maintained by Tenneco Gas Transportation Company. (48) Measurement facilities are owned by PSI, Inc., and operated and maintained by ANR Pipeline Company. (49) Measurement facilities are owned, operated, and maintained by Tennessee Gas Pipeline Company. (50) Measurement facilities are owned, operated, and maintained by Colorado Interstate Gas Company. (51) Measurement facilities are owned by Producer's Gas Company and operated and maintained by Natural Gas Pipeline Company of America. (52) Measurement facilities are owned by Zapata Exploration and operated and maintained by ANR Pipeline Company. (53) Measurement facilities are jointly owned by Amoco, Mobil, and Union; operated and maintained by ANR Pipeline Company. (54) Measurement facilities are owned, operated, and maintained by VHC Gas Systems, L.P. (55) Measurement facilities are owned by Walter Oil and Gas and operated and maintained by Columbia Gulf Transmission Company. (56) Measurement facilities are operated and maintained by Natural Gas Pipeline Company of America. (57) Measurement facilities are operated and maintained by Texas Gas Transmission Corporation. (58) Measurement facilities are operated and maintained by Tennessee Gas Pipeline Company. (59) Measurement facilities are operated and maintained by Columbia Gulf Transmission Company. (60) Measurement facilities are owned, operated, and maintained by Midwestern Gas Transmission Company. (61) Measurement facilities are owned, operated, and maintained by Western Kentucky Gas Company. (62) Measurement facilities are owned by Egan Hub Partners, L. P., and operated and maintained by Texas Gas Transmission Corporation. (63) Measurement facilities are owned and maintained by Louisiana Chalk Gathering System and operated by Texas Gas Transmission Corporation. EX-10.13(H) 17 d10753exv10w13xhy.txt FIRM STANDBY GAS STORAGE CONTRACT EXHIBIT 10.13(h) HATTIESBURG-A 200,000 SUBSCRIBED IN PHASE I. FIRM STANDBY GAS STORAGE CONTRACT BY AND BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990 PART A* * This Contract for 200,000 MQS ("Part A") is issued, together with a second contract for 100,000 MQS ("Part B"), in replacement of the original Firm Standby Gas Storage Contract for 300,000 MQS dated February 21, 1990. TABLE OF CONTENTS
FIRM STANDBY GAS STORAGE CONTRACT I. ACQUISITION AND CONSTRUCTION .................................................................. 2 II. GAS TO BE STORED AND DELIVERED.................................................................. 4 III. SCHEDULING...................................................................................... 6 IV. POINT(S) OF DELIVERY AND REDELIVERY ............................................................ 8 V. TERM............................................................................................ 8 VI. RATES........................................................................................... 9 VII. NOTICES......................................................................................... 13 VIII. GENERAL TERMS AND CONDITIONS.................................................................... 15 IX. ADDITIONAL STORAGE OPTION....................................................................... 15 X. MISCELLANEOUS................................................................................... 16 Exhibit "A" General Terms and Conditions I. DEFINITIONS..................................................................................... 1 II. QUALITY......................................................................................... 3 III. PRESSURE ....................................................................................... 4 IV. TITLE AND RISK OF LOSS.......................................................................... 4 V. MEASUREMENT..................................................................................... 6 VI. BILLINGS AND PAYMENTS........................................................................... 9 VII. TAXES.......................................................................................... 10 VIII. REGULATORY BODIES............................................................................... 13 IX. FORCE MAJEURE................................................................................... 14 X. DEFAULT AND TERMINATION......................................................................... 16 Exhibit "B" Point(s) of Delivery and Redelivery
GAS STORAGE CONTRACT THIS GAS STORAGE CONTRACT (hereinafter referred to as the "Contract") is made effective as of the 21st day of February, 1990, by and between HATTIESBURG INDUSTRIAL GAS SALES COMPANY, a Delaware corporation, (f/k/a Endevco Industrial Gas Sales Company) (herein referred to as "Company"), operator of the Storage Facilities (as defined below) and managing general partner of the Hattiesburg Gas Storage Company, the owner of the said Storage Facilities, and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). W I T N E S S E T H: WHEREAS, Company and Customer are parties to a "Precedent Agreement" dated October 13, 1989, wherein Company and Customer agreed, upon the satisfaction of certain conditions, to enter into this Contract; and WHEREAS, the conditions in the Precedent Agreement have been satisfied or waived; and WHEREAS, subject to the terms hereof, Company will acquire certain caverns located near Petal, Mississippi and develop such caverns into underground natural gas storage facilities (hereinafter referred to as the "Storage Facilities") initially having a usable storage capacity of approximately two billion cubic feet ("Phase I"), and which may, at Company's discretion, subsequently be expanded to a capacity of approximately five billion cubic feet of usable storage capacity ("Phase II"); and WHEREAS, Company will install and construct all facilities necessary to connect the Storage Facilities with the Point(s) of Delivery and Point(s) of Redelivery herein specified; and WHEREAS, Customer desires that Company receive, on a firm basis, at the Points of Delivery herein specified, certain quantities of gas from the pipeline facilities of Transcontinental Gas Pipe Line Corporation ("Transco") and/or Tennessee Gas Pipeline Company ("Tennessee") for the purpose of injecting and storing such gas for Customer or for its account in such Storage Facilities, and that Company redeliver such gas, on a firm basis, into the facilities of said pipeline companies, at the Points of Redelivery herein specified; and WHEREAS, Company desires to perform such services for Customer, all to be provided pursuant and subject to the terms and conditions hereof; NOW, THEREFORE, for and in consideration of the mutual covenants herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed by both parties hereto, Company and Customer hereby agree as follows: ARTICLE I ACQUISITION AND CONSTRUCTION Within thirty (30) days after the execution hereof, Company shall endeavor to close its purchase of the Storage Facilities, on terms and conditions satisfactory to Company. Thereafter, Company shall commence the construction and development of the Storage Facilities and shall provide Customer written notice of the 2 commencement of construction and the date upon which Company anticipates that such facilities will be operational. Upon completion of construction, including testing, as required by all applicable federal, state and/or applicable codes, and all other matters required for operation, Company shall provide Customer written notice that said facilities are fully operational and shall state in such notice a date upon which Company will be ready to receive gas for storage, which date shall be not less than thirty (30) days following such notice (such date to be hereinafter referred to as the "Commencement Date"). If the Commencement Date does not occur on or before December 1, 1990, or such later date as may be agreed upon, (subject to a day for day extension for delays caused by an event(s) of "force majeure" as herein defined and for each day after March 8, 1990 which expires prior to the date that Company receives executed Firm Storage Contracts covering at least 165,000 MMBtu of MDWQ, as herein defined), for any reason, including, without limitation, Company's inability to close its purchase of the Storage Facilities on terms acceptable to Company, then either party shall have the right to terminate this Contract, without further liability or obligation to the other party hereunder, by providing the other party thirty (30) days prior written notice. Notwithstanding the foregoing, in the event that Customer gives notice of termination in accordance with the above and, thereafter, Company provides written notice to Customer stating a Commencement Date which will occur prior to the expiration of such thirty (30) day period, then, Customer's notice of termination shall be void and of no further force or effect and 3 this Contract shall continue in accordance with its terms, unless Company is unable to commence service on the Commencement Date stated in its notice. ARTICLE II GAS TO BE STORED AND DELIVERED 2.1 Subject to the terms and provisions of this Contract, Company agrees to reserve for service to Customer a portion of the Storage Facilities. The capacities so reserved for Customer shall be sufficient to enable Customer to inject gas into, withdraw gas from, and store gas in the Storage Facilities, in quantities up to the maximum quantities set forth below: (i) a maximum daily withdrawal quantity ("MDWQ") of 20,000 MMBtu per day; (ii) a maximum daily injection quantity ("MDIQ") of 10,000 MMBtu per day; (iii) a maximum capacity in the Storage Facilities ("MQS") equal to 200,000 MMBtu. 2.2 Customer shall tender or cause to be tendered to Company at the Point(s) of Delivery any gas which Customer desires to have injected into storage hereunder. Customer shall also receive or cause to be received gas requested to be withdrawn from storage at the Point(s) of Redelivery upon tender for redelivery by Company. 2.3 Subject to the operating conditions of the pipelines delivering or receiving gas for Customer's account, Company shall receive gas for injection from Customer at the Point(s) of Delivery and redeliver gas to Customer at the Point(s) of Redelivery as scheduled by Customer from time to time; provided that Company 4 shall not be obligated to receive for injection any quantity of gas if the injection of the same would cause the quantity of gas stored in the Storage Facilities for Customer's account ("Customer's Gas Storage Inventory") to exceed Customer's MQS as stated above; nor shall Company be obligated at any time to deliver more gas to Customer than Customer has in its then-current Customer's Gas Storage Inventory. 2.4 Company shall not be obligated to receive, at any Point of Delivery for injection, or to redeliver, at any Point of Redelivery, any quantity of gas when the quantity of gas tendered for delivery to Company or requested by Customer to be redelivered, together with all other volumes of gas tendered for delivery to Company at any such Point of Delivery, or requested for redelivery at such Point of Redelivery, is less than 5,000 MMBtu per day in the aggregate. 2.5 In addition to the maximum daily rates of injection and withdrawal as specified above in Section 2.1, Company shall use its best efforts to accommodate requests of Customer to inject or withdraw gas at greater rates of flow and, at such Point(s) of Delivery or Point(s) or Redelivery in addition to those specified on Exhibit "B" annexed hereto, at such times as such additional capacities are not required for service to other firm, standby storage customers. Any such additional services shall be provided at the rates stated in Section 6.1(c) and 6.1(d), as may be amended by Section 6.1(e), only as capacities are available and on a prorata basis to other firm, standby storage customers, without obligation or liability for interruption by Company as to any 5 withdrawals or injections in excess of the maximums reserved for Customer. Additional withdrawals and/or injections will be made only to the extent that Customer has gas in storage to be withdrawn, or unfilled capacity in the Storage Facilities reserved as part of Customer's MQS as stated herein. ARTICLE III SCHEDULING 3.1 At any time during any day when Customer desires Company to receive and inject gas into, or to withdraw and deliver gas from, the Storage Facilities, Customer shall give verbal notice in accordance with Section 3.2 of this Article to Company's dispatcher, specifying the quantity of gas to be injected or withdrawn and the appropriate Points of Delivery or Points of Redelivery, as applicable. Customer shall make available and tender any gas to be injected hereunder and receive and accept delivery, upon tender by Company, any gas requested to be withdrawn from storage. The quantity of gas stored in the Storage Facilities for the account of Customer shall be increased or decreased upon injection or withdrawal of gas from storage, as applicable. Customer shall not (unless otherwise agreed by Company), on an hourly basis, tender for injection nor shall Company be obligated to receive gas for injection or to withdraw and deliver gas from storage, at rates of flow in excess of 1/24 of Customer's MDIQ or MDWQ, respectively. 3.2 Customer shall notify Company at least eight (8) hours in advance of any requested change in the daily or hourly rate of flow for injections or withdrawals of gas hereunder. Company may waive 6 any part of the eight (8) hour notice upon request if, in Company's reasonable judgement, operating conditions permit such waiver. Customer shall notify Company immediately of any circumstance which causes or will cause the deliveries to or receipts from Company to be different from those requested. Notices provided in this Article may be verbal, followed by a written confirmation delivered via telecopy, overnight mail, first class U.S. mail, or hand-delivery when such written confirmation is requested by either party. Customer shall provide notice of any changes in deliveries to or receipts from Company to all applicable transporting pipelines and shall be responsible for, and shall indemnify and hold Company harmless from, any and all liabilities and expenses resulting from Customer's failure to notify all applicable transporting pipelines of any such changes. 3.3 In the event that an imbalance occurs on the pipeline to or from which such gas is delivered or received, which imbalance results from Company's failure to tender the quantities of gas scheduled for delivery from storage, or accept delivery of the quantities of gas scheduled for injection into storage and tendered for delivery by Customer, all in accordance with and subject to this Contract, Company shall reimburse Customer for any imbalance penalty due and rightfully owing to the pipeline receiving or delivering the gas at such Point(s) of Delivery or Point(s) of Redelivery, which was caused by Company's failure to accept or deliver gas. In the event that Company is unable to receive or deliver gas as required by this Contract and in accordance with the request of Customer as provided above, Company shall notify 7 Customer as soon as practicable following any failure to receive or tender such gas and, Customer shall, as soon as practicable following receipt of such notice, notify and change nominations and scheduling with all pipelines and other parties delivering or receiving gas to be delivered to or withdrawn from storage for Customer and be reasonably diligent in taking such further actions to prevent or minimize any imbalances from occurring. Customer and Company will diligently work to correct any imbalance so caused prior to the end of the applicable balancing period. ARTICLE IV POINT(S) OF DELIVERY AND REDELIVERY 4.1 The Point(s) of Delivery for all gas to be tendered by Customer to Company for injection into the Storage Facilities shall be as specified on Exhibit "B" attached hereto, and the maximum daily quantity of gas which Company is obligated to receive from Customer at each individual Point of Delivery shall not exceed the maximum stated thereon. 4.2 The Point(s) of Redelivery for all gas to be tendered by Company to Customer for redelivery pursuant to the terms hereof shall be as specified on Exhibit "B", attached hereto, and the maximum quantities of gas which Company is obligated to redeliver to Customer at each such Point of Redelivery shall not exceed the maximum stated thereon. ARTICLE V TERM 5.1 This Contract shall be effective as of the date set forth at the outset hereof and shall continue in full force and effect 8 for a primary term of fifteen (15) years following the Commencement Date, as defined in Article I hereof, and year to year thereafter unless and until terminated effective at the end of such fifteenth (15th) year or any year thereafter by either party upon not less than thirty-six (36) months prior written notice. 5.2 Upon expiration hereof, Company agrees that in the event that gas storage services are still being provided in the Storage Facilities by Company, or any assignee of Company as provided for herein, to other customers, then, Customer shall have the right and option to continue to receive storage services from Company, or such assignee of Company, pursuant to terms and conditions, and for rates and charges substantially similar to those being offered to said other customers by Company, or such assignee of Company, at the time of such expiration. ARTICLE VI RATES 6.1 During the first ten (10) years following the Commencement Date, Customer shall pay to Company each month the following charges: 6.1(a) A storage charge ("D(1)") of twenty and one-half cents ($0.205) multiplied by Customer's MQS amount specified in this Agreement; plus 6.1(b) A deliverability charge ("D(2)") of fifty-eight cents ($0.58) multiplied by Customer's MDWQ amount; plus 6.1(c) One cent ($0.01) for each MMBtu of gas received by Company for injection into storage hereunder and one cent 9 ($0.01) for each MMBtu of gas redelivered by Company to Customer hereunder; plus 6.1(d) Customer's pro-rata share of the cost of gas consumed in the operation of the Storage Facilities, such to be pro rated among all Customers based upon the quantities of gas injected and withdrawn by each Customer during each month. It is presently estimated that the total cost of gas to be consumed in the injection and withdrawal of gas into and from the Storage Facilities will initially total approximately three cents ($0.03) per MMBtu, in the aggregate; however, the parties agree that this cost may change from time to time and Customer shall continue to bear its pro rata share of such cost. Company shall endeavor to operate the Storage Facilities in an efficient manner so as to limit the gas consumed to that quantity reasonably required. Each month, Company shall provide Customer a statement showing its prorata share of such quantity and the cost of the gas consumed in the operation of Storage Facilities, along with the necessary supporting workpapers showing the total quantity and cost of gas so consumed and the proration calculations. Customer shall have the option, exercisable upon thirty (30) days prior written notice at any time during the term hereof, to thereafter (during the term hereof) supply its pro-rata share of gas consumed, as opposed to reimbursing Company in accordance herewith. In the event that Customer elects to provide its pro-rata share of the fuel used hereunder, then, following such election, Company shall establish and maintain 10 an account (the "Fuel Account") with Customer. Initially, one and one-half percent (1 1/2%) of all gas delivered to Company at the Points of Delivery hereunder shall be retained by Company and credited to the Fuel Account. Customer shall not pay any injection, withdrawal or storage fee as to any volumes retained by Company. At the close of each month, Company shall debit the Fuel Account with Customer's pro-rata share of the fuel gas. From time to time during the term hereof, Company shall have the right, upon providing Customer ten (10) days' prior written notice, to adjust the quantity of gas to be retained by Company and credited to the Fuel Account in order to reflect actual quantities of gas consumed in the operation of the Storage Facilities and, to cause the Fuel Account to be as near to zero as is practicable on a monthly basis. Within thirty (30) days following the termination hereof, Company shall deliver gas to Customer, or Customer shall deliver gas to Company, as is necessary to cause the Fuel Account to equal zero. Company shall report the status of the Fuel Account as of the end of the previous month with each monthly statement. Customer shall have the right to deliver to Company the maximum capacities set forth in Section 2.1(iii) in addition to the gas delivered by Customer for credit to the Fuel Account. 6.1(e) The fees payable for each MMBtu of gas delivered to Company for injection and for each MMBtu of gas redelivered to Customer hereunder, as provided for in section 6.1(c), shall be subject to adjustment, upon 11 application to and approval by the appropriate regulatory commission, to reflect increases or decreases in the cost of maintenance, supplies and other variable expenses incurred by Company in performing the services hereunder. Customer shall have the right to contest any increase sought hereunder before the appropriate regulatory commission. No such adjusted fee shall exceed, however: (i) the fee herein provided; multiplied by (ii) the sum of one (1) plus the percentage change in the Gross National Product Implicit Price Deflator (the "Index") for the December of the then-current calendar year as compared to such Index for December, 1990. 6.2 Notwithstanding the above, in the event that Company elects to expand the Storage Facilities as referenced in section 9.1, the rates and charges payable hereunder during the remaining portion of the initial ten (10) years hereof shall be redetermined such that the sum of: (a) the D(1) storage charge, as provided in section 6.1(a); and (b) the D(2) deliverability charge, as provided in section 6.1(b); will be reduced such that the total reservation charges payable hereunder during each month shall not exceed eighty percent (80%) of the total reservation charges payable hereunder prior to such expansion and rate redetermination. 6.3 The charges payable hereunder for the remainder of the term hereof following the tenth (10th) year (after the Commencement Date) may be redetermined by the appropriate regulatory body in accordance with this section 6.3. Company shall have the right, upon its election, or shall be obligated, upon request of Customer, to submit cost-of-service information to the appropriate regulatory 12 authority for a review of the rates charged hereunder and to request a determination by such regulatory authority of a rate for the remaining term hereof. Customer shall have the right to take part in such proceedings and to contest the proposed rates to the full extent allowed. Company shall provide Customer not less than thirty (30) days prior written notice of Company's intent to file for a new rate as herein provided. In the event that the rates resulting from such redetermination are in excess of one hundred and ten percent (110%) of the rates specified in Section 6.1, then Customer shall have the right to terminate this Contract upon sixty (60) days' prior written notice; provided, however, that during such sixty (60) day period following the receipt of Customer's notice, Company shall have the option, without obligation, to agree to charge Customer rates which do not exceed one hundred and ten percent (110%) of the rates set forth in Section 6.1 and, in such event, this Contract shall continue for the remaining term. Company shall provide Customer written notice of any such election before the expiration of said sixty (60) day period and, shall therein specify the rate to be charged hereunder. ARTICLE VII NOTICES 7.1 Whenever any notice, request, demand, statement or payment is required or permitted to be given under any provision of this Contract, unless expressly provided otherwise, such shall be in writing, signed by or on behalf of the person giving the same, and shall be deemed to have been given and received upon the 13 actual receipt (including the receipt of a telecopy or facsimile of such notice) at the address of the parties as follows: Company; For Notices: Hattiesburg Industrial Gas Sales Company 5950 Berkshire Lane Suite 1400, L.B. 17 Dallas, Texas 75225 Payments (Wire Transfer): Union Bank of California -- Los Angeles ABA # 122000496 For Account of Hattiesburg Gas Storage Company Acct No. 0880411845 Customer: Mississippi Valley Gas Company 711 W. Capital Street Jackson, Mississippi 39203 7.2 Operating communications made by telephone or other mutually agreeable means shall be confirmed in writing or by telecopy within two (2) days following same if requested by either party. To facilitate such operating communications on a daily basis, lists of names, telephone and telecopy numbers of appropriate operating personnel shall be exchanged by and between Company and Customer before commencement of service under this Contract. Such lists shall be updated from time to time if changed. 7.3 The addresses of the parties may be revised upon written notice given in accordance herewith, designating in such writing the new address of the party so affected. 14 ARTICLE VIII GENERAL TERMS AND CONDITIONS The General Terms and Conditions attached hereto as Exhibit "A" are hereby incorporated herein and made a part of this Contract as if fully set forth herein. Any conflict or inconsistency, either in construction or interpretation, between the terms hereof and the General Terms and Conditions attached hereto shall be resolved in favor of the terms hereof. ARTICLE IX ADDITIONAL STORAGE OPTION 9.1 Company anticipates that it may elect to expand the Storage Facilities at some time following initial storage operations. In the event that Company so elects to expand the Storage Facilities, Company hereby grants Customer an option on a pro rata portion of any increased capacities (for storage, withdrawal or injection) developed by Company in the Storage Facilities. Such proportionate share shall equal (i) the total additional capacity (for storage, withdrawal or injection) developed by Company in such Storage Facilities multiplied by (ii) a fraction, the numerator of which shall equal Customer's rights to such capacity hereunder (MQS, MDWQ or MDIQ) and the denominator of which shall equal the total storage capacity (for storage, withdrawal or injection) of the Storage Facilities immediately preceding such increase in capacity. Customer shall exercise its option, if at all, in accordance with section 9.2 below. 15 9.2 In the event that Company makes the determination to increase any capacity (for storage, withdrawal or injection) at the Storage Facilities, Company shall so notify Customer in writing. Such notice shall contain the terms and conditions upon which Company will contract with other parties for such capacity(ies), which terms shall be similar to those provided in this Contract. For ninety (90) days following receipt of such notice, Customer shall have the right, without obligation, to contract for additional storage rights in the Storage Facilities upon the terms and conditions offered by Company and reflected in the notice or such other terms as may be agreed to by Customer and Company. Should Customer elect to contract for such additional rights, and provide Company with written notice of such election within such ninety (90) day period, Company shall provide Customer with formal contracts for execution. The failure of Customer to provide written notice to Company of its election to contract for such additional capacity rights within such ninety (90) day period, or the failure of Customer, following such election, to execute and return to Company the contract provided to Customer within thirty (30) days following Customer's receipt of same, shall be deemed a waiver of Customer's option on such capacity(ies). ARTICLE X MISCELLANEOUS 10.1 Headings. The subject headings of the articles and sections of this Contract are intended for the sole purpose of convenient reference and are not intended, nor shall the same be 16 construed, to be a part of this Contract or considered in any interpretation hereof. 