UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended September 30, 2004 | ||
OR | ||
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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
75-1743247
(State or other jurisdiction of
incorporation or organization)
(IRS employer
identification no.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal executive
offices)
75240
(Zip code)
Registrants telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
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Common stock, No Par Value
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
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 þ No o
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 registrants 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. o
Indicate by check whether the recipient is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o
The aggregate market value of the voting stock held by non-affiliates of the registrant was $1,265,996,935 as of March 31, 2004. On March 31, 2004 the registrant had 52,235,980 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 9, 2005 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 other natural gas nonutility businesses. As of September 30, 2004 we distributed 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 covered service areas in 12 states. Our primary service areas are located in Colorado, Kansas, Kentucky, Louisiana, Mississippi, Tennessee and Texas. We have more limited service areas in Georgia, Illinois, Iowa, Missouri and Virginia. In addition, we transport natural gas for others through our distribution system.
Through our nonutility businesses, we provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers in 18 states. We own or hold an interest in natural gas storage fields in Kentucky and Louisiana that we use to supply natural gas to our customers.
TXU Gas Acquisition
On October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas). The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas. The TXU Gas acquisition makes us one of the largest publicly-traded companies in the United States whose primary business is the transmission and distribution of natural gas and the provision of related services. It also makes us one of the largest intrastate pipeline operators in Texas.
The purchase price for the TXU Gas acquisition was approximately $1.905 billion (after preliminary closing adjustments), which we paid in cash. We acquired approximately $121 million of working capital of TXU Gas and did not assume any indebtedness of TXU Gas in connection with the acquisition. TXU Gas provided for the repayment of all of its indebtedness and redeemed all of its preferred stock prior to closing and retained and agreed to pay certain other liabilities under the terms of the acquisition agreement. The purchase price is subject to further adjustment sixty days after closing for the actual amount of working capital we acquired and other specified matters. We anticipate that any post-closing purchase price adjustments will not be material.
We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of 9,939,393 shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. In October 2004, we paid off the commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004 which generated net proceeds of approximately $1.39 billion and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of approximately $382.5 million before other offering costs. As a result of this refinancing, we canceled the senior unsecured revolving bridge credit facility.
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Operating Segments
Our operations are currently 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 nonutility segment, which includes all of our other nonutility operations. |
Financial information relating to our operating segments is contained in Note 17 to the consolidated financial statements.
Strategy
Our overall strategy is to:
| integrate the operations of TXU Gas that we acquired | |
| improve the quality and consistency of earnings growth, while operating our natural gas utility and nonutility businesses exceptionally well; and | |
| enhance and strengthen a culture built on our core values. |
Over the last five years, we have grown through several acquisitions, including our acquisition in April 2001 of the remaining 55 percent interest in Woodward Marketing, L.L.C. that we did not already own, our acquisition in July 2001 of the assets of Louisiana Gas Service Company, our acquisition in December 2002 of Mississippi Valley Gas Company and our acquisition in October 2004 of the natural gas distribution and pipeline operations of TXU Gas.
We have experienced over 20 consecutive years of increasing dividends and earnings growth after giving effect to our acquisitions. We have achieved this record of growth while operating our utility operations efficiently by managing our operating and maintenance expenses, 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 increase and mitigating weather-related risks through weather-normalized rates in many of our service areas. Additionally, we have strengthened our nonutility business by ceasing speculative trading activities, increasing gross profit margins and actively pursuing opportunities to increase the amount of storage available to us.
Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We are strengthening our culture through