10.2 Amendment. Neither this Contract nor any provisions hereof may ever be amended, changed, modified or supplemented except by an agreement in writing, duly executed by the party to be charged with the same. 10.3 Waiver. No failure by either party to enforce the performance of any obligation of the other party under this Contract shall operate as a waiver of such obligation or default, or as a waiver of any other right or default, whether of a like or different character. 10.4 Choice of Law. As to all matters of construction and interpretation, this Contract shall be interpreted, construed and governed by the laws of the State of Texas. 10.5 Succession. Either party may assign its rights, titles or interests hereunder to any individual, bank, trustee, company or corporation as security for any note, notes, bonds or other obligations or securities of such assignor, but not otherwise, without the written consent of the other party hereto, which consent shall not be unreasonably withheld. No assignment provided for hereunder shall in any way operate to enlarge, alter or change any obligation of the other party hereto nor shall the assignee be relieved of its obligations hereunder without the express written consent of the non-assigning party. 10.6 Right of Examination. Both Company and Customer shall have the right to examine, at any reasonable time, the books, records, charts and any operating data of the other to the extent 17 reasonably necessary to verify the accuracy of any statement, chart or computation made under or pursuant to the provisions of this Contract. All books, records and charts related to any statement, charge or computation made hereunder shall be retained and available for review or inspection for a period of two years. 10.7 Entire Agreement. This Contract contains the entire agreement and understanding of the parties hereto and there are no agreements, understandings or representations, either oral or in writing, except as set forth herein. That certain Precedent Agreement, between Customer and Company, is hereby expressly superseded and terminated by the execution hereof. 10.8 Authority. Company and Customer each hereby represents and warrants that it has the full right, power and authority to enter into this Contract, and that this Contract will not violate the provisions of any other contract or agreement to which it is a party. 10.9 Reissuance of Original Contract. This Contract ("Part A"), and another Gas Storage Contract of even date herewith specifying a MQS of 100,000 ("Part B"), are issued in replacement of that certain Firm Standby Gas Storage Contract between Customer and Company dated February 21, 1990. The replacement of the former contract is effected for administrative purposes only, and shall be interpreted and construed for all purposes as merely a continuation of the original contract. IN WITNESS WHEREOF, the parties have executed this Contract in one or more copies or counterparts, each of which shall constitute 18 and be an original of this Contract effective between the parties effective as of the date first-above written. COMPANY: ATTEST: HATTIESBURG INDUSTRIAL GAS SALES COMPANY - -s- [ILLEGIBLE] By: -s- [ILLEGIBLE] - ---------------------------- -------------------------------------- Its: President ATTEST: CUSTOMER: MISSISSIPPI VALLEY GAS COMPANY - -s- [ILLEGIBLE] By: -s- WARREN K. ROGERS - ---------------------------- -------------------------------------- Its: Senior Vice President 19 EXHIBIT "A" TO GAS STORAGE CONTRACT BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990 GENERAL TERMS AND CONDITIONS These General Terms and Conditions ("General Terms") are attached to and incorporated into the above-referenced GAS STORAGE CONTRACT between HATTIESBURG INDUSTRIAL GAS SALES COMPANY (herein referred to as "Company") and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). ARTICLE I DEFINITIONS For the purposes of this Contract, unless expressly stated otherwise, the following definitions shall be applicable. 1.1 The term "Btu" shall mean British Thermal Units. 1.2 A "day" shall mean the twenty-four (24) hour period beginning at 7:00 a.m. Jackson, Mississippi time on each calendar day and ending at 7:00 a.m. Jackson, Mississippi time on the following calendar day. 1.3 "Contract" shall mean the above-referenced Gas Storage Contract together with these General Terms and all other attachments hereto or thereto. 1.4 The term "gas" shall mean natural gas in its natural state, produced from wells, including casinghead gas produced with crude oil, natural gas from gas wells and residue gas resulting from processing both casinghead gas and gas well gas. General Terms - Page 1 1.5 The term "Mcf" shall mean one thousand (1,000) cubic feet at a pressure of fifteen and twenty-five thousandths (15.025) psia and at a temperature of sixty degrees (60 degrees) Fahrenheit. 1.6 The term "MMBtu" shall mean 1,000,000 Btu. 1.7 A "month" shall mean that period of time beginning at 7:00 a.m. Jackson, Mississippi time on the first day of a calendar month and ending at 7:00 a.m. Jackson, Mississippi time on the first day of the following calendar month; provided, that, the first month hereunder shall commence on the first day of the calendar month in which the Commencement Date occurs, and the last month hereunder shall end on the date that this Contract terminates. 1.8 "Point(s) of Delivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is received by Company for injection into storage. 1.9 "Point(s) of Redelivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is tendered by Company to Customer for delivery from storage. 1.10 The term "psia" shall mean pounds per square inch absolute. 1.11 The term "psig" shall mean pounds per square inch gauge. 1.12 "Storage Facilities" shall be as defined in the "WHEREAS" clauses of the Contract. 1.13 The term "year" shall mean a period of twelve (12) consecutive months. General Terms - Page 2 ARTICLE II QUALITY The gas delivered by either party to the other hereunder shall meet the quality specifications of the transporting pipeline which receives or delivers such gas at the Point(s) of Delivery or Redelivery and shall, in addition, be of such quality that it shall meet the following specifications, if such standards are more stringent: a. Be commercially free of dust, gum, gum-forming constituents, gasoline, and other solid and/or liquid matter, including but not limited to water, gas treating chemicals and well completion fluids and debris, which may become separated from the gas during transportation thereof. b. Contain not more than one quarter (1/4) grain of hydrogen sulphide per one hundred (100) cubic feet, as determined by the cadmium sulfate quantitative test, nor more than nine (9) grains of total sulfur per one hundred (100) cubic feet. c. The gas delivered hereunder shall not contain more than two-tenths of one percent (0.2%) by volume of oxygen, and shall not contain more than two percent (2%) by volume of carbon dioxide; and shall not contain more than two percent (2%) by volume of nitrogen. d. Have a heating value of not less than nine hundred eighty (980) Btu's per cubic feet. General Terms - Page 3 e. Have a temperature of not more than one hundred twenty degrees Fahrenheit (120 degrees F), nor less than forty degrees Fahrenheit (40 degrees F). f. Have been dehydrated by any method other than the use of a calcium chloride as desiccant, for removal of entrained water in excess of seven (7) pounds of water per million (1,000,000) cubic feet of gas. ARTICLE III PRESSURE Company shall deliver gas to Customer from storage hereunder at pressures sufficient to enter the transporting pipeline's facilities at the Point(s) of Redelivery against the operating pressures maintained in such pipeline from time to time, provided that Company shall not be required to deliver gas at pressures in excess of 960 psig. Customer shall deliver gas to Company for injection at the Point(s) of Delivery at the pressures as may be available from time to time in the transporting pipeline's facilities at such points, but in no event shall such pressures be less than 550 psig or greater than Company's maximum allowable operating pressure. ARTICLE IV TITLE AND RISK OF LOSS 4.1 Title to the natural gas stored by Company and delivered to Customer hereunder shall, at all times, be in Customer and, except as provided in Section 4.2 Company makes no warranty of title whatsoever. Customer warrants for itself, its successors and General Terms - Page 4 assigns, that it will have at the time of delivery of gas storage hereunder good title or valid right to deliver such stored hereunder. Customer warrants for itself, its successors and assigns, that the gas it delivers hereunder shall be free and clear of all liens, encumbrances, or claims whatsoever; and that it shall indemnify Company and save it harmless from all claims, actions, damages, costs and expenses arising directly or indirectly from or with respect to the title to gas tendered to Company hereunder. 4.2 Company warrants that it shall neither cause nor allow any cloud or encumbrance of any nature to arise by, through or under Company with respect to Customer's title to any gas tendered to Company for storage, and agrees to redeliver such gas pursuant to this Contract free from all liens and adverse claims arising by, through or under Company, and that it will indemnify, defend, protect, and save Customer harmless from all claims, suits, actions, damages, costs and expenses arising directly or indirectly from the same. 4.3 As between Customer and Company: Customer shall be in control and possession of the gas prior to delivery to Company for injection at the Point(s) of Delivery and after redelivery by Company to Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Company harmless from any damage or injury caused thereby except for damages and injuries caused by the negligence of Company; and, Company shall be in control and possession of the gas after the receipt of the same for injection at the Point(s) of Delivery and until redelivery by Company to General Terms - Page 5 Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Customer harmless from any damage or injury caused thereby, except for damages and injuries caused by the negligence of Customer. The risk of loss for all gas injected into, stored in and withdrawn from the Storage Facilities shall be and remain with the party having control and possession of the gas as herein provided. ARTICLE V MEASUREMENT 5.1 The unit of volume for measurement of gas delivered hereunder shall be one (1) cubic foot of gas at a base temperature of sixty degrees Fahrenheit (60 degrees F) and at an absolute pressure of fifteen and twenty-five thousandths (15.025) pounds per square inch. All fundamental constants, observations, records, and procedures involved in determining and/or verifying the quantity and other characteristics of gas delivered hereunder shall, unless otherwise specified herein, be in accordance with the standards prescribed in American Gas Association ("A.G.A.") Gas Measurement Committee Report No. 3, as now and from time to time amended or supplemented. All measurements of gas shall be determined by calculation into terms of such unit. All quantities given herein, unless expressly stated otherwise, are in terms of such unit. Notwithstanding the foregoing, it is agreed that, for all purposes, the Btu content of the gas received and delivered by Company hereunder shall be measured on an "as delivered" basis rather than a fully saturated or "wet" basis. General Terms - Page 6 5.2 Company, at its sole expense, shall install, maintain and operate, or cause to be installed, maintained and operated, the measurement facilities required hereunder. Said measurement facilities shall be so equipped with orifice meters, recording gauges, or other types of meters of standard make and design commonly acceptable in the industry, as to accomplish the accurate measurement of gas delivered hereunder. The changing of charts, calibrating and adjustment of meters shall be done by Company or its agent. 5.3 The accuracy of Company's measuring equipment shall be verified by Company at least once in each thirty (30) day period. If either party desires a special test of any measuring equipment, it will promptly notify the other party and the parties shall then cooperate to secure a prompt verification of the accuracy of such equipment. The expenses of any such special test, if requested by Customer, shall be borne by Customer if the measuring equipment tested is found to be accurate within the limit of plus or minus two percent (2%) of error. For the purposes of measurement and meter calibration, the atmospheric pressure shall be assumed to be fourteen and seventy-three hundredths (14.73) pounds per square inch, irrespective of variations in natural atmospheric pressure from time to time. Company and Customer, upon request, shall have the right to be present at any test of any measuring equipment, including any check measuring equipment installed by Customer at its sole expense. General Terms - Page 7 5.4 If upon testing, the metering equipment is found to be inaccurate, in the aggregate, by two percent (2%) or more, either plus or minus, registration thereof and any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half (1/2) of the time elapsed since the day of the last calibration, not exceeding, however, forty-five (45) days. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately; however, if any inaccuracy is less than two percent (2%), all prior readings and measurements shall be deemed to be accurate and no adjustments to any prior reading shall be made. If, for any reason, any meter is registering inaccurately or is out of service or out of repair so that the quantity of gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of gas so delivered during such period shall be estimated and agreed upon by the parties hereto upon the basis of the best available data determined, a. by using the registration of any check measuring equipment, if installed and registering accurately or in the absence of (a); b. by correcting the error if the percentage of error is ascertainable by calibration, test, or mathematical calculation, or in the absence of both (a) and (b); General Terms - Page 8 c. by estimating the quantity of gas deliveries by deliveries during preceding periods under similar conditions when the meter was registering accurately. 5.5 The measurement hereunder shall be corrected for deviation from Boyle's Law at the pressure and temperature under which gas is delivered hereunder. ARTICLE VI BILLINGS AND PAYMENTS 6.1 On or before the first (1st) day of each month, Company shall render to Customer an invoice for the storage charge (D(1)) and the deliverability charge (D(2)) due hereunder for such month. Customer shall pay such invoiced amounts on or before the fifteenth (15th) day of the month for which such charges are due. 6.2 On the tenth (10th) day of each month, Company shall render to Customer a statement for the preceding month properly identifying the applicable Point(s) of Delivery and Point(s) of Redelivery and showing the total quantity of gas received from and delivered to Customer hereunder, the amounts due pursuant to Sections 6.1(c) and 6.1(d) of the Gas Storage Contract therefor, the amount of Customer's gas in storage as of the close of such month, and information sufficient to explain and support any adjustments made by Company (in accordance with section 6.4 below) in determining the amount billed. Customer shall pay Company the full amount reflected on the statements rendered within fifteen (15) days of its receipt of same. If the fifteenth (15th) day shall fall upon a weekend or legal holiday, then such payment shall General Terms - Page 9 be made on the first regular business day following such fifteenth (15th) day. 6.3 In the event that Customer fails to pay any amounts when due, interest shall accrue on all unpaid amounts from the date due until paid at a rate of interest equal to the lesser of: (i) the rate of interest quoted as the "prime rate" of NCNB Texas National Bank -- Dallas, Texas to its largest and most credit-worthy commercial customers; or (ii) the highest legal rate of interest allowed by law. 6.4 In the event an error is discovered in the amount billed in any statement rendered by Company, such error shall be adjusted within thirty (30) days of the discovery of the error. In the event a dispute arises as to the amount payable in any statement rendered, Customer shall pay the amount shown payable to Company in the statement which is not in dispute. Any overcharges collected by Company pursuant to this section 6.4 shall be remitted to Customer, with interest, calculated as provided in section 6.3, from the date such overcharges are received by Company until repaid. Such payment shall not be deemed to be a waiver of the right by Customer to recoup any overpayment. All statements shall be considered final, and any and all objections thereto be deemed waived, unless made in writing within twenty-four (24) months of Customer's receipt thereof. General Terms - Page 10 ARTICLE VII TAXES 7.1 Subject to the provisions of Section 7.3, Customer agrees to pay to Company, by way of reimbursement, within fifteen (15) days of receipt of an invoice for same (pro-rated among all customers), all new taxes enacted and levied or imposed upon Company after the Commencement Date and, any increases in existing taxes which may be made effective after the Commencement Date, which arise out of the gas storage services provided hereunder. In the event that any additional taxes or increases in taxes are imposed with respect to the storage of gas hereunder and, should Company elect not to challenge the same, then Customer shall be subrogated to Company's rights to challenge same. 7.2 The term "taxes" as used herein, shall mean all taxes which are now in existence or which may in the future be levied upon Company, or its facilities or the storage of gas hereunder and arising out of the gas storage services to be provided hereunder including, but not limited to, street and alley rental tax, licenses, fees and any other taxes, charges or fees of any kind levied, assessed or made by any governmental authority on the act, right or privilege of transporting, handling or delivering gas or using Company's Storage Facilities, which is measured by the volume, heating value, value of the gas, or any fee in respect to the gas or the storage,transportation or other handling thereof (excluding, however, real property, ad valorem, capital stock, income or excess profit taxes, or general franchise taxes imposed General Terms - Page 11 on corporations on account of their corporate existence or on their right to do business within the state as a foreign corporation and similar taxes). 7.3 Customer shall not be obligated to reimburse Company pursuant to Section 7.1 in any year in an amount in excess of five percent (5%) of the cumulative total of the monthly demand charges paid by Customer to Company in such year. In the event that the total of the increases in taxes and additional taxes exceed such five percent (5%) amount, then Company shall have the option of paying the same or of seeking a determination from the appropriate regulatory agency that such additional taxes or increases in taxes are prudent and appropriate for inclusion in Company's rates. Subject to the following provisions, in the event that such regulatory agency determines that such additional and increased taxes including, without limitation, those in excess of said five percent (5%) amount, are appropriate for inclusion, Customer shall have the option of either paying such approved rate increases or terminating this Contract, upon providing Company sixty days' prior written notice; provided, however, that upon receipt of Customer's notice of termination, Company shall have the option, without obligation, to charge Customer an increased amount which does not exceed such five percent (5%) amount and, in such event, Customer's notice of termination shall be of no force or effect and this Contract shall continue in accordance with its terms. Company shall provide Customer written notice of any such election within such sixty (60) day period. Customer shall be given notice and General Terms - Page 12 shall have the right to participate in such rate determination and oppose the appropriateness of including the additional or increased taxes in Company's rates. ARTICLE VIII REGULATORY BODIES This Contract is subject to all present and future valid laws and lawful orders of all regulatory bodies now or hereafter having jurisdiction of either or both the parties; and should either of the parties, by force of any such law or regulation imposed at any time during the term of this Contract, be rendered unable, wholly or in part, to carry out its obligations under this Contract, other than Customer's obligation to make payments due hereunder then, this Contract shall continue nevertheless and shall then be deemed modified to conform with the requirements of such law or regulation. Notwithstanding the above, this Contract shall not be deemed to be so modified if such law or regulation substantially and materially prohibits Company from providing services to Customer hereunder substantially in accordance with the terms set forth in this Contract and, in such event, Company and Customer shall negotiate in good faith to amend the terms of this Contract such that such law or regulation may be complied with and both Company and Customer will continue to receive the rights and benefits herein provided. This Contract is expressly made subject to any and all tariff and other filings made by Company and approved by any federal or state regulatory body provided, that Company will not, without Customer's consent, seek to alter the General Terms - Page 13 firm character of the storage services herein provided or to reduce the term of this Contract. In the event that any regulatory body having jurisdiction over this Contract prohibits Company from collecting rates for the services provided hereunder which are at least equal to the rates and charges provided for in this Contract, then Company shall have the right to terminate this Contract. In the event that any regulatory body having jurisdiction requires Company to collect rates for services provided hereunder which are in excess of the rates herein provided, then Customer shall have the right to terminate this Contract. ARTICLE IX FORCE MAJEURE 9.1 In the event of either party hereto being rendered unable, wholly or in part, by force majeure to carry out its obligations under this Contract, other than to make payments hereunder (except as provided in section 9.3 below), the obligations of the party, as 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 as far as possible be remedied with all reasonable dispatch. The party so affected by such event of force majeure shall give written notice, including reasonably full particulars of such force majeure, in writing or by telegraph to the other party as soon as possible but in no event more than ten (10) days after the occurrence of the cause so relied upon. General Terms - Page 14 9.2 The term "force majeure" as employed herein shall mean, without limitation, acts of God, strikes, lockouts, or other industrial disturbances, acts of the public enemy, wars, blockades, insurrection, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrest and restraints of governments and people, civil disturbances, explosions, breakage and/or accidents to machinery, lines or pipe, freezing of lines of pipe, inability to obtain or delay in obtaining rights-of-way, material, supplies, labor or permits, or refusal by pipelines, which are transporting on customer's behalf, to receive or deliver gas hereunder. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty, and that the above requirements that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of any opposing party when such course is inadvisable in the discretion of the party having the difficulty. Company shall utilize all reasonable efforts to design, operate and maintain its facilities in a manner which minimizes the potential for freezing of wells or lines of pipe. 9.3 In the event that Company is, due to an event of force majeure, as herein defined, unable to provide storage services, in whole or in part, under this Contract, then the obligation of Customer to make payment of demand charges hereunder shall thereafter be waived or reduced proportionately until service is again made available hereunder. General Terms - Page 15 ARTICLE X DEFAULT AND TERMINATION 10.1 If either party hereto shall fail to perform any of the covenants or obligations imposed upon it by virtue of this Contract (except where such failure shall be excused under any of the provisions hereof), then in such event the other party may, at its option, terminate this Contract by proceeding as follows: the party not in default shall cause a written notice to be served upon the party in default, stating specifically the cause for terminating this Contract and declaring it to be the intention of the party giving the notice to terminate the same; whereupon, the party in default shall have thirty (30) days after receipt of the aforesaid notice in which to remedy or remove the cause or causes of default stated in the notice of termination and if, within said period of thirty (30) days, the party in default does so remedy and remove said cause or causes, and fully indemnifies the party not in default, then such notice shall be nullified and this Contract shall continue in full force and effect. In the event the party in default does not so remedy and remove the cause or causes of default, or does not fully indemnify the party giving the notice for such party's actual damages as a result of such default within said period of thirty (30) days, then this Contract shall become null and void from and after the expiration of said period; provided, however, that if such default be remedied but no indemnification therefor has been made due to a bona fide dispute between the parties as to the amount thereof, then this Contract General Terms - Page 16 shall not terminate, but the party not in default shall have the right to seek recovery of its actual damages as provided by law. Any termination for breach of this Contract shall be carried out strictly in accordance with this section. Nothing in this Section 10.1 shall be construed to limit in any way the remedies available to either party for breach of this Contract except for the right to terminate. 10.2 Any cancellation of this Contract pursuant to the provisions of this Article X shall be without prejudice to the right of the party not in default to collect any amounts then due it and without waiver of any other remedy to which the party not in default may be entitled. 10.3 In the event of termination, cancellation or expiration of this Contract and, upon such occurrence, there is gas in storage for Customer's account, this Contract shall continue in force and effect for the sole purpose of withdrawal and delivery of and payment for storage services of said gas for an additional ninety (90) days. General Terms - Page 17 EXHIBIT "B" TO GAS STORAGE CONTRACT BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990
Maximum Quantity POINT(S) OF DELIVERY (In MMBtu's) -------------------- ---------------- Interconnection between the Storage 10,000 Facilities and the pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage 10,000 Facilities and the pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Delivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Delivery shall not exceed the MDIQ stated in the Contract, unless otherwise agreed by Company.
Maximum Quantity POINT (S) Of REDELIVERY (In MMBtu's) ----------------------- ---------------- Interconnection between the Storage 20,000 Facilities and the pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage 20,000 Facilities and the pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Redelivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Redelivery shall not exceed the MDWQ stated in the Contract, unless otherwise agreed by Company. HATTIESBURG - B 100,000 SUBSCRIBED IN PHASE 1 FIRM STANDBY GAS STORAGE CONTRACT BY AND BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990 PART B* * This Contract for 100,000 MQS ("Part B") is issued, together with a second contract for 200,000 MQS ("Part A"), in replacement of the original Firm Standby Gas Storage Contract for 300,000 MQS dated February 21, 1990. TABLE OF CONTENTS FIRM STANDBY GAS STORAGE CONTRACT I. ACQUISITION AND CONSTRUCTION........................................... 2 II. GAS TO BE STORED AND DELIVERED......................................... 4 III. SCHEDULING............................................................. 6 IV. POINT(S) OF DELIVERY AND REDELIVERY.................................... 8 V. TERM .................................................................. 8 VI. RATES ................................................................. 9 VII. NOTICES................................................................ 13 VIII. GENERAL TERMS AND CONDITIONS........................................... 15 IX. ADDITIONAL STORAGE OPTION.............................................. 15 X. MISCELLANEOUS.......................................................... 16 Exhibit "A" General Terms and Conditions I. DEFINITIONS............................................................ 1 II. QUALITY................................................................ 3 III. PRESSURE............................................................... 4 IV. TITLE AND RISK OF LOSS................................................. 4 V. MEASUREMENT............................................................ 6 VI. BILLINGS AND PAYMENTS ................................................. 9 VII. TAXES.................................................................. 10 VIII. REGULATORY BODIES...................................................... 13 IX. FORCE MAJEURE.......................................................... 14 X. DEFAULT AND TERMINATION................................................ 16 Exhibit "B" Point(s) of Delivery and Redelivery
GAS STORAGE CONTRACT THIS GAS STORAGE CONTRACT (hereinafter referred to as the "Contract") is made effective as of the 21st day of February, 1990, by and between HATTIESBURG INDUSTRIAL GAS SALES COMPANY, a Delaware corporation, (f/k/a Endevco Industrial Gas Sales Company) (herein referred to as "Company"), operator of the Storage Facilities (as defined below) and managing general partner of the Hattiesburg Gas Storage Company, the owner of the said Storage Facilities, and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). W I T N E S S E T H: WHEREAS, Company and Customer are parties to a "Precedent Agreement" dated October 13, 1989, wherein Company and Customer agreed, upon the satisfaction of certain conditions, to enter into this Contract; and WHEREAS, the conditions in the Precedent Agreement have been satisfied or waived; and WHEREAS, subject to the terms hereof, Company will acquire certain caverns located near Petal, Mississippi and develop such caverns into underground natural gas storage facilities (hereinafter referred to as the "Storage Facilities") initially having a usable storage capacity of approximately two billion cubic feet ("Phase I"), and which may, at Company's discretion, subsequently be expanded to a capacity of approximately five billion cubic feet of usable storage capacity ("Phase II"); and WHEREAS, Company will install and construct all facilities necessary to connect the Storage Facilities with the Point(s) of Delivery and Point(s) of Redelivery herein specified; and WHEREAS, Customer desires that Company receive, on a firm basis, at the Points of Delivery herein specified, certain quantities of gas from the pipeline facilities of Transcontinental Gas Pipe Line Corporation ("Transco") and/or Tennessee Gas Pipeline Company ("Tennessee") for the purpose of injecting and storing such gas for Customer or for its account in such Storage Facilities, and that Company redeliver such gas, on a firm basis, into the facilities of said pipeline companies, at the Points of Redelivery herein specified; and WHEREAS, Company desires to perform such services for Customer, all to be provided pursuant and subject to the terms and conditions hereof; NOW, THEREFORE, for and in consideration of the mutual covenants herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed by both parties hereto, Company and Customer hereby agree as follows: ARTICLE I ACQUISITION AND CONSTRUCTION Within thirty (30) days after the execution hereof, Company shall endeavor to close its purchase of the Storage Facilities, on terms and conditions satisfactory to Company. Thereafter, Company shall commence the construction and development of the Storage Facilities and shall provide Customer written notice of the 2 commencement of construction and the date upon which Company anticipates that such facilities will be operational. Upon completion of construction, including testing, as required by all applicable federal, state and/or applicable codes, and all other matters required for operation, Company shall provide Customer written notice that said facilities are fully operational and shall state in such notice a date upon which Company will be ready to receive gas for storage, which date shall be not less than thirty (30) days following such notice (such date to be hereinafter referred to as the "Commencement Date"). If the Commencement Date does not occur on or before December 1, 1990, or such later date as may be agreed upon, (subject to a day for day extension for delays caused by an event(s) of "force majeure" as herein defined and for each day after March 8, 1990 which expires prior to the date that Company receives executed Firm Storage Contracts covering at least 165,000 MMBtu of MDWQ, as herein defined), for any reason, including, without limitation, Company's inability to close its purchase of the Storage Facilities on terms acceptable to Company, then either party shall have the right to terminate this Contract, without further liability or obligation to the other party hereunder, by providing the other party thirty (30) days prior written notice. Notwithstanding the foregoing, in the event that Customer gives notice of termination in accordance with the above and, thereafter, Company provides written notice to Customer stating a Commencement Date which will occur prior to the expiration of such thirty (30) day period, then, Customer's notice of termination shall be void and of no further force or effect and 3 this Contract shall continue in accordance with its terms, unless Company is unable to commence service on the Commencement Date stated in its notice. ARTICLE II GAS TO BE STORED AND DELIVERED 2.1 Subject to the terms and provisions of this Contract, Company agrees to reserve for service to Customer a portion of the Storage Facilities. The capacities so reserved for Customer shall be sufficient to enable Customer to inject gas into, withdraw gas from, and store gas in the Storage Facilities, in quantities up to the maximum quantities set forth below: (i) a maximum daily withdrawal quantity ("MDWQ") of 10,000 MMBtu per day; (ii) a maximum daily injection quantity ("MDIQ") of 5,000 MMBtu per day; (iii) a maximum capacity in the Storage Facilities ("MQS") equal to 100,000 MMBtu. 2.2 Customer shall tender or cause to be tendered to Company at the Point(s) of Delivery any gas which Customer desires to have injected into storage hereunder. Customer shall also receive or cause to be received gas requested to be withdrawn from storage at the Point(s) of Redelivery upon tender for redelivery by Company. 2.3 Subject to the operating conditions of the pipelines delivering or receiving gas for Customer's account, Company shall receive gas for injection from Customer at the Point(s) of Delivery and redeliver gas to Customer at the Point(s) of Redelivery as scheduled by Customer from time to time; provided that Company 4 shall not be obligated to receive for injection any quantity of gas if the injection of the same would cause the quantity of gas stored in the Storage Facilities for Customer's account ("Customer's Gas Storage Inventory") to exceed Customer's MQS as stated above; nor shall Company be obligated at any time to deliver more gas to Customer than Customer has in its then-current Customer's Gas Storage Inventory. 2.4 Company shall not be obligated to receive, at any Point of Delivery for injection, or to redeliver, at any Point of Redelivery, any quantity of gas when the quantity of gas tendered for delivery to Company or requested by Customer to be redelivered, together with all other volumes of gas tendered for delivery to Company at any such Point of Delivery, or requested for redelivery at such Point of Redelivery, is less than 5,000 MMBtu per day in the aggregate. 2.5 In addition to the maximum daily rates of injection and withdrawal as specified above in Section 2.1, Company shall use its best efforts to accommodate requests of Customer to inject or withdraw gas at greater rates of flow and, at such Point(s) of Delivery or Point(s) or Redelivery in addition to those specified on Exhibit "B" annexed hereto, at such times as such additional capacities are not required for service to other firm, standby storage customers. Any such additional services shall be provided at the rates stated in Section 6.1(c) and 6.1(d), as may be amended by Section 6.1(e), only as capacities are available and on a pro-rata basis to other firm, standby storage customers, without obligation or liability for interruption by Company as to any 5 withdrawals or injections in excess of the maximums reserved for Customer. Additional withdrawals and/or injections will be made only to the extent that Customer has gas in storage to be withdrawn, or unfilled capacity in the Storage Facilities reserved as part of Customer's MQS as stated herein. ARTICLE III SCHEDULING 3.1 At any time during any day when Customer desires Company to receive and inject gas into, or to withdraw and deliver gas from, the Storage Facilities, Customer shall give verbal notice in accordance with Section 3.2 of this Article to Company's dispatcher, specifying the quantity of gas to be injected or withdrawn and the appropriate Points of Delivery or Points of Redelivery, as applicable. Customer shall make available and tender any gas to be injected hereunder and receive and accept delivery, upon tender by Company, any gas requested to be withdrawn from storage. The quantity of gas stored in the Storage Facilities for the account of Customer shall be increased or decreased upon injection or withdrawal of gas from storage, as applicable. Customer shall not (unless otherwise agreed by Company), on an hourly basis, tender for injection nor shall Company be obligated to receive gas for injection or to withdraw and deliver gas from storage, at rates of flow in excess of 1/24 of Customer's MDIQ or MDWQ, respectively. 3.2 Customer shall notify Company at least eight (8) hours in advance of any requested change in the daily or hourly rate of flow for injections or withdrawals of gas hereunder. Company may waive 6 any part of the eight (8) hour notice upon request if, in Company's reasonable judgement, operating conditions permit such waiver. Customer shall notify Company immediately of any circumstance which causes or will cause the deliveries to or receipts from Company to be different from those requested. Notices provided in this Article may be verbal, followed by a written confirmation delivered via telecopy, overnight mail, first class U.S. mail, or hand-delivery when such written confirmation is requested by either party. Customer shall provide notice of any changes in deliveries to or receipts from Company to all applicable transporting pipelines and shall be responsible for, and shall indemnify and hold Company harmless from, any and all liabilities and expenses resulting from Customer's failure to notify all applicable transporting pipelines of any such changes. 3.3 In the event that an imbalance occurs on the pipeline to or from which such gas is delivered or received, which imbalance results from Company's failure to tender the quantities of gas scheduled for delivery from storage, or accept delivery of the quantities of gas scheduled for injection into storage and tendered for delivery by Customer, all in accordance with and subject to this Contract, Company shall reimburse Customer for any imbalance penalty due and rightfully owing to the pipeline receiving or delivering the gas at such Point(s) of Delivery or Point(s) of Redelivery, which was caused by Company's failure to accept or deliver gas. In the event that Company is unable to receive or deliver gas as required by this Contract and in accordance with the request of Customer as provided above, Company shall notify 7 Customer as soon as practicable following any failure to receive or tender such gas and, Customer shall, as soon as practicable following receipt of such notice, notify and change nominations and scheduling with all pipelines and other parties delivering or receiving gas to be delivered to or withdrawn from storage for Customer and be reasonably diligent in taking such further actions to prevent or minimize any imbalances from occurring. Customer and Company will diligently work to correct any imbalance so caused prior to the end of the applicable balancing period. ARTICLE IV POINT(S) OF DELIVERY AND REDELIVERY 4.1 The Point(s) of Delivery for all gas to be tendered by Customer to Company for injection into the Storage Facilities shall be as specified on Exhibit "B" attached hereto, and the maximum daily quantity of gas which Company is obligated to receive from Customer at each individual Point of Delivery shall not exceed the maximum stated thereon. 4.2 The Point(s) of Redelivery for all gas to be tendered by Company to Customer for redelivery pursuant to the terms hereof shall be as specified on Exhibit "B", attached hereto, and the maximum quantities of gas which Company is obligated to redeliver to Customer at each such Point of Redelivery shall not exceed the maximum stated thereon. ARTICLE V TERM 5.1 This Contract shall be effective as of the date set forth at the outset hereof and shall continue in full force and effect 8 for a primary term of fifteen (15) years following the Commencement Date, as defined in Article I hereof, and year to year thereafter unless and until terminated effective at the end of such fifteenth (15th) year or any year thereafter by either party upon not less than thirty-six (36) months prior written notice. 5.2 Upon expiration hereof, Company agrees that in the event that gas storage services are still being provided in the Storage Facilities by Company, or any assignee of Company as provided for herein, to other customers, then, Customer shall have the right and option to continue to receive storage services from Company, or such assignee of Company, pursuant to terms and conditions, and for rates and charges substantially similar to those being offered to said other customers by Company, or such assignee of Company, at the time of such expiration. ARTICLE VI RATES 6.1 During the first ten (10) years following the Commencement Date, Customer shall pay to Company each month the following charges: 6.1(a) A storage charge ("D (1)") of twenty and one-half cents ($0.205) multiplied by Customer's MQS amount specified in this Agreement; plus 6.1(b) A deliverability charge ("D (2)") of fifty-eight cents ($0.58) multiplied by Customer's MDWQ amount; plus 6.1(c) One cent ($0.01) for each MMBtu of gas received by Company for injection into storage hereunder and one cent 9 ($0.01) for each MMBtu of gas redelivered by Company to Customer hereunder; plus 6.1(d) Customer's pro-rata share of the cost of gas consumed in the operation of the Storage Facilities, such to be pro rated among all Customers based upon the quantities of gas injected and withdrawn by each Customer during each month. It is presently estimated that the total cost of gas to be consumed in the injection and withdrawal of gas into and from the Storage Facilities will initially total approximately three cents ($0.03) per MMBtu, in the aggregate; however, the parties agree that this cost may change from time to time and Customer shall continue to bear its pro rata share of such cost. Company shall endeavor to operate the Storage Facilities in an efficient manner so as to limit the gas consumed to that quantity reasonably required. Each month, Company shall provide Customer a statement showing its prorata share of such quantity and the cost of the gas consumed in the operation of Storage Facilities, along with the necessary supporting workpapers showing the total quantity and cost of gas so consumed and the proration calculations. Customer shall have the option, exercisable upon thirty (30) days prior written notice at any time during the term hereof, to thereafter (during the term hereof) supply its pro-rata share of gas consumed, as opposed to reimbursing Company in accordance herewith. In the event that Customer elects to provide its pro-rata share of the fuel used hereunder, then, following such election, Company shall establish and maintain 10 an account (the "Fuel Account") with Customer. Initially, one and one-half percent (1 1/2%) of all gas delivered to Company at the Points of Delivery hereunder shall be retained by Company and credited to the Fuel Account. Customer shall not pay any injection, withdrawal or storage fee as to any volumes retained by Company. At the close of each month, Company shall debit the Fuel Account with Customer's pro-rata share of the fuel gas. From time to time during the term hereof, Company shall have the right, upon providing Customer ten (10) days' prior written notice, to adjust the quantity of gas to be retained by Company and credited to the Fuel Account in order to reflect actual quantities of gas consumed in the operation of the Storage Facilities and, to cause the Fuel Account to be as near to zero as is practicable on a monthly basis. Within thirty (30) days following the termination hereof, Company shall deliver gas to Customer, or Customer shall deliver gas to Company, as is necessary to cause the Fuel Account to equal zero. Company shall report the status of the Fuel Account as of the end of the previous month with each monthly statement. Customer shall have the right to deliver to Company the maximum capacities set forth in Section 2.1(iii) in addition to the gas delivered by Customer for credit to the Fuel Account. 6.1(e) The fees payable for each MMBtu of gas delivered to Company for injection and for each MMBtu of gas redelivered to Customer hereunder, as provided for in section 6.1(c), shall be subject to adjustment, upon 11 application to and approval by the appropriate regulatory commission, to reflect increases or decreases in the cost of maintenance, supplies and other variable expenses incurred by Company in performing the services hereunder. Customer shall have the right to contest any increase sought hereunder before the appropriate regulatory commission. No such adjusted fee shall exceed, however: (i) the fee herein provided; multiplied by (ii) the sum of one (1) plus the percentage change in the Gross National Product Implicit Price Deflator (the "Index") for the December of the then-current calendar year as compared to such Index for December, 1990. 6.2 Notwithstanding the above, in the event that Company elects to expand the Storage Facilities as referenced in section 9.1, the rates and charges payable hereunder during the remaining portion of the initial ten (10) years hereof shall be redetermined such that the sum of: (a) the D(1) storage charge, as provided in section 6.1(a); and (b) the D(2) deliverability charge, as provided in section 6.1(b); will be reduced such that the total reservation charges payable hereunder during each month shall not exceed eighty percent (80%) of the total reservation charges payable hereunder prior to such expansion and rate redetermination. 6.3 The charges payable hereunder for the remainder of the term hereof following the tenth (10th) year (after the Commencement Date) may be redetermined by the appropriate regulatory body in accordance with this section 6.3. Company shall have the right, upon its election, or shall be obligated, upon request of Customer, to submit cost-of-service information to the appropriate regulatory 12 authority for a review of the rates charged hereunder and to request a determination by such regulatory authority of a rate for the remaining term hereof. Customer shall have the right to take part in such proceedings and to contest the proposed rates to the full extent allowed. Company shall provide Customer not less than thirty (30) days prior written notice of Company's intent to file for a new rate as herein provided. In the event that the rates resulting from such redetermination are in excess of one hundred and ten percent (110%) of the rates specified in Section 6.1, then Customer shall have the right to terminate this Contract upon sixty (60) days' prior written notice; provided, however, that during such sixty (60) day period following the receipt of Customer's notice, Company shall have the option, without obligation, to agree to charge Customer rates which do not exceed one hundred and ten percent (110%) of the rates set forth in Section 6.1 and, in such event, this Contract shall continue for the remaining term. Company shall provide Customer written notice of any such election before the expiration of said sixty (60) day period and, shall therein specify the rate to be charged hereunder. ARTICLE VII NOTICES 7.1 Whenever any notice, request, demand, statement or payment is required or permitted to be given under any provision of this Contract, unless expressly provided otherwise, such shall be in writing, signed by or on behalf of the person giving the same, and shall be deemed to have been given and received upon the 13 actual receipt (including the receipt of a telecopy or facsimile of such notice) at the address of the parties as follows: Company: For Notices: Hattiesburg Industrial Gas Sales Company 5950 Berkshire Lane Suite 1400, L.B. 17 Dallas, Texas 75225 Payments (Wire Transfer) : Union Bank of California -- Los Angeles ABA # 122000496 For Account of Hattiesburg Gas Storage Company Acct No. 0880411845 Customer: Mississippi Valley Gas Company 711 W. Capital Street Jackson, Mississippi 39203 7.2 Operating communications made by telephone or other mutually agreeable means shall be confirmed in writing or by telecopy within two (2) days following same if requested by either party. To facilitate such operating communications on a daily basis, lists of names, telephone and telecopy numbers of appropriate operating personnel shall be exchanged by and between Company and Customer before commencement of service under this Contract. Such lists shall be updated from time to time if changed. 7.3 The addresses of the parties may be revised upon written notice given in accordance herewith, designating in such writing the new address of the party so affected. 14 ARTICLE VIII GENERAL TERMS AND CONDITIONS The General Terms and Conditions attached hereto as Exhibit "A" are hereby incorporated herein and made a part of this Contract as if fully set forth herein. Any conflict or inconsistency, either in construction or interpretation, between the terms hereof and the General Terms and Conditions attached hereto shall be resolved in favor of the terms hereof, ARTICLE IX ADDITIONAL STORAGE OPTION 9.1 Company anticipates that it may elect to expand the Storage Facilities at some time following initial storage operations. In the event that Company so elects to expand the Storage Facilities, Company hereby grants Customer an option on a pro rata portion of any increased capacities (for storage, withdrawal or injection) developed by Company in the Storage Facilities. Such proportionate share shall equal (i) the total additional capacity (for storage, withdrawal or injection) developed by Company in such Storage Facilities multiplied by (ii) a fraction, the numerator of which shall equal Customer's rights to such capacity hereunder (MQS, MDWQ or MDIQ) and the denominator of which shall equal the total storage capacity (for storage, withdrawal or injection) of the Storage Facilities immediately preceding such increase in capacity. Customer shall exercise its option, if at all, in accordance with section 9.2 below. 15 9.2 In the event that Company makes the determination to increase any capacity (for storage, withdrawal or injection) at the Storage Facilities, Company shall so notify Customer in writing. Such notice shall contain the terms and conditions upon which Company will contract with other parties for such capacity(ies), which terms shall be similar to those provided in this Contract. For ninety (90) days following receipt of such notice, Customer shall have the right, without obligation, to contract for additional storage rights in the Storage Facilities upon the terms and conditions offered by Company and reflected in the notice or such other terms as may be agreed to by Customer and Company. Should Customer elect to contract for such additional rights, and provide Company with written notice of such election within such ninety (90) day period, Company shall provide Customer with formal contracts for execution. The failure of Customer to provide written notice to Company of its election to contract for such additional capacity rights within such ninety (90) day period, or the failure of Customer, following such election, to execute and return to Company the contract provided to Customer within thirty (30) days following Customer's receipt of same, shall be deemed a waiver of Customer's option on such capacity(ies). ARTICLE X MISCELLANEOUS 10.1 Headings. The subject headings of the articles and sections of this Contract are intended for the sole purpose of convenient reference and are not intended, nor shall the same be 16 construed, to be a part of this Contract or considered in any interpretation hereof. 10.2 Amendment. Neither this Contract nor any provisions hereof may ever be amended, changed, modified or supplemented except by an agreement in writing, duly executed by the party to be charged with the same. 10.3 Waiver. No failure by either party to enforce the performance of any obligation of the other party under this Contract shall operate as a waiver of such obligation or default, or as a waiver of any other right or default, whether of a like or different character. 10.4 Choice of Law. As to all matters of construction and interpretation, this Contract shall be interpreted, construed and governed by the laws of the State of Texas. 10.5 Succession. Either party may assign its rights, titles or interests hereunder to any individual, bank, trustee, company or corporation as security for any note, notes, bonds or other obligations or securities of such assignor, but not otherwise, without the written consent of the other party hereto, which consent shall not be unreasonably withheld. No assignment provided for hereunder shall in any way operate to enlarge, alter or change any obligation of the other party hereto nor shall the assignee be relieved of its obligations hereunder without the express written consent of the non-assigning party. 10.6 Right of Examination. Both Company and Customer shall have the right to examine, at any reasonable time, the books, records, charts and any operating data of the other to the extent 17 reasonably necessary to verify the accuracy of any statement, chart or computation made under or pursuant to the provisions of this Contract. All books, records and charts related to any statement, charge or computation made hereunder shall be retained and available for review or inspection for a period of two years. 10.7 Entire Agreement. This Contract contains the entire agreement and understanding of the parties hereto and there are no agreements, understandings or representations, either oral or in writing, except as set forth herein. That certain Precedent Agreement, between Customer and Company, is hereby expressly superseded and terminated by the execution hereof. 10.8 Authority. Company and Customer each hereby represents and warrants that it has the full right, power and authority to enter into this Contract, and that this Contract will not violate the provisions of any other contract or agreement to which it is a party. 10.9 Reissuance of Original Contract. This Contract ("Part B"), and another Gas Storage Contract of even date herewith specifying a MQS of 200,000 ("Part A"), are issued in replacement of that certain Firm Standby Gas Storage Contract between Customer and Company dated February 21, 1990. The replacement of the former contract is effected for administrative purposes only, and shall be interpreted and construed for all purposes as merely a continuation of the original contract. IN WITNESS WHEREOF, the parties have executed this Contract in one or more copies or counterparts, each of which shall constitute 18 and be an original of this Contract effective between the parties effective as of the date first-above written. COMPANY: ATTEST: HATTIESBURG INDUSTRIAL GAS SALES COMPANY [ILLEGIBLE] By: [ILLEGIBLE] - --------------------------------- ------------------------------------ Its: President CUSTOMER: ATTEST: MISSISSIPPI VALLEY GAS COMPANY [ILLEGIBLE] By: -s- Warren K. Rogers - --------------------------------- ------------------------------------ Its: Senior Vice President 19 EXHIBIT "A" TO GAS STORAGE CONTRACT BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990 GENERAL TERMS AND CONDITIONS These General Terms and Conditions ("General Terms") are attached to and incorporated into the above-referenced GAS STORAGE CONTRACT between HATTIESBURG INDUSTRIAL GAS SALES COMPANY (herein referred to as "Company") and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). ARTICLE I DEFINITIONS For the purposes of this Contract, unless expressly stated otherwise, the following definitions shall be applicable. 1.1 The term "Btu" shall mean British Thermal Units. 1.2 A "day" shall mean the twenty-four (24) hour period beginning at 7:00 a.m. Jackson, Mississippi time on each calendar day and ending at 7:00 a.m. Jackson, Mississippi time on the following calendar day. 1.3 "Contract" shall mean the above-referenced Gas Storage Contract together with these General Terms and all other attachments hereto or thereto. 1.4 The term "gas" shall mean natural gas in its natural state, produced from wells, including casinghead gas produced with crude oil, natural gas from gas wells and residue gas resulting from processing both casinghead gas and gas well gas. General Terms - Page 1 1.5 The term "Mcf" shall mean one thousand (1,000) cubic feet at a pressure of fifteen and twenty-five thousandths (15.025) psia and at a temperature of sixty degrees (60 degrees) Fahrenheit. 1.6 The term "MMBtu" shall mean 1,000,000 Btu. 1.7 A "month" shall mean that period of time beginning at 7:00 a.m. Jackson, Mississippi time on the first day of a calendar month and ending at 7:00 a.m. Jackson, Mississippi time on the first day of the following calendar month; provided, that, the first month hereunder shall commence on the first day of the calendar month in which the Commencement Date occurs, and the last month hereunder shall end on the date that this Contract terminates. 1.8 "Point(s) of Delivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is received by Company for injection into storage. 1.9 "Point(s) of Redelivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is tendered by Company to Customer for delivery from storage. 1.10 The term "psia" shall mean pounds per square inch absolute. 1.11 The term "psig" shall mean pounds per square inch gauge. 1.12 "Storage Facilities" shall be as defined in the "WHEREAS" clauses of the Contract. 1.13 The term "year" shall mean a period of twelve (12) consecutive months. General Terms - Page 2 ARTICLE II QUALITY The gas delivered by either party to the other hereunder shall meet the quality specifications of the transporting pipeline which receives or delivers such gas at the Point(s) of Delivery or Redelivery and shall, in addition, be of such quality that it shall meet the following specifications, if such standards are more stringent: a. Be commercially free of dust, gum, gum-forming constituents, gasoline, and other solid and/or liquid matter, including but not limited to water, gas treating chemicals and well completion fluids and debris, which may become separated from the gas during transportation thereof. b. Contain not more than one quarter (1/4) grain of hydrogen sulphide per one hundred (100) cubic feet, as determined by the cadmium sulfate quantitative test, nor more than nine (9) grains of total sulfur per one hundred (100) cubic feet. c. The gas delivered hereunder shall not contain more than two-tenths of one percent (0.2%) by volume of oxygen, and shall not contain more than two percent (2%) by volume of carbon dioxide; and shall not contain more than two percent (2%) by volume of nitrogen. d. Have a heating value of not less than nine hundred eighty (980) Btu's per cubic feet. General Terms - Page 3 e. Have a temperature of not more than one hundred twenty degrees Fahrenheit (120 degrees F), nor less than forty degrees Fahrenheit (40 degrees F). f. Have been dehydrated by any method other than the use of a calcium chloride as desiccant, for removal of entrained water in excess of seven (7) pounds of water per million (1,000,000) cubic feet of gas. ARTICLE III PRESSURE Company shall deliver gas to Customer from storage hereunder at pressures sufficient to enter the transporting pipeline's facilities at the Point(s) of Redelivery against the operating pressures maintained in such pipeline from time to time, provided that Company shall not be required to deliver gas at pressures in excess of 960 psig. Customer shall deliver gas to Company for injection at the Point(s) of Delivery at the pressures as may be available from time to time in the transporting pipeline's facilities at such points, but in no event shall such pressures be less than 550 psig or greater than Company's maximum allowable operating pressure. ARTICLE IV TITLE AND RISK OF LOSS 4.1 Title to the natural gas stored by Company and delivered to Customer hereunder shall, at all times, be in Customer and, except as provided in Section 4.2 Company makes no warranty of title whatsoever. Customer warrants for itself, its successors and General Terms - Page 4 assigns, that it will have at the time of delivery of gas storage hereunder good title or valid right to deliver such stored hereunder. Customer warrants for itself, its successors and assigns, that the gas it delivers hereunder shall be free and clear of all liens, encumbrances, or claims whatsoever; and that it shall indemnify Company and save it harmless from all claims, actions, damages, costs and expenses arising directly or indirectly from or with respect to the title to gas tendered to Company hereunder. 4.2 Company warrants that it shall neither cause nor allow any cloud or encumbrance of any nature to arise by, through or under Company with respect to Customer's title to any gas tendered to Company for storage, and agrees to redeliver such gas pursuant to this Contract free from all liens and adverse claims arising by, through or under Company, and that it will indemnify, defend, protect, and save Customer harmless from all claims, suits, actions, damages, costs and expenses arising directly or indirectly from the same. 4.3 As between Customer and Company: Customer shall be in control and possession of the gas prior to delivery to Company for injection at the Point(s) of Delivery and after redelivery by Company to Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Company harmless from any damage or injury caused thereby except for damages and injuries caused by the negligence of Company; and, Company shall be in control and possession of the gas after the receipt of the same for injection at the Point(s) of Delivery and until redelivery by Company to General Terms - Page 5 Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Customer harmless from any damage or injury caused thereby, except for damages and injuries caused by the negligence of Customer. The risk of loss for all gas injected into, stored in and withdrawn from the Storage Facilities shall be and remain with the party having control and possession of the gas as herein provided. ARTICLE V MEASUREMENT 5.1 The unit of volume for measurement of gas delivered hereunder shall be one (1) cubic foot of gas at a base temperature of sixty degrees Fahrenheit (60 degrees F) and at an absolute pressure of fifteen and twenty-five thousandths (15.025) pounds per square inch. All fundamental constants, observations, records, and procedures involved in determining and/or verifying the quantity and other characteristics of gas delivered hereunder shall, unless otherwise specified herein, be in accordance with the standards prescribed in American Gas Association ("A.G.A.") Gas Measurement Committee Report No. 3, as now and from time to time amended or supplemented. All measurements of gas shall be determined by calculation into terms of such unit. All quantities given herein, unless expressly stated otherwise, are in terms of such unit. Notwithstanding the foregoing, it is agreed that, for all purposes, the Btu content of the gas received and delivered by Company hereunder shall be measured on an "as delivered" basis rather than a fully saturated or "wet" basis. General Terms - Page 6 5.2 Company, at its sole expense, shall install, maintain and operate, or cause to be installed, maintained and operated, the measurement facilities required hereunder. Said measurement facilities shall be so equipped with orifice meters, recording gauges, or other types of meters of standard make and design commonly acceptable in the industry, as to accomplish the accurate measurement of gas delivered hereunder. The changing of charts, calibrating and adjustment of meters shall be done by Company or its agent. 5.3 The accuracy of Company's measuring equipment shall be verified by Company at least once in each thirty (30) day period. If either party desires a special test of any measuring equipment, it will promptly notify the other party and the parties shall then cooperate to secure a prompt verification of the accuracy of such equipment. The expenses of any such special test, if requested by Customer, shall be borne by Customer if the measuring equipment tested is found to be accurate within the limit of plus or minus two percent (2%) of error. For the purposes of measurement and meter calibration, the atmospheric pressure shall be assumed to be fourteen and seventy-three hundredths (14.73) pounds per square inch, irrespective of variations in natural atmospheric pressure from time to time. Company and Customer, upon request, shall have the right to be present at any test of any measuring equipment, including any check measuring equipment installed by Customer at its sole expense. General Terms - Page 7 5.4 If upon testing, the metering equipment is found to be inaccurate, in the aggregate, by two percent (2%) or more, either plus or minus, registration thereof and any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half (1/2) of the time elapsed since the day of the last calibration, not exceeding, however, forty-five (45) days. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately; however, if any inaccuracy is less than two percent (2%), all prior readings and measurements shall be deemed to be accurate and no adjustments to any prior reading shall be made. If, for any reason, any meter is registering inaccurately or is out of service or out of repair so that the quantity of gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of gas so delivered during such period shall be estimated and agreed upon by the parties hereto upon the basis of the best available data determined, a. by using the registration of any check measuring equipment, if installed and registering accurately or in the absence of (a); b. by correcting the error if the percentage of error is ascertainable by calibration, test, or mathematical calculation, or in the absence of both (a) and (b); General Terms - Page 8 c. by estimating the quantity of gas deliveries by deliveries during preceding periods under similar conditions when the meter was registering accurately. 5.5 The measurement hereunder shall be corrected for deviation from Boyle's Law at the pressure and temperature under which gas is delivered hereunder. ARTICLE VI BILLINGS AND PAYMENTS 6.1 On or before the first (1st) day of each month, Company shall render to Customer an invoice for the storage charge (D(1)) and the deliverability charge (D(2)) due hereunder for such month. Customer shall pay such invoiced amounts on or before the fifteenth (15th) day of the month for which such charges are due. 6.2 On the tenth (10th) day of each month, Company shall render to Customer a statement for the preceding month properly identifying the applicable Point(s) of Delivery and Point(s) of Redelivery and showing the total quantity of gas received from and delivered to Customer hereunder, the amounts due pursuant to Sections 6.1(c) and 6.1(d) of the Gas Storage Contract therefor, the amount of Customer's gas in storage as of the close of such month, and information sufficient to explain and support any adjustments made by Company (in accordance with section 6.4 below) in determining the amount billed. Customer shall pay Company the full amount reflected on the statements rendered within fifteen (15) days of its receipt of same. If the fifteenth (15th) day shall fall upon a weekend or legal holiday, then such payment shall General Terms - Page 9 be made on the first regular business day following such fifteenth (15th) day. 6.3 In the event that Customer fails to pay any amounts when due, interest shall accrue on all unpaid amounts from the date due until paid at a rate of interest equal to the lesser of: (i) the rate of interest quoted as the "prime rate" of NCNB Texas National Bank -- Dallas, Texas to its largest and most credit-worthy commercial customers; or (ii) the highest legal rate of interest allowed by law. 6.4 In the event an error is discovered in the amount billed in any statement rendered by Company, such error shall be adjusted within thirty (30) days of the discovery of the error. In the event a dispute arises as to the amount payable in any statement rendered, Customer shall pay the amount shown payable to Company in the statement which is not in dispute. Any overcharges collected by Company pursuant to this section 6.4 shall be remitted to Customer, with interest, calculated as provided in section 6.3, from the date such overcharges are received by Company until repaid. Such payment shall not be deemed to be a waiver of the right by Customer to recoup any overpayment. All statements shall be considered final, and any and all objections thereto be deemed waived, unless made in writing within twenty-four (24) months of Customer's receipt thereof. General Terms - Page 10 ARTICLE VII TAXES 7.1 Subject to the provisions of Section 7.3, Customer agrees to pay to Company, by way of reimbursement, within fifteen (15) days of receipt of an invoice for same (pro-rated among all customers), all new taxes enacted and levied or imposed upon Company after the Commencement Date and, any increases in existing taxes which may be made effective after the Commencement Date, which arise out of the gas storage services provided hereunder. In the event that any additional taxes or increases in taxes are imposed with respect to the storage of gas hereunder and, should Company elect not to challenge the same, then Customer shall be subrogated to Company's rights to challenge same. 7.2 The term "taxes" as used herein, shall mean all taxes which are now in existence or which may in the future be levied upon Company, or its facilities or the storage of gas hereunder and arising out of the gas storage services to be provided hereunder including, but not limited to, street and alley rental tax, licenses, fees and any other taxes, charges or fees of any kind levied, assessed or made by any governmental authority on the act, right or privilege of transporting, handling or delivering gas or using Company's Storage Facilities, which is measured by the volume, heating value, value of the gas, or any fee in respect to the gas or the storage, transportation or other handling thereof (excluding, however, real property, ad valorem, capital stock, income or excess profit taxes, or general franchise taxes imposed General Terms - Page 11 on corporations on account of their corporate existence or on their right to do business within the state as a foreign corporation and similar taxes). 7.3 Customer shall not be obligated to reimburse Company pursuant to Section 7.1 in any year in an amount in excess of five percent (5%) of the cumulative total of the monthly demand charges paid by Customer to Company in such year. In the event that the total of the increases in taxes and additional taxes exceed such five percent (5%) amount, then Company shall have the option of paying the same or of seeking a determination from the appropriate regulatory agency that such additional taxes or increases in taxes are prudent and appropriate for inclusion in Company's rates. Subject to the following provisions, in the event that such regulatory agency determines that such additional and increased taxes including, without limitation, those in excess of said five percent (5%) amount, are appropriate for inclusion, Customer shall have the option of either paying such approved rate increases or terminating this Contract, upon providing Company sixty days' prior written notice; provided, however, that upon receipt of Customer's notice of termination, Company shall have the option, without obligation, to charge Customer an increased amount which does not exceed such five percent (5%) amount and, in such event, Customer's notice of termination shall be of no force or effect and this Contract shall continue in accordance with its terms. Company shall provide Customer written notice of any such election within such sixty (60) day period. Customer shall be given notice and General Terms - Page 12 shall have the right to participate in such rate determination and oppose the appropriateness of including the additional or increased taxes in Company's rates. ARTICLE VIII REGULATORY BODIES This Contract is subject to all present and future valid laws and lawful orders of all regulatory bodies now or hereafter having jurisdiction of either or both the parties; and should either of the parties, by force of any such law or regulation imposed at any time during the term of this Contract, be rendered unable, wholly or in part, to carry out its obligations under this Contract, other than Customer's obligation to make payments due hereunder then, this Contract shall continue nevertheless and shall then be deemed modified to conform with the requirements of such law or regulation. Notwithstanding the above, this Contract shall not be deemed to be so modified if such law or regulation substantially and materially prohibits Company from providing services to Customer hereunder substantially in accordance with the terms set forth in this Contract and, in such event, Company and Customer shall negotiate in good faith to amend the terms of this Contract such that such law or regulation may be complied with and both Company and Customer will continue to receive the rights and benefits herein provided. This Contract is expressly made subject to any and all tariff and other filings made by Company and approved by any federal or state regulatory body provided, that Company will not, without Customer's consent, seek to alter the General Terms - Page 13 Rev. 022790 firm character of the storage services herein provided or to reduce the term of this Contract. In the event that any regulatory body having jurisdiction over this Contract prohibits Company from collecting rates for the services provided hereunder which are at least equal to the rates and charges provided for in this Contract, then Company shall have the right to terminate this Contract. In the event that any regulatory body having jurisdiction requires Company to collect rates for services provided hereunder which are in excess of the rates herein provided, then Customer shall have the right to terminate this Contract. ARTICLE IX FORCE MAJEURE 9.1 In the event of either party hereto being rendered unable, wholly or in part, by force majeure to carry out its obligations under this Contract, other than to make payments hereunder (except as provided in section 9.3 below), the obligations of the party, as 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 as far as possible be remedied with all reasonable dispatch. The party so affected by such event of force majeure shall give written notice, including reasonably full particulars of such force majeure, in writing or by telegraph to the other party as soon as possible but in no event more than ten (10) days after the occurrence of the cause so relied upon. General Terms - Page 14 Rev. 022790 9.2 The term "force majeure" as employed herein shall mean, without limitation, acts of God, strikes, lockouts, or other industrial disturbances, acts of the public enemy, wars, blockades, insurrection, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrest and restraints of governments and people, civil disturbances, explosions, breakage and/or accidents to machinery, lines or pipe, freezing of lines of pipe, inability to obtain or delay in obtaining rights-of-way, material, supplies, labor or permits, or refusal by pipelines, which are transporting on Customer's behalf, to receive or deliver gas hereunder. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty, and that the above requirements that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of any opposing party when such course is inadvisable in the discretion of the party having the difficulty. Company shall utilize all reasonable efforts to design, operate and maintain its facilities in a manner which minimizes the potential for freezing of wells or lines of pipe. 9.3 In the event that Company is, due to an event of force majeure, as herein defined, unable to provide storage services, in whole or in part, under this Contract, then the obligation of Customer to make payment of demand charges hereunder shall thereafter be waived or reduced proportionately until service is again made available hereunder. General Terms - Page 15 Rev. 022790 ARTICLE X DEFAULT AND TERMINATION 10.1 If either party hereto shall fail to perform any of the covenants or obligations imposed upon it by virtue of this Contract (except where such failure shall be excused under any of the provisions hereof), then in such event the other party may, at its option, terminate this Contract by proceeding as follows: the party not in default shall cause a written notice to be served upon the party in default, stating specifically the cause for terminating this Contract and declaring it to be the intention of the party giving the notice to terminate the same; whereupon, the party in default shall have thirty (30) days after receipt of the aforesaid notice in which to remedy or remove the cause or causes of default stated in the notice of termination and if, within said period of thirty (30) days, the party in default does so remedy and remove said cause or causes, and fully indemnifies the party not in default, then such notice shall be nullified and this Contract shall continue in full force and effect. In the event the party in default does not so remedy and remove the cause or causes of default, or does not fully indemnify the party giving the notice for such party's actual damages as a result of such default within said period of thirty (30) days, then this Contract shall become null and void from and after the expiration of said period; provided, however, that if such default be remedied but no indemnification therefor has been made due to a bona fide dispute between the parties as to the amount thereof, then this Contract General Terms - Page 16 Rev. 027790 shall not terminate, but the party not in default shall have the right to seek recovery of its actual damages as provided by law. Any termination for breach of this Contract shall be carried out strictly in accordance with this section. Nothing in this Section 10.1 shall be construed to limit in any way the remedies available to either party for breach of this Contract except for the right to terminate. 10.2 Any cancellation of this Contract pursuant to the provisions of this Article X shall be without prejudice to the right of the party not in default to collect any amounts then due it and without waiver of any other remedy to which the party not in default may be entitled. 10.3 In the event of termination, cancellation or expiration of this Contract and, upon such occurrence, there is gas in storage for Customer's account, this Contract shall continue in force and effect for the sole purpose of withdrawal and delivery of and payment for storage services of said gas for an additional ninety (90) days. General Terms - Page 17 Rev. 021790 EXHIBIT "B" TO GAS STORAGE CONTRACT BETWEEN HATTIESBURG INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE FEBRUARY 21, 1990
Maximum Quantity POINT(S) OF DELIVERY (In MMBtu's) - -------------------- ---------------- Interconnection between the Storage Facilities and the 5,000 pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage Facilities and the 5,000 pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Delivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Delivery shall not exceed the MDIQ stated in the Contract, unless otherwise agreed by Company.
Maximum Quantity POINT(S) of REDELIVERY (In MMBtu's) - ---------------------- ---------------- Interconnection between the Storage Facilities and the 10,000 pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage Facilities and the 10,000 pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Redelivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Redelivery shall not exceed the MDWQ stated in the Contract, unless otherwise agreed by Company. EX-10.13(I) 18 d10753exv10w13xiy.txt GAS STORAGE CONTRACT EXHIBIT 10.13(i) HATTIESBURG - 1A ADDITIONAL 100,000 SUBSCRIBED IN PHASE 1A GAS STORAGE CONTRACT BY AND BETWEEN ENDEVCO INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY DATED 08/24/90 PHASE IA TABLE OF CONTENTS
FIRM STANDBY GAS STORAGE CONTRACT I. CONDITIONS PRECEDENT..................................................................... 2 II. ACQUISITION AND CONSTRUCTION............................................................. 3 III. GAS TO BE STORED AND DELIVERED........................................................... 3 IV. SCHEDULING............................................................................... 5 V. POINT(S) OF DELIVERY AND REDELIVERY...................................................... 6 VI. TERM..................................................................................... 6 VII. RATES.................................................................................... 7 VIII. NOTICES ................................................................................. 9 IX. GENERAL TERMS AND CONDITIONS............................................................. 9 X. MISCELLANEOUS............................................................................ 10 Exhibit "A" General Terms and Conditions I. DEFINITIONS.............................................................................. 1 II. QUALITY.................................................................................. 2 III. PRESSURE................................................................................. 3 IV. TITLE AND RISK OF LOSS.................................................................. 3 V. MEASUREMENT............................................................................. 4 VI. BILLINGS AND PAYMENTS .................................................................. 5 VII. TAXES ................................................................................. 6 VIII. REGULATORY BODIES ...................................................................... 7 IX. FORCE MAJEURE........................................................................... 8 X. DEFAULT AND TERMINATION ................................................................ 9
Exhibit "B" Point(s) of Delivery and Redelivery GAS STORAGE CONTRACT THIS GAS STORAGE CONTRACT (hereinafter referred to as the "Contract") is made and entered into as of the 24th day of August, 1990, by and between ENDEVCO INDUSTRIAL GAS SALES COMPANY, a Delaware corporation, (herein referred to as "Company"), operator of the Storage Facilities (as defined below) and managing general partner of the Hattiesburg Gas Storage Company, the owner of the said Storage Facilities, and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). W I T N E S S E T H: WHEREAS, Company is the operator of certain underground gas storage facilities located near Petal, Mississippi (hereinafter referred to as the "Storage Facilities") which initially have (or will have upon completion) a usable storage capacity of approximately 2.2 billion cubic feet ("Phase I"); and WHEREAS, subject to the terms hereof, as a result of interest by existing storage customers and additional parties in obtaining storage services, in addition to that available in the initial phase of the project ("Phase I") and in a shorter time frame than contemplated through a Phase II operation (the leaching of a new cavern on the existing properties), Company desires to enlarge the Storage Facilities by approximately one billion cubic feet of additional usable storage capacity by acquiring an additional underground storage cavern located on properties not previously acquired by Company, and converting said cavern into gas storage service and incorporating the same into the Storage Facilities (said acquisition and expansion to be referred to as "Phase IA"); and WHEREAS, Customer desires to contract for a portion of the additional capacity to be added in Phase IA to the Storage Facilities, and desires that Company receive, on a firm basis, at the Points of Delivery herein specified, certain quantities of gas from the pipeline facilities of Transcontinental Gas Pipe Line Corporation ("Transco") and/or Tennessee Gas Pipeline Company ("Tennessee") for the purpose of injecting and storing such gas for Customer or for its account in such Storage Facilities, and that Company redeliver such gas, on a firm basis, into the facilities of said pipeline companies at the Points of Redelivery herein specified; and WHEREAS, Company desires to perform such services for Customer, all to be provided pursuant and subject to the terms and conditions hereof; NOW, THEREFORE, for and in consideration of the mutual covenants herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed by both parties hereto, Company and Customer hereby agree as follows: ARTICLE I CONDITIONS PRECEDENT 1.1 The obligations of Company under this Contract shall be subject to the occurrence of each of the following conditions precedent, the satisfaction of which must be acceptable to Company in its sole discretion: (a) Company shall have obtained all permits, authorizations, certificates and approvals, as deemed necessary or desirable by Company, from all appropriate local, state or federal agencies having jurisdiction over the construction, operation or rates charged for services, to enable Company to perform its obligations and receive the benefits provided for herein; (b) Company shall have received executed gas storage contracts with other storage customers, on terms and conditions substantially similar to those contained herein, under which all storage customers (including Customer hereunder) are committed to contract, in the aggregate, for a quantity of daily deliverability (defined as the "MDWQ" in Article I to the General Terms and Conditions attached hereto as Exhibit "A") from the additional storage cavern to be added to the Storage Facilities under Phase IA, which is equal to or greater than 80,000 MMBtu per day; and (c) Company shall have acquired the properties (including, without limitation, the additional cavern to be incorporated into the Storage Facilities in said Phase IA expansion) on terms and conditions satisfactory to Company and, shall have arranged all necessary funding and financing for such expansion on terms acceptable to Company. 1.2 Company shall use its best efforts and be diligent in seeking the satisfaction of each of the above-referenced conditions precedent. However, the conditions set forth in section 1.1 above shall not be deemed to have been satisfied unless and until Company notifies Customer in writing of the satisfaction of all of the same. In the event that Company has not provided Customer notice of the satisfaction of all of the above-referenced conditions by 5:00 p.m. on March 31, 1991, then Customer shall have the right to terminate this Contract without further liability hereunder upon thirty (30) days prior written notice; provided, however, that should Company give Customer written notice of the satisfaction of such conditions within thirty (30) days following its receipt of Customer's notice of termination, as herein provided, then customer's notice of termination shall be null and void and this Contract shall continue in accordance with its terms. 2 1.3 Should Company determine at any time that such conditions can not be satisfied within a reasonable time and at a reasonable expense, Company shall have the continuing right to terminate this Contract without further liability hereunder, upon providing written notice to Customer. Company may not discriminate as between the termination of this Contract in accordance with this Section 1.3 and the termination of all other storage contracts with other customers contracting for capacity in the Phase IA expansion. The termination by Company of this Contract in accordance with this Section 1.3 shall only be made in connection with the termination of all of the other contracts with other customers as referenced in Section 1.1(b) above. ARTICLE II CONSTRUCTION Within thirty (30) days after the satisfaction of all of the conditions set forth in Article I, Company shall commence the construction and development of Phase IA of the Storage Facilities and shall provide Customer written notice of the commencement of construction and the date upon which Company anticipates that such facilities will be operational. Upon completion of construction, including testing, as required by all applicable federal, state and/or applicable codes, and all other matters required for operation, Company shall provide Customer written notice that said facilities are fully operational and shall state in such notice a date upon which Company will be ready to receive gas for storage, which date shall be not less than ten (10) days following such notice (such date to be hereinafter referred to as the "Commencement Date"). If the Commencement Date does not occur on or before December 1, 1991, or such later date as may be agreed upon, (subject to a day for day extension for delays caused by an event(s) of "force majeure" as herein defined) either party shall have the right to terminate this Contract, without further liability or obligation to the other party hereunder, by providing the other party thirty (30) days prior written notice. Notwithstanding the foregoing, in the event that Customer gives notice of termination in accordance with the above and, thereafter, Company provides written notice to Customer stating a Commencement Date which will occur prior to the expiration of such thirty (30) day period, then, Customer's notice of termination shall be void and of no further force or effect and this Contract shall continue in accordance with its terms, provided that service commences hereunder on the Commencement Date stated in such notice. ARTICLE III GAS TO BE STORED AND DELIVERED 3.1 Subject to the terms and provisions of this Contract, Company agrees to reserve for service to Customer a portion of the capacity in Phase IA of the Storage Facilities. The capacities so reserved for Customer shall be sufficient to enable Customer to inject gas into, withdraw gas from, and store gas in the Storage 3 Facilities, in quantities up to the maximum quantities set forth below: (i) a maximum daily withdrawal quantity ("MDWQ") of 10,000 MMBtu per day; (ii) a maximum daily injection quantity ("MDIQ") of 5,000 MMBtu per day; (iii) a maximum capacity in the Storage Facilities ("MQS") equal to 100,000 MMBtu. 3.2 Customer shall tender or cause to be tendered to Company at the Point(s) of Delivery any gas which Customer desires to have injected into storage hereunder. Customer shall also receive or cause to be received gas requested to be withdrawn from storage at the Point(s) of Redelivery upon tender for redelivery by Company. 3.3 Subject to the operating conditions of the pipelines delivering or receiving gas for Customer's account, Company shall receive gas for injection from Customer at the Point(s) of Delivery and redeliver gas to Customer at the Point (s) of Redelivery as scheduled by Customer from time to time; provided that Company shall not be obligated to receive for injection any quantity of gas if the injection of the same would cause the quantity of gas stored in the Storage Facilities for Customer's account ("Customer's Gas Storage Inventory") to exceed Customer's MQS as stated above; nor shall Company be obligated at any time to deliver more gas to Customer than Customer has in its then-current Customer's Gas Storage Inventory. 3.4 Company shall not be obligated to receive, at any Point of Delivery for injection, or to redeliver, at any Point of Redelivery, any quantity of gas when the quantity of gas tendered for delivery to Company or requested by Customer to be redelivered, together with all other volumes of gas tendered for delivery to Company at any such Point of Delivery, or requested for redelivery at such Point of Redelivery, is less than 5,000 MMBtu per day in the aggregate. 3.5 In addition to the maximum daily rates of injection and withdrawal as specified above in Section 3.1, Company shall use its best efforts to accommodate requests of Customer to inject or withdraw gas at greater rates of flow and, at such Point (s) of Delivery or Point(s) or Redelivery in addition to those specified on Exhibit "B" annexed hereto, at such times as such additional capacities are not required for service to other firm storage customers. Any such additional services shall be provided at the rates stated in Section 7.1(c) and 7.1(d), as may be amended by Section 7.1(e), only as capacities are available. All such services shall be provided on a pro-rata basis to all firm storage customers, without obligation or liability for interruption by Company as to any withdrawals or injections in excess of the maximums reserved for Customer. Additional withdrawals and/or 4 injections will be made only to the extent that Customer has gas in storage to be withdrawn, or unfilled capacity in the Storage Facilities reserved as part of Customer's MQS as stated herein. ARTICLE IV SCHEDULING 4.1 At any time during any day when Customer desires Company to receive and inject gas into, or to withdraw and deliver gas from the Storage Facilities, Customer shall give verbal notice in accordance with Section 4.2 of this Article to Company's dispatcher, specifying the quantity of gas to be injected or withdrawn and the appropriate Points of Delivery or Points of Redelivery, as applicable. Customer shall make available and tender any gas to be injected hereunder and shall receive and accept delivery, upon tender by Company, any gas requested to be withdrawn from storage. The quantity of gas stored in the Storage Facilities for the account of Customer shall be increased or decreased upon injection or withdrawal of gas from storage, as applicable. Customer shall not (unless otherwise agreed by Company), on an hourly basis, tender for injection, nor shall Company be obligated to receive gas for injection or to withdraw and deliver gas from storage, at rates of flow in excess of 1/24 of Customer's MDIQ or MDWQ, respectively. 4.2 Customer shall notify Company at least eight (8) hours in advance of any requested change in the daily or hourly rate of flow for injections or withdrawals of gas hereunder. Company may waive any part of the eight (8) hour notice upon request if, in Company's reasonable judgement, operating conditions permit such waiver. Customer shall notify Company immediately of any circumstance which causes or will cause the deliveries to or receipts from Company to be different from those requested. Notices provided in this Article may be verbal, followed by a written confirmation delivered via telecopy, overnight mail, first class U.S. mail, or hand- delivery when such written confirmation is requested by either party. Customer shall provide notice of any changes in deliveries to or receipts from Company to all applicable transporting pipelines and shall be responsible for, and shall indemnify and hold Company harmless from, any and all liabilities and expenses resulting from Customer's failure to notify all applicable transporting pipelines of any such changes. 4.3 In the event that an imbalance occurs on the pipeline to or from which such gas is delivered or received, which imbalance results from Company's failure to tender the quantities of gas scheduled for delivery from storage, or accept delivery of the quantities of gas scheduled for injection into storage and tendered for delivery by Customer, all in accordance with and subject to this Contract, Company shall reimburse Customer for any imbalance penalty due and rightfully owing to the pipeline receiving or delivering the gas at such Point(s) of Delivery or Point(s) of Redelivery, which was caused by Company's failure to accept or deliver gas. In the event that Company is unable to receive or 5 deliver gas as required by this Contract and in accordance with the request of Customer as provided above, Company shall notify Customer as soon as practicable following any failure to receive or tender such gas and, Customer shall, as soon as practicable following receipt of such notice, notify and change nominations and scheduling with all pipelines and other parties delivering or receiving gas to be delivered to or withdrawn from storage for Customer. Customer shall take all reasonable actions to prevent or minimize any imbalances from occurring. Customer and Company will diligently work to correct any imbalance so caused prior to the end of the applicable balancing period. ARTICLE V POINT(S) OF DELIVERY AND REDELIVERY 5.1 The Point(s) of Delivery for all gas to be tendered by Customer to Company for injection into the Storage Facilities shall be as specified on Exhibit "B" attached hereto, and the maximum daily quantity of gas which Company is obligated to receive from Customer at each individual Point of Delivery shall not exceed the maximum stated thereon. 5.2 The Point(s) of Redelivery for all gas to be tendered by Company to Customer for redelivery pursuant to the terms hereof shall be as specified on Exhibit "B", attached hereto, and the maximum quantities of gas which Company is obligated to redeliver to Customer at each such Point of Redelivery shall not exceed the maximum stated thereon. ARTICLE VI TEEM 6.1 This Contract shall be effective as of the date set forth at the outset hereof and shall continue in full force and effect for a primary term which shall end as of the end of the primary term of the gas storage contracts between Company and firm gas storage customers which contracted for service in Phase I, i.e., such primary term being a period of fifteen (15) years following the initial operation of the Storage Facilities (Phase I). Following the primary term, this Contract shall continue from year to year unless and until terminated effective at the end of said primary term or the end of any year thereafter by either party upon not less than twelve (12) months prior written notice. 6.2 Upon expiration hereof, Company agrees that in the event that gas storage services are still being provided in the Storage Facilities by Company, or any assignee of Company as provided for herein, to other customers, then, Customer shall have the right and option to continue to receive storage services from Company, or such assignee of Company, pursuant to terms and conditions, and for rates and charges substantially similar to those being offered to said other customers by Company, or such assignee of Company, at the time of such expiration. 6 ARTICLE VII RATES 7.1 Commencing as of the Commencement Date, and continuing thereafter for a period ending at the end of the tenth (10th) year following Company's initial operation of the Storage Facilities (in Phase I) (the "Initial Pricing Period"), and thereafter unless adjusted in accordance with the terms hereof, further Customer shall pay to Company each month the following charges: 7.1(a) A storage charge ("D(1)") of twenty and one-half cents ($0.205) multiplied by Customer's MQS amount specified in this Agreement; plus 7.1(b) A deliverability charge ("D(2)") of fifty-eight cents ($0.58) multiplied by Customer's MDWQ amount; plus 7.1(c) One cent ($0.01) for each MMBtu of gas received by Company for injection into storage hereunder and one cent ($0.01) for each MMBtu of gas redelivered by Company to Customer hereunder; plus 7.1(d) Customer's pro-rata share of the cost of gas consumed in the operation of the Storage Facilities, such to be pro rated among all customers based upon the quantities of gas injected and withdrawn by each customer during each month. The parties agree that this cost may change from time to time and Customer shall continue to bear its pro rata share of such cost. Company shall endeavor to operate the Storage Facilities in an efficient manner so as to limit the gas consumed to that quantity reasonably required. Each month, Company shall provide Customer a statement showing its prorata share of such quantity and the cost of the gas consumed in the operation of Storage Facilities, along with the necessary supporting workpapers showing the total quantity and cost of gas so consumed and the proration calculations. Customer shall have the option, exercisable upon thirty (30) days prior written notice at any time during the term hereof, to thereafter (during the term hereof) supply its pro-rata share of gas consumed, as opposed to reimbursing Company in accordance herewith. In the event that Customer elects to provide its pro-rata share of the fuel used hereunder, then, following such election, Company shall establish and maintain an account (the "Fuel Account") with Customer. Initially, one and one-half percent (1 1/2%) of all gas delivered to Company at the Points of Delivery hereunder shall be retained by Company and credited to the Fuel Account. Customer shall not pay any injection, withdrawal or storage fee as to any volumes retained by Company. At the close of each month, Company shall debit the Fuel Account with Customer's pro-rata share of the fuel gas. From time to time during the term hereof, Company shall have the right, upon providing Customer ten (10) days' prior written notice, to adjust the quantity of gas to be retained by Company and credited to the Fuel Account in 7 order to reflect actual quantities of gas consumed in the operation of the Storage Facilities and, to cause the Fuel Account to be as near to zero as is practicable on a monthly basis. Within thirty (30) days following the termination hereof, Company shall deliver gas to Customer, or Customer shall deliver gas to Company, as is necessary to cause the Fuel Account to equal zero. Company shall report the status of the Fuel Account as of the end of the previous month with each monthly statement. Customer shall have the right to deliver to Company the maximum capacities set forth in Section 3.1(iii) in addition to the gas delivered by Customer for credit to the Fuel Account. 7.1(e) The fees payable for each MMBtu of gas delivered to Company for injection and for each MMBtu of gas redelivered to Customer hereunder, as provided for in section 7.1(c), shall be subject to adjustment, upon application to and approval by the appropriate regulatory commission, to reflect increases or decreases in the cost of maintenance, supplies and other variable expenses incurred by Company in performing the services hereunder. Customer shall have the right to contest any increase sought hereunder before the appropriate regulatory commission. No such adjusted fee shall exceed, however: (i) the fee herein provided; multiplied by (ii) the sum of one (1) plus the percentage change in the Gross National Product Implicit Price Deflator (the "Index") for the December of the then-current calendar year as compared to such Index for December, 1990. 7.2 Notwithstanding the above, in the event that Company's rates and charges to its Phase I customers are decreased within the Initial Pricing Period, as described above, then the rates and charges payable hereunder shall also be decreased such that the rates and charges for service hereunder shall equal the rates and charges payable by said customers in Phase I. 7.3 The charges payable hereunder for the remainder of the term hereof following the expiration of the Initial Pricing Period, as described in Section 7.1, may be redetermined by the appropriate regulatory body in accordance with this Section 7.3. Company shall have the right, upon its election, or shall be obligated, upon request of Customer, to submit cost-of-service information to the appropriate regulatory authority for a review of the rates charged hereunder and to request a determination by such regulatory authority of a rate for the remaining term hereof. Customer shall have the right to take part in such proceedings and to contest the proposed rates to the full extent allowed. Company shall provide Customer not less than thirty (30) days prior written notice of Company's intent to file for a new rate as herein provided. In the event that the rates resulting from such redetermination are in excess of one hundred and ten percent (110%) of the rates specified in Section 7.1, then Customer shall have the right to terminate this Contract upon sixty (60) days' prior written notice; provided, however, that during such sixty (60) day period following the 8 receipt of Customer's notice, Company shall have the option, without obligation, to agree to charge Customer rates which do not exceed one hundred and ten percent (110%) of the rates set forth in Section 7.1 and, in such event, this Contract shall continue for the remaining term. Company shall provide Customer written notice of any such election before the expiration of said sixty (60) day period and, shall therein specify the rate to be charged hereunder. ARTICLE VIII NOTICES 8.1 Whenever any notice, request, demand, statement or payment is required or permitted to be given under any provision of this Contract, unless expressly provided otherwise, such shall be in writing, signed by or on behalf of the person giving the same, and shall be deemed to have been given and received upon the actual receipt (including the receipt of a telecopy or facsimile of such notice) at the address of the parties as follows: Company: For Notices: Endevco Industrial Gas Sales Company 8080 N. Central Expressway Twelfth Floor, Lock Box 47 Dallas, Texas 75206 For Payments: Endevco Industrial Gas Sales Company P. 0. Box 97611 Dallas, Texas 75397 Customer: Mississippi Valley Gas Company 711 W. Capital Street Jackson, Mississippi 39203 ATTN: RATE DEPARTMENT 8.2 Operating communications made by telephone or other mutually agreeable means shall be confirmed in writing or by telecopy within two (2) days following same if requested by either party. To facilitate such operating communications on a daily basis, lists of names, telephone and telecopy numbers of appropriate operating personnel shall be exchanged by and between Company and Customer before commencement of service under this Contract. Such lists shall be updated from time to time if changed. 8.3 The addresses of the parties may be revised upon written notice given in accordance herewith, designating in such writing the new address of the party so affected. ARTICLE IX GENERAL TERMS AND CONDITIONS The General Terms and Conditions attached hereto as Exhibit "A" are hereby incorporated herein and made a part of this 9 Contract as if fully set forth herein. Any conflict or inconsistency, either in construction or interpretation, between the terms hereof and the General Terms and Conditions attached hereto shall be resolved in favor of the terms hereof. ARTICLE X MISCELLANEOUS 10.1 Headings. The subject headings of the articles and sections of this Contract are intended for the sole purpose of convenient reference and are not intended, nor shall the same be construed, to be a part of this Contract or considered in any interpretation hereof. 10.2 Amendment. Neither this Contract nor any provisions hereof may ever be amended, changed, modified or supplemented except by an agreement in writing, duly executed by the party to be charged with the same. 10.3 Waiver. No failure by either party to enforce the performance of any obligation of the other party under this Contract shall operate as a waiver of such obligation or default, or as a waiver of any other right or default, whether of a like or different character. 10.4 Choice of Law. As to all matters of construction and interpretation, this Contract shall be interpreted, construed and governed by the laws of the State of Texas. 10.5 Succession. Either party may assign its rights, titles or interests hereunder to any individual, bank, trustee, company or corporation as security for any note, notes, bonds or other obligations or securities of such assignor, but not otherwise, without the written consent of the other party hereto, which consent shall not be unreasonably withheld. No assignment provided for hereunder shall in any way operate to enlarge, alter or change any obligation of the other party hereto nor shall the assignee be relieved of its obligations hereunder without the express written consent of the non-assigning party. 10.6 Right of Examination. Both Company and Customer shall have the right to examine, at any reasonable time, the books, records, charts and any operating data of the other to the extent reasonably necessary to verify the accuracy of any statement, chart or computation made under or pursuant to the provisions of this Contract. All books, records and charts related to any statement, charge or computation made hereunder shall be retained and available for review or inspection for a period of two years. 10.7 Entire Agreement. This Contract contains the entire agreement and understanding of the parties hereto with respect to the subject matter hereof and, there are no agreements, understandings or representations, either oral or in writing, except as set forth herein. 10 10.8 Authority. Company and Customer each hereby represents and warrants that it has the full right, power and authority to enter into this Contract, and that this Contract will not violate the provisions of any other contract or agreement to which it is a party. 10.9 Effect on Prior Storage Contract. The parties hereto are also parties to that certain Gas Storage Contract dated February 21, 1990 providing for storage services in Phase I of the Storage Facilities. The parties acknowledge that the Phase IA expansion made the subject hereof does not affect or implement the adjustments to the fees payable for Phase I services, as set forth in Section 6.2 of such contract; nor does it increase, decrease or otherwise affect Customer's priority rights to contract for additional capacity which may be added to the Storage Facilities by leaching an additional cavern on the properties initially acquired by Company (Phase II) as provided in Section 9.1 of such contract. IN WITNESS WHEREOF, the parties have executed this Contract in one or more copies or counterparts, each of which shall constitute and be an original of this Contract effective between the parties as of the date first-above written. COMPANY: ATTEST: ENDEVCO INDUSTRIAL GAS SALES COMPANY - -s- [ILLEGIBLE] By: -s- [ILLEGIBLE] - -------------------------------- ----------------------------- Assistant Corporate Secretary Its: [ILLEGIBLE] ----------------------------- CUSTOMER: ATTEST: MISSISSIPPI VALLEY GAS COMPANY - -s- [ILLEGIBLE] By: -s- E.R BUTLER - -------------------------------- ----------------------------- Secretary Its: PRES. ----------------------------- 11 EXHIBIT "A" TO GAS STORAGE CONTRACT BETWEEN ENDEVCO INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY DATED AUGUST 24, 1990 GENERAL TERMS AND CONDITIONS These General Terms and Conditions ("General Terms") are attached to and incorporated into the above-referenced GAS STORAGE CONTRACT between ENDEVCO INDUSTRIAL GAS SALES COMPANY (herein referred to as "Company") and MISSISSIPPI VALLEY GAS COMPANY, a Mississippi corporation (herein referred to as "Customer"). ARTICLE I DEFINITIONS For the purposes of this Contract, unless expressly stated otherwise, the following definitions shall be applicable. 1.1 The term "Btu" shall mean British Thermal Units. 1.2 A "day" shall mean the twenty-four (24) hour period beginning at 7:00 a.m. Jackson, Mississippi time on each calendar day and ending at 7:00 a.m. Jackson, Mississippi time on the following calendar day. 1.3 "Contract" shall mean the above-referenced Gas Storage Contract together with these General Terms and all other attachments hereto or thereto. 1.4 The term "gas" shall mean natural gas in its natural state, produced from wells, including casinghead gas produced with crude oil, natural gas from gas wells and residue gas resulting from processing both casinghead gas and gas well gas. 1.5 The term "Mcf" shall mean one thousand (1,000) cubic feet at a pressure of fifteen and twenty-five thousandths (15.025) psia and at a temperature of sixty degrees (60 degrees) Fahrenheit. 1.6 The term "MMBtu" shall mean 1,000,000 Btu. 1.7 A "month" shall mean that period of time beginning at 7:00 a.m. Jackson, Mississippi time on the first day of a calendar month and ending at 7:00 a.m. Jackson, Mississippi time on the first day of the following calendar month; provided, that, the first month hereunder shall commence on the first day of the calendar month in which the Commencement Date occurs, and the last month hereunder shall end on the date that this Contract terminates. General Terms - Page 1 1.8 "Point(s) of Delivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is received by Company for injection into storage. 1.9 "Point(s) of Redelivery" shall mean the point or points, as identified on Exhibit "B" of the Contract, at which gas is tendered by Company to Customer for delivery from storage. 1.10 The term "psia" shall mean pounds per square inch absolute. 1.11 The term "psig" shall mean pounds per square inch gauge. 1.12 "Storage Facilities" shall be as defined in the "WHEREAS" clauses of the Contract. 1.13 The term "year" shall mean a period of twelve (12) consecutive months. ARTICLE II QUALITY The gas delivered by either party to the other hereunder shall meet the quality specifications of the transporting pipeline which receives or delivers such gas at the Point(s) of Delivery or Redelivery and shall, in addition, be of such quality that it shall meet the following specifications, if such standards are more stringent: a. Be commercially free of dust, gum, gum-forming constituents, gasoline, and other solid and/or liquid matter, including but not limited to water, gas treating chemicals and well completion fluids and debris, which may become separated from the gas during transportation thereof. b. Contain not more than one quarter (1/4) grain of hydrogen sulphide per one hundred (100) cubic feet, as determined by the cadmium sulfate quantitative test, nor more than nine (9) grains of total sulfur per one hundred (100) cubic feet. c. The gas delivered hereunder shall not contain more than two-tenths of one percent (0.2%) by volume of oxygen, and shall not contain more than two percent (2%) by volume of carbon dioxide; and shall not contain more than two percent (2%) by volume of nitrogen. d. Have a heating value of not less than nine hundred eighty (980) Btu's per cubic feet. General Terms - Page 2 e. Have a temperature of not more than one hundred twenty degrees Fahrenheit (120 degrees F), nor less than forty degrees Fahrenheit (40 degrees F). f. Have been dehydrated by any method other than the use of a calcium chloride as desiccant, for removal of entrained water in excess of seven (7) pounds of water per million (1,000,000) cubic feet of gas. ARTICLE III PRESSURE Company shall deliver gas to Customer from storage hereunder at pressures sufficient to enter the transporting pipeline's facilities at the Point(s) of Redelivery against the operating pressures maintained in such pipeline from time to time, provided that Company shall not be required to deliver gas at pressures in excess of 960 psig. Customer shall deliver gas to Company for injection at the Point(s) of Delivery at the pressures as may be available from time to time in the transporting pipeline's facilities at such points, but in no event shall such pressures be less than 550 psig or greater than Company's maximum allowable operating pressure. ARTICLE IV TITLE AND RISK OF LOSS 4.1 Title to the natural gas stored by Company and delivered to Customer hereunder shall, at all times, be in Customer and, except as provided in Section 4.2 Company makes no warranty of title whatsoever. Customer warrants for itself, its successors and assigns, that it will have, at the time of delivery, good title or valid right to deliver such gas for storage hereunder. Customer warrants for itself, its successors and assigns, that the gas it delivers hereunder shall be free and clear of all liens, encumbrances, or claims whatsoever; and that it shall indemnify Company and save it harmless from all claims, actions, damages, costs and expenses arising directly or indirectly from or with respect to the title to gas tendered to Company hereunder. 4.2 Company warrants that it shall neither cause nor allow any cloud or encumbrance of any nature to arise by, through or under Company with respect to Customer's title to any gas tendered to Company for storage, and agrees to redeliver such gas pursuant to this Contract free from all liens and adverse claims arising by, through or under Company, and that it will indemnify, defend, protect, and save Customer harmless from all claims, suits, actions, damages, costs and expenses arising directly or indirectly from the same. 4.3 As between Customer and Company: Customer shall be in control and possession of the gas prior to delivery to company for injection at the Point(s) of Delivery and after redelivery by General Terms - Page 3 company to Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Company harmless from any damage or injury caused thereby except for damages and injuries caused by the negligence of Company; and, Company shall be in control and possession of the gas after the receipt of the same for injection at the Point(s) of Delivery and until redelivery by Company to Customer at the Point(s) of Redelivery, and, shall indemnify, defend and hold Customer harmless from any damage or injury caused thereby, except for damages and injuries caused by the negligence of Customer. The risk of loss for all gas injected into, stored in and withdrawn from the Storage Facilities shall be and remain with the party having control and possession of the gas as herein provided. ARTICLE V MEASUREMENT 5.1 The unit of volume for measurement of gas delivered hereunder shall be one (1) cubic foot of gas at a base temperature of sixty degrees Fahrenheit (60 degrees F) and at an absolute pressure of fifteen and twenty-five thousandths (15.025) pounds per square inch. All fundamental constants, observations, records, and procedures involved in determining and/or verifying the quantity and other characteristics of gas delivered hereunder shall, unless otherwise specified herein, be in accordance with the standards prescribed in American Gas Association ("A.G.A.") Gas Measurement Committee Report No. 3, as now and from time to time amended or supplemented. All measurements of gas shall be determined by calculation into terms of such unit. All quantities given herein, unless expressly stated otherwise, are in terms of such unit. Notwithstanding the foregoing, it is agreed that, for all purposes, the Btu content of the gas received and delivered by Company hereunder shall be measured on an "as delivered" basis rather than a fully saturated or "wet" basis. 5.2 Company, at its sole expense, shall install, maintain and operate, or cause to be installed, maintained and operated, the measurement facilities required hereunder. Said measurement facilities shall be so equipped with orifice meters, recording gauges, or other types of meters of standard make and design commonly acceptable in the industry, as to accomplish the accurate measurement of gas delivered hereunder. The changing of charts, calibrating and adjustment of meters shall be done by Company or its agent. 5.3 The accuracy of Company's measuring equipment shall be verified by Company at least once in each thirty (30) day period. If either party desires a special test of any measuring equipment, it will promptly notify the other party and the parties shall then cooperate to secure a prompt verification of the accuracy of such equipment. The expenses of any such special test, if requested by Customer, shall be borne by Customer if the measuring equipment tested is found to be accurate within the limit of plus or minus General Terms - Page 4 two percent (2%) of error. For the purposes of measurement and meter calibration, the atmospheric pressure shall be assumed to be fourteen and seventy-three hundredths (14.73) pounds per square inch, irrespective of variations in natural atmospheric pressure from time to time. Company and Customer, upon request, shall have the right to be present at any test of any measuring equipment, including any check measuring equipment installed by Customer at its sole expense. 5.4 If, upon testing, the metering equipment is found to be inaccurate, in the aggregate, by two percent (2%) or more, either plus or minus, registration thereof and any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half (1/2) of the time elapsed since the day of the last calibration, not exceeding, however, forty-five (45) days. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately; however, if any inaccuracy is less than two percent (2%), all prior readings and measurements shall be deemed to be accurate and no adjustments to any prior reading shall be made. If, for any reason, any meter is registering inaccurately or is out of service or out of repair so that the quantity of gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of gas so delivered during such period shall be estimated and agreed upon by the parties hereto upon the basis of the best available data determined: a. by using the registration of any check measuring equipment, if installed and registering accurately, or in the absence of (a); b. by correcting the error if the percentage of error is ascertainable by calibration, test, or mathematical calculation, or in the absence of both (a) and (b); c. by estimating the quantity of gas deliveries by deliveries during preceding periods under similar conditions when the meter was registering accurately. 5.5 The measurement hereunder shall be corrected for deviation from Boyle's Law at the pressure and temperature under which gas is delivered hereunder. ARTICLE VI BILLINGS AND PAYMENTS 6.1 On or before the tenth (10th) day of each month, Company shall render to Customer a statement for the preceding month properly identifying the applicable Point(s) of Delivery and Point(s) of Redelivery and showing the total quantity of gas received from and delivered to Customer hereunder, the amount due General Terms - Page 5 therefor, the amount of Customer's gas in storage as of the close of such month and information sufficient to explain and support any adjustments made by Company (in accordance with section 6.3 below) in determining the amount billed. 6.2 Customer shall pay Company the full amount reflected on the statements rendered within fifteen (15) days of its receipt of same. If the fifteenth (15th) day shall fall upon a weekend or legal holiday, then such payment shall be made on the first regular business day following such fifteenth (15th) day. In the event that Customer fails to pay such amounts when due, interest shall accrue on all unpaid amounts from the date due until paid at a rate of interest equal to the lesser of: (i) the rate of interest quoted as the "prime rate" of NCNB Texas National Bank -- Dallas, Texas to its largest and most credit-worthy commercial customers; or (ii) the highest legal rate of interest allowed by law. 6.3 In the event an error is discovered in the amount billed in any statement rendered by Company, such error shall be adjusted within thirty (30) days of the discovery of the error. In the event a dispute arises as to the amount payable in any statement rendered, Customer shall pay the amount shown payable to Company in the statement which is not in dispute. Any overcharges collected by Company pursuant to this section 6.3 shall be remitted to Customer, with interest, calculated as provided in section 6.2, from the date such overcharges are received by Company until repaid. Such payment shall not be deemed to be a waiver of the right by Customer to recoup any overpayment. All statements shall be considered final, and any and all objections thereto shall be deemed waived, unless made in writing within twenty-four (24) months of Customer's receipt thereof. ARTICLE VII TAXES 7.1 Subject to the provisions of Section 7.3, Customer agrees to pay to Company, by way of reimbursement, within fifteen (15) days of receipt of an invoice for same (pro-rated among all customers), all new taxes enacted and levied or imposed upon Company after the Commencement Date and, any increases in existing taxes which may be made effective after the Commencement Date, which arise out of the gas storage services provided hereunder. In the event that any additional taxes or increases in taxes are imposed with respect to the storage of gas hereunder and, should Company elect not to challenge the same, then Customer shall be subrogated to Company's rights to challenge same. 7.2 The term "taxes" as used herein, shall mean all taxes which are now in existence or which may in the future be levied upon Company, or its facilities or the storage of gas hereunder and arising out of the gas storage services to be provided hereunder including, but not limited to, street and alley rental tax, licenses, fees and any other taxes, charges or fees of any kind General Terms - Page 6 levied, assessed or made by any governmental authority on the act, right or privilege of transporting, handling or delivering gas or using Company's Storage Facilities, which is measured by the volume, heating value, value of the gas, or any fee in respect to the gas or the storage,transportation or other handling thereof (excluding, however, real property, ad valorem, capital stock, income or excess profit taxes, or general franchise taxes imposed on corporations on account of their corporate existence or on their right to do business within the state as a foreign corporation and similar taxes). 7.3 Customer shall not be obligated to reimburse Company pursuant to Section 7.1 in any year in an amount in excess of five percent (5%) of the cumulative total of the monthly demand charges paid by Customer to Company in such year. In the event that the total of the increases in taxes and additional taxes exceed such five percent (5%) amount, then Company shall have the option of paying the same or of seeking a determination from the appropriate regulatory agency that such additional taxes or increases in taxes are prudent and appropriate for inclusion in Company's rates. Subject to the following provisions, in the event that such regulatory agency determines that such additional and increased taxes including, without limitation, those in excess of said five percent (5%) amount, are appropriate for inclusion, Customer shall have the option of either paying such approved rate increases or terminating this Contract, upon providing Company sixty days' prior written notice; provided, however, that upon receipt of Customer's notice of termination, Company shall have the option, without obligation, to charge Customer an increased amount which does not exceed such five percent (5%) amount and, in such event, Customer's notice of termination shall be of no force or effect and this Contract shall continue in accordance with its terms. Company shall provide Customer written notice of any such election within such sixty (60) day period. Customer shall be given notice and shall have the right to participate in such rate determination and oppose the appropriateness of including the additional or increased taxes in Company's rates. ARTICLE VIII REGULATORY BODIES This Contract is subject to all present and future valid laws and lawful orders of all regulatory bodies now or hereafter having jurisdiction of either or both the parties; and should either of the parties, by force of any such law or regulation imposed at any time during the term of this Contract, be rendered unable, wholly or in part, to carry out its obligations under this Contract, other than Customer's obligation to make payments due hereunder then, this Contract shall continue nevertheless and shall then be deemed modified to conform with the requirements of such law or regulation. Notwithstanding the above, this Contract shall not be deemed to be so modified if such law or regulation substantially and materially prohibits Company from providing services to General Terms - Page 7 Customer hereunder substantially in accordance with the terms set forth in this Contract and, in such event, Company and Customer shall negotiate in good faith to amend the terms of this Contract such that such law or regulation may be complied with and both Company and Customer will continue to receive the rights and benefits herein provided. This Contract is expressly made subject to any and all tariff and other filings made by Company and approved by any federal or state regulatory body provided, that Company will not, without Customer's consent, seek to alter the firm character of the storage services herein provided or to reduce the term of this Contract. In the event that any regulatory body having jurisdiction over this Contract prohibits Company from collecting rates for the services provided hereunder which are at least equal to the rates and charges provided for in this Contract, then Company shall have the right to terminate this Contract. In the event that any regulatory body having jurisdiction requires Company to collect rates for services provided hereunder which are in excess of the rates herein provided, then Customer shall have the right to terminate this Contract. ARTICLE IX FORCE MAJEURE 9.1 In the event of either party hereto being rendered unable, wholly or in part, by force majeure to carry out its obligations under this Contract, other than to make payments hereunder (except as provided in section 9.3 below), the obligations of the party, as 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 as far as possible be remedied with all reasonable dispatch. The party so affected by such event of force majeure shall give written notice, including reasonably full particulars of such force majeure, in writing or by telegraph to the other party as soon as possible but in no event more than ten (10) days after the occurrence of the cause so relied upon. 9.2 The term "force majeure" as employed herein shall mean, without limitation, acts of God, strikes, lockouts, or other industrial disturbances, acts of the public enemy, wars, blockades, insurrection, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrest and restraints of governments and people, civil disturbances, explosions, breakage and/or accidents to machinery or lines or pipe, freezing of lines of pipe, inability to obtain or delay in obtaining rights-of-way, material, supplies, labor or permits, or refusal by pipelines, which are transporting on Customer's behalf, to receive or deliver gas hereunder. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty, and that the above requirements that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of any opposing party when such course is General Terms - Page 8 inadvisable in the discretion of the party having the difficulty. Company shall utilize all reasonable efforts to design, operate and maintain its facilities in a manner which minimizes the potential for freezing of wells or lines of pipe. 9.3 In the event that Company is, due to an event of force majeure, as herein defined, unable to provide storage services, in whole or in part, under this Contract, then the obligation of Customer to make payment of demand charges hereunder shall thereafter be waived or reduced proportionately until service is again made available hereunder. ARTICLE X DEFAULT AND TERMINATION 10.1 If either party hereto shall fail to perform any of the covenants or obligations imposed upon it by virtue of this Contract (except where such failure shall be excused under any of the provisions hereof), then in such event the other party may, at its option, terminate this Contract by proceeding as follows: the party not in default shall cause a written notice to be served upon the party in default, stating specifically the cause for terminating this Contract and declaring it to be the intention of the party giving the notice to terminate the same; whereupon, the party in default shall have thirty (30) days after receipt of the aforesaid notice in which to remedy or remove the cause or causes of default stated in the notice of termination. If, within said period of thirty (30) days, the party in default does so remedy and remove said cause or causes, and fully indemnifies the party not in default, then such notice shall be nullified and this Contract shall continue in full force and effect. In the event the party in default does not so remedy and remove the cause or causes of default, or does not fully indemnify the party giving the notice for such party's actual damages as a result of such default within said period of thirty (30) days, then this Contract shall become null and void from and after the expiration of said period; provided, however, that if such default be remedied but no indemnification therefor has been made due to a bona fide dispute between the parties as to the amount thereof, then this Contract shall not terminate, but the party not in default shall have the right to seek recovery of its actual damages as provided by law. Any termination for breach of this Contract shall be carried out strictly in accordance with this section. Nothing in this Section 10.1 shall be construed to limit in any way the remedies available to either party for breach of this Contract except for the right to terminate. 10.2 Any cancellation of this Contract pursuant to the provisions of this Article X shall be without prejudice to the right of the party not in default to collect any amounts then due it and without waiver of any other remedy to which the party not in default may be entitled. General Terms - Page 9 10.3 In the event of termination, cancellation or expiration of this Contract and, upon such occurrence, there is gas in storage for Customer's account, this Contract shall continue in force and effect for the sole purpose of withdrawal and delivery of and payment for storage services for said gas for an additional ninety (90) days. END OF GENERAL TERMS General Terms - Page 10 EXHIBIT "B" TO GAS STORAGE CONTRACT BETWEEN ENDEVCO INDUSTRIAL GAS SALES COMPANY AND MISSISSIPPI VALLEY GAS COMPANY DATED AUGUST 24,1990
Maximum Quantity POINT(S) OF DELIVERY (In MMBtu's) -------------------- ---------------- Interconnection between the Storage 5,000 Facilities and the pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage 5,000 Facilities and the pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Delivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Delivery shall not exceed the MDIQ stated in the Contract, unless otherwise agreed by Company.
POINT(S) OF DELIVERY (In MMBtu's) -------------------- ------------ Interconnection between the Storage 10,000 Facilities and the pipeline facilities of Transco in Covington County, Mississippi Interconnection between the Storage 10,000 Facilities and the pipeline facilities of Tennessee in Forrest County, Mississippi
Gas may be scheduled for delivery at either or both of the Points of Redelivery, in quantities up to the maximum quantities indicated for each such point, but the cumulative total of deliveries at both Points of Redelivery shall not exceed the MDWQ stated in the Contract, unless otherwise agreed by Company. EX-10.13(J) 19 d10753exv10w13xjy.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(j) TGP-1443 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) THIS AGREEMENT is made and entered into as of the 1st day of September, 1993, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and MISSISSIPPI VALLEY GAS COMPANY, a MISSISSIPPI Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties." ARTICLE I DEFINITIONS 1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof, which shall be 15,000 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit "A" attached hereto. 1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE II TRANSPORTATION Transportation Service - Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas. ARTICLE III POINT(S) OF RECEIPT AND DELIVERY The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit "A" attached hereto. ARTICLE IV All facilities are in place to render the service provided for in this Agreement. 1 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE V QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT For all gas received, transported and delivered hereunder the Parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. To the extent that no new measurement facilities are installed to provide service hereunder, measurement operations will continue in the manner in which they have previously been handled. In the event that such facilities are not operated by Transporter or a downstream pipeline, then responsibility for operations shall be deemed to be Shipper's. ARTICLE VI RATES AND CHARGES FOR GAS TRANSPORTATION 6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges, and surcharges to be paid by Shipper to Transporter for the transportation service provided herein shall be in accordance with Transporter's Rate Schedule FT-A and the General Terms and Conditions of Transporter's FERC Gas Tariff. 6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid for by Shipper, which Transporter incurs in rendering service hereunder. 6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. ARTICLE VII BILLINGS AND PAYMENTS Transporter shall bill and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of Transporter's FERC Gas Tariff. 2 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE VIII GENERAL TERMS AND CONDITIONS This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-A and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC. ARTICLE IX REGULATION 9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 9.2 The transportation service described herein shall be provided subject to Subpart G, Part 284, of the FERC Regulations. ARTICLE X RESPONSIBILITY DURING TRANSPORTATION Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE XI WARRANTIES 11.1 In addition to the warranties set forth in Article IX of the General Terms and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the following: (a) Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each point as specified on Exhibit "A" attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to 3 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Race Schedule) receive or deliver gas as contemplated by this Agreement. (b) Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty by Shipper herein. 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty. ARTICLE XII TERM 12.1 This Agreement shall be effective as of the 1st day of September, 1993, and shall remain in force and effect until the 31st day of August, 2002, ("Primary Term") and on a month to month basis thereafter unless terminated by either Party upon at least thirty (30) days prior written notice to the other Party; provided, however, that if the Primary Term is one year or more, then unless Shipper elects upon one year's prior written notice to Transporter to request a lesser extension term, the Agreement shall automatically extend upon the expiration of the Primary Term for a term of five years and shall automatically extend for successive five year terms thereafter unless Shipper provides notice described above in advance of the expiration of a succeeding term; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. 12.2 Any portions of this Agreement necessary to resolve or cash-out imbalances under this Agreement as required by the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1, shall survive the other parts of this Agreement until such time as such balancing has been accomplished; provided, however, that Transporter notifies Shipper of such imbalance no later than twelve months after the termination of this Agreement. 12.3 This Agreement will terminate automatically upon written notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Tariff. 4 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XIII NOTICE Except as otherwise provided in the General Terms and Conditions applicable to this Agreement, any notice under this Agreement shall be in writing and mailed to the post office address of the Party intended to receive the same, as follows: TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY P.O. Box 2511 Houston, Texas 77252-2511 Attention: Transportation Marketing SHIPPER: NOTICES: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P. O. BOX 3348 JACKSON, MS 39203 Attention: SHERI ROWE BILLING: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P. O. BOX 3348 JACKSON, MS 39203 Attention: SHERI ROWE or to such other address as either Party shall designate by formal written notice to the other. ARTICLE XIV ASSIGNMENTS 14.1 Either Party may assign or pledge this Agreement and all rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligation under this Agreement, assign any of its rights hereunder to a company with which it is affiliated. Otherwise, Shipper shall not assign this Agreement or any of its rights hereunder, except in accord with Article III, Section 11 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 14.2 Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. 5 SERVICE PACKAGE NO. 1443 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XV MISCELLANEOUS 15.1 The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to the doctrines governing choice of law. 15.2 If any provisions of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at either Party's option; and if the severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. 15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas Tariff, no modification of or supplement to the terms and provisions stated in this agreement shall be or become effective until Shipper has submitted a request for change through the TENN-SPEED. 2 System and Shipper has been notified through TENN-SPEED 2 of Transporter's agreement to such change. 15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a part hereof for all purposes. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written. TENNESSEE GAS PIPELINE COMPANY BY: -s- Lawrence G. Williams ---------------------------- Lawrence G. Williams Agent and Attorney-in-Fact MISSISSIPPI VALLEY GAS COMPANY BY: -s- WARREN K. ROGERS ---------------------------- TITLE: Executive Vice President DATE: July 14, 1994 6 EX-10.13(K) 20 d10753exv10w13xky.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(k) TGP-1478 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) THIS AGREEMENT is made and entered into as of the 1st day of November, 1993, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and MISSISSIPPI " VALLEY GAS COMPANY, a MISSISSIPPI Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties." ARTICLE I DEFINITIONS 1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof, which shall be 20,000 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit "A" attached hereto. 1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE II TRANSPORTATION Transportation Service - Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas. ARTICLE III POINT(S) OF RECEIPT AND DELIVERY The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit "A" attached hereto. ARTICLE IV All facilities are in place to render the service provided for in this Agreement. 1 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE V QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT For all gas received, transported and delivered hereunder the Parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. To the extent that no new measurement facilities are installed to provide service hereunder, measurement operations will continue in the manner in which they have previously been handled. In the event that such facilities are not operated by Transporter or a downstream pipeline, then responsibility for operations shall be deemed to be Shipper's. ARTICLE VI RATES AND CHARGES FOR GAS TRANSPORTATION 6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges, and surcharges to be paid by Shipper to Transporter for the transportation service provided herein shall be in accordance with Transporter's Rate Schedule FT-A and the General Terms and Conditions of Transporter's FERC Gas Tariff. 6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid for by Shipper, which Transporter incurs in rendering service hereunder. 6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. ARTICLE VII BILLINGS AND PAYMENTS Transporter shall bill and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of Transporter's FERC Gas Tariff. 2 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE VIII GENERAL TERMS AND CONDITIONS This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-A and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC. ARTICLE IX REGULATION 9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 9.2 The transportation service described herein shall be provided subject to Subpart G, Part 284, of the FERC Regulations. ARTICLE X RESPONSIBILITY DURING TRANSPORTATION Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE XI WARRANTIES 11.1 In addition to the warranties set forth in Article IX of the General Terms and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the following: (a) Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each point as specified on Exhibit "A" attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to 3 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) receive or deliver gas as contemplated by this Agreement. (b) Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty by Shipper herein. 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty. ARTICLE XII TERM 12.1 This Agreement shall be effective as of the 1st day of November, 1993, and shall remain in force and effect for the months of November through the 31st day of March on a yearly basis until the 31st day of March, 2001, ("Primary Term") and on a month to month basis thereafter unless terminated by either Party upon at least thirty (30) days prior written notice to the other Party; provided, however, that if the Primary Term is one year or more, then unless Shipper elects upon one year's prior written notice to Transporter to request a lesser extension term, the Agreement shall automatically extend upon the expiration of the Primary Term for a term of five years and shall automatically extend for successive five year terms thereafter unless Shipper provides notice described above in advance of the expiration of a succeeding term; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. 12.2 Any portions of this Agreement necessary to resolve or cash-out imbalances under this Agreement as required by the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1, shall survive the other parts of this Agreement until such time as such balancing has been accomplished; provided, however, that Transporter notifies Shipper of such imbalance no later than twelve months after the termination of this Agreement. 12.3 This Agreement will terminate automatically upon written notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Tariff. 4 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XIII NOTICE Except as otherwise provided in the General Terms and Condition applicable to this Agreement, any notice under this Agreement shall be in writing and mailed to the post office address of the party intended to receive the same, as follows: TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY P.O. Box 2511 Houston, Texas 77252-2511 Attention: Transportation Marketing SHIPPER: NOTICES: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P. O. BOX 3348 JACKSON, MS 39203 Attention: Rates & Gas Supply BILLING: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P. O. BOX 3348 JACKSON, MS 39203 Attention: Rates & Gas Supply or to such other address as either Party shall designate by formal written notice to the other. ARTICLE XIV ASSIGNMENTS 14.1 Either Party may assign or pledge this Agreement and all rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligation under this Agreement, assign any of its rights hereunder to a company with which it is affiliated. Otherwise, Shipper shall not assign this Agreement or any of its rights hereunder, except in accord with Article III, Section 11 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 14.2 Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. 5 SERVICE PACKAGE NO. 1478 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XV MISCELLANEOUS 15.1 The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to the doctrines governing choice of law. 15.2 If any provisions of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at either Party's option; and if the severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. 15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas Tariff, no modification of or supplement to the terms and provisions stated in this agreement shall be or become effective until Shipper has submitted a request for change through the TENN-SPEED. 2 System and Shipper has been notified through TENN-SPEED 2 of Transporter's agreement to such change. 15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a part hereof for all purposes. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written. TENNESSEE GAS PIPELINE COMPANY By: -s- Lawrence G. Williams --------------------------------- Lawrence G. Williams Agent and Attorney-in-Fact MISSISSIPPI VALLEY GAS COMPANY By: -s- Warren K. Rogers ---------------------------------- TITLE: Executive Vice President DATE: August 19, 1994 6 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) EXHIBIT "A" AMENDMENT #0 TO GAS TRANSPORTATION AGREEMENT DATED November 1, 1993 BETWEEN TENNESSEE GAS PIPELINE COMPANY AND MISSISSIPPI VALLEY GAS COMPANY MISSISSIPPI VALLEY GAS COMPANY EFFECTIVE DATE OF AMENDMENT: November 1, 1993 RATE SCHEDULE: FT-A SERVICE PACKAGE: 1478 SERVICE PACKAGE TQ: 20,000 Dth
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TQ BILLABLE-TQ - ---------------------------------------------------------------------------------------------------------------------------------- 020702 HATTIESBURG - PETAL MISS. STOR CORNERSTONE GAS RESOURCES, INC FORREST MS 01 R 500 20,000 20,000 Total Receipt TQ: 20,000 20,000 020211 TEXAS-GREENWOOD MISS TEXAS GAS TRANSMISSION CORP LEFLORE MS 01 D 800 5,500 5,500 020671 MISSISSIPPI - LAUDERDALE COUNT MISSISSIPPI VALLEY GAS COMPANY LAUDERDALE MS 01 D 500 7,250 7,250 020766 MISSISSIPPI - NEW HOPE SALES MISSISSIPPI VALLEY GAS COMPANY LOWNDES MS 01 D 500 7,250 7,250 Total Delivery TQ: 20,000 20,000 NUMBER OF RECEIPT POINTS AFFECTED: 1 NUMBER OF DELIVERY POINTS AFFECTED: 3
NOTE: EXHIBIT "A" IS A REFLECTION OF THE CONTRACT AND ALL AMENDMENTS AS OF THE AMENDMENT EFFECTIVE DATE. 8 EX-10.13(L) 21 d10753exv10w13xly.txt GAS TRANSPORTATION AGREEMENT EXHIBIT 10.13(l) TGP-5151 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) THIS AGREEMENT is made and entered into as of the 1st day of November, 1993, by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and MISSISSIPPI VALLEY GAS COMPANY, a MISSISSIPPI Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties." ARTICLE I DEFINITIONS 1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each year during the term hereof, which shall be 17,500 dekatherms. Any limitations of the quantities to be received from each Point of Receipt and/or delivered to each Point of Delivery shall be as specified on Exhibit "A" attached hereto. 1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff. ARTICLE II TRANSPORTATION Transportation Service - Transporter agrees to accept and receive daily on a firm basis, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas. ARTICLE III POINT(S) OF RECEIPT AND DELIVERY The Primary Point(s) of Receipt and Delivery shall be those points specified on Exhibit "A" attached hereto. ARTICLE IV All facilities are in place to render the service provided for in this Agreement. 1 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE V QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT For all gas received, transported and delivered hereunder the Parties agree to the Quality Specifications and Standards for Measurement as specified in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. To the extent that no new measurement facilities are installed to provide service hereunder, measurement operations will continue in the manner in which they have previously been handled. In the event that such facilities are not operated by Transporter or a downstream pipeline, then responsibility for operations shall be deemed to be Shipper's. ARTICLE VI RATES AND CHARGES FOR GAS TRANSPORTATION 6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges, and surcharges to be paid by Shipper to Transporter for the transportation service provided herein shall be in accordance with Transporter's Rate Schedule FT-A and the General Terms and Conditions of Transporter's FERC Gas Tariff. 6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid for by Shipper, which Transporter incurs in rendering service hereunder. 6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-A, (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. ARTICLE VII BILLINGS AND PAYMENTS Transporter shall bill and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of Transporter's FERC Gas Tariff. 2 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE VIII GENERAL TERMS AND CONDITIONS This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-A and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC. ARTICLE IX REGULATION 9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations. 9.2 The transportation service described herein shall be provided subject to Subpart G, Part 284, of the FERC Regulations. ARTICLE X RESPONSIBILITY DURING TRANSPORTATION Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1. ARTICLE XI WARRANTIES 11.1 In addition to the warranties set forth in Article IX of the General Terms and Conditions of Transporter's FERC Gas Tariff, Shipper warrants the following: (a) Shipper warrants that all upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each point as specified on Exhibit "A" attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to 3 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) receive or deliver gas as contemplated by this Agreement. (b) Shipper agrees to indemnify and hold Transporter harmless from all suits, actions, debts, accounts, damages, costs, losses and expenses (including reasonable attorneys fees) arising from or out of breach of any warranty by Shipper herein. 11.2 Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty. ARTICLE XII TERM 12.1 This Agreement shall be effective as of the 1st day of November, 1993, and shall remain in force and effect until the 30th day of November 2000, ("Primary Term") and on a month to month basis thereafter unless terminated by either Party upon at least thirty (30) days prior written notice to the other Party; provided, however, that if the Primary Term is one year or more, then unless Shipper elects upon one year's prior written notice to Transporter to request a lesser extension term, the Agreement shall automatically extend upon the expiration of the Primary Term for a term of five years and shall automatically extend for successive five year terms thereafter unless Shipper provides notice described above in advance of the expiration of a succeeding term; provided further, if the FERC or other governmental body having jurisdiction over the service rendered pursuant to this Agreement authorizes abandonment of such service, this Agreement shall terminate on the abandonment date permitted by the FERC or such other governmental body. 12.2 Any portions of this Agreement necessary to resolve or cash-out imbalances under this Agreement as required by the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. 1, shall survive the other parts of this Agreement until such time as such balancing has been accomplished; provided, however, that Transporter notifies Shipper of such imbalance no later than twelve months after the termination of this Agreement. 12.3 This Agreement will terminate automatically upon written notice from Transporter in the event Shipper fails to pay all of the amount of any bill for service rendered by Transporter hereunder in accord with the terms and conditions of Article VI of the General Terms and Conditions of Transporter's FERC Tariff. 4 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XIII NOTICE Except as otherwise provided in the General Terms and Conditions applicable to this Agreement, any notice under this Agreement shall be in writing and mailed to the post office address of the Party intended to receive the same, as follows: TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY P.O. Box 2511 Houston, Texas 77252-2511 Attention: Transportation Marketing SHIPPER: NOTICES: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P.O. BOX 3348 JACKSON, MS 39203 Attention: Rates & Gas Supply BILLING: MISSISSIPPI VALLEY GAS COMPANY 711 W. CAPITOL STREET P.O. BOX 3348 JACKSON, MS 39203 Attention: Rates & Gas Supply or to such other address as either Party shall designate by formal written notice to the other. ARTICLE XIV ASSIGNMENTS 14.1 Either Party may assign or pledge this Agreement and all rights and obligations hereunder under the provisions of any mortgage, deed of trust, indenture, or other instrument which it has executed or may execute hereafter as security for indebtedness. Either Party may, without relieving itself of its obligation under this Agreement, assign any of its rights hereunder to a company with which it is affiliated. Otherwise, Shipper shall not assign this Agreement or any of its rights hereunder, except in accord with Article III, Section 11 of the General Terms and Conditions of Transporter's FERC Gas Tariff. 14.2 Any person which shall succeed by purchase, merger, or consolidation to the properties, substantially as an entirety, of either Party hereto shall be entitled to the rights and shall be subject to the obligations of its predecessor in interest under this Agreement. 5 SERVICE PACKAGE NO. 5151 AMENDMENT NO. 0 GAS TRANSPORTATION AGREEMENT (For Use Under FT-A Rate Schedule) ARTICLE XV MISCELLANEOUS 15.1 The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Texas, without regard to the doctrines governing choice of law. 15.2 If any provisions of this Agreement is declared null and void, or voidable, by a court of competent jurisdiction, then that provision will be considered severable at either Party's option; and if the severability option is exercised, the remaining provisions of the Agreement shall remain in full force and effect. 15.3 Unless otherwise expressly provided in this Agreement or Transporter's Gas Tariff, no modification of or supplement to the terms and provisions stated in this agreement shall be or become effective until Shipper has submitted a request for change through the TENN-SPEED. 2 System and Shipper has been notified through TENN-SPEED 2 of Transporter's agreement to such change. 15.4 Exhibit "A" attached hereto is incorporated herein by reference and made a part hereof for all purposes. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written. TENNESSEE GAS PIPELINE COMPANY By: -s- Lawrence G. Williams --------------------------- Lawrence G. Williams Agent and Attorney-in-Fact MISSISSIPPI VALLEY GAS COMPANY BY: -s- WARREN K. ROGERS --------------------------- TITLE: Executive Vice President DATE: July 14, 1994 EX-12 22 d10753exv12.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES . . . Exhibit 12 Atmos Energy Corporation Computation of Earnings to Fixed Charges
Year Ended September 30 ----------------------------------------------------------------- 2003 2002 2001 2000 1999 ------------- ------------ ------------ ------------- ----------- Income from continuing operations before provision for income taxes and cumulative effect of accounting change $126,371 $ 94,836 $ 89,458 $ 56,237 $ 27,299 per statement of income Add: Portion of rents representative of the interest factor 3,626 3,614 2,917 3,007 3,520 Interest on debt & amortization of debt expense 63,660 59,174 47,011 43,823 37,063 ------------- ------------ ------------ ------------- ----------- Income as adjusted $193,657 $ 157,624 $ 139,386 $ 103,067 $67,882 ============= ============ ============ ============= =========== Fixed charges: Interest on debt & amortization of debt expense (1) $ 63,660 $ 59,174 $ 47,011 $ 43,823 $37,063 Capitalized interest (2) 623 1,272 1,494 - 3,724 Capitalized expenses related to indebtedness (3) - - 4,718 - - Rents 10,878 10,842 8,752 9,020 10,560 Portion of rents representative of the interest factor (4) 3,626 3,614 2,917 3,007 3,520 ------------- ------------ ------------ ------------- ----------- Fixed charges (1)+(2)+(3)+(4) $ 67,909 $ 64,060 $ 56,140 $ 46,830 $44,307 ============= ============ ============ ============= =========== Ratio of earnings to fixed charges 2.85 2.46 2.48 2.20 1.53
EX-21 23 d10753exv21.txt SUBSIDIARIES OF REGISTRANT . . . Exhibit 21 SUBSIDIARIES OF ATMOS ENERGY CORPORATION
State of Percent of Name Incorporation Ownership ---- ------------- --------- ATMOS ENERGY HOLDINGS, INC. Delaware 100% MISSISSIPPI ENERGIES, INC. Mississippi 100% MISSISSIPPI WASTEWATER, INC. Mississippi 100% MISSISSIPPI WATER, INC. Mississippi 100% ATMOS ENERGY SERVICES, LLC Delaware 100% (a limited liability company) (wholly-owned by Atmos Energy Holdings, Inc.) EGASCO, LLC Texas 100% (a limited liability company) (wholly-owned by Atmos Energy Holdings, Inc.) ENERGAS ENERGY SERVICES TRUST Pennsylvania 100% (a business trust) (wholly-owned by Atmos Energy Services, LLC) UNITED CITIES PROPANE GAS, INC. Tennessee 100% (a wholly-owned subsidiary of Atmos Energy Holdings, Inc.) ENERMART ENERGY SERVICES TRUST (a business trust) Pennsylvania 100% (wholly-owned by Atmos Energy Holdings, Inc.) ATMOS ENERGY MARKETING, LLC Delaware 100% (a limited liability company) (wholly-owned by Atmos Energy Holdings, Inc.) ATMOS POWER SYSTEMS, INC. Georgia 100% (a wholly-owned subsidiary of Atmos Energy Holdings, Inc.) ATMOS PIPELINE AND STORAGE, LLC Delaware 100% (a limited liability company) (wholly-owned by Atmos Energy Holdings, Inc.)
State of Percent of Name Incorporation Ownership ---- ------------- --------- UCG STORAGE, INC. Delaware 100% (wholly-owned by Atmos Pipeline and Storage, LLC) WKG STORAGE, INC. Delaware 100% (wholly-owned by Atmos Pipeline and Storage, LLC) ATMOS EXPLORATION AND PRODUCTION, INC. Delaware 100% (wholly-owned by Atmos Pipeline and Storage, LLC) TRANS LOUISIANA INDUSTRIAL GAS COMPANY, INC. Delaware 100% (wholly-owned by Atmos Energy Marketing, LLC) WOODWARD MARKETING, LLC Delaware 100% (a limited liability company) (wholly-owned by Atmos Energy Marketing, LLC) SOUTHERN RESOURCES, INC. Kentucky 100% (wholly-owned by Woodward Marketing, LLC) TRANS LOUISIANA GAS PIPELINE, INC. Louisiana 100% (wholly-owned by Atmos Pipeline and Storage, LLC) TRANS LOUISIANA GAS STORAGE, INC. Delaware 100% (wholly-owned by Atmos Pipeline and Storage, LLC)
Effective October 1, 2003, Southern Resources, Inc. was merged with and into Woodward Marketing, L.L.C., Trans Louisiana Industrial Gas Company, Inc. was merged with and into Atmos Energy Marketing, LLC, Atmos Energy Marketing, LLC was merged with and into Woodward Marketing, L.L.C., and Woodward Marketing, L.L.C. was renamed Atmos Energy Marketing, LLC. Also, after its sale to a third party effective October 1, 2003, Mississippi Wastewater, Inc. is no longer a subsidiary of the Company. EX-23 24 d10753exv23.txt CONSENT OF ERNST & YOUNG LLP Exhibit 23 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in the Registration Statements (Form S-3, No. 33-37869; Form S-3 D/A, No. 33-70212; Form S-3, No. 33-58220; Form S-3, No. 33-56915; Form S-3/A, No. 333-03339; Form S-3/A, No. 333-32475; Form S-3/A, No. 333-50477; Form S-3/A, No. 333-93705; Form S-3, No. 333-95525; Form S-3, No. 333-75576; Form S-4, No. 333-13429; Form S-8, No. 33-68852; Form S-8, No. 33-57687; Form S-8, No. 33-57695; Form S-8, No. 333-32343; Form S-8, No. 333-46337; Form S-8, No. 333-73143; Form S-8, No. 333-73145; Form S-8, No. 333-63738; and Form S-8, No. 333-88832) of Atmos Energy Corporation and in the related Prospectuses of our report dated November 10, 2003, with respect to the consolidated financial statements and schedule of Atmos Energy Corporation included in this Annual Report (Form 10-K) for the year ended September 30, 2003. ERNST & YOUNG LLP Dallas, Texas November 19, 2003 EX-31 25 d10753exv31.txt CERTIFICATIONS BY CEO & CFO - SECTION 302 EXHIBIT 31 CERTIFICATIONS I, Robert W. Best, certify that: 1. I have reviewed this annual report on Form 10-K of Atmos Energy Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors: a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 21, 2003 By: /s/ ROBERT W. BEST --------------------------- Robert W. Best Chairman, President and Chief Executive Officer I, John P. Reddy, certify that: 1. I have reviewed this annual report on Form 10-K of Atmos Energy Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors: a) All significant deficiencies or material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 21, 2003 By: /s/ JOHN P. REDDY ------------------------------- John P. Reddy Senior Vice President and Chief Financial Officer EX-32.1 26 d10753exv32w1.txt CERTIFICATION BY CEO - SECTION 906 EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert W. Best, Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ ROBERT W. BEST - --------------------------- Robert W. Best Chairman, President and Chief Executive Officer November 21, 2003 EX-32.2 27 d10753exv32w2.txt CERTIFICATION BY CFO - SECTION 906 EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, John P. Reddy, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ JOHN P. REDDY - --------------------------- John P. Reddy Senior Vice President and Chief Financial Officer November 21, 2003 EX-99 28 d10753exv99.txt ANNUAL CERTIFICATION - SECTION 303A.12 EXHIBIT 99 November 20, 2003 BY: FEDERAL EXPRESS - -------------------- Ms. Cathy Ruggiero Corporate Governance New York Stock Exchange, Inc. 20 Broad Street 17th Floor New York, New York 10005 Re: Annual Certification Dear Ms. Ruggiero: Pursuant to Section 303A.12 of the New York Stock Exchange Listed Company Manual, on behalf of Atmos Energy Corporation (the "Company"), as Chairman, President and Chief Executive Officer of the Company, I am hereby certifying to the New York Stock Exchange (the "NYSE") that as of this date, I am unaware of any violation by the Company of the NYSE corporate governance listing standards. Very truly yours, /s/ ROBERT W. BEST Robert W. Best -----END PRIVACY-ENHANCED MESSAGE-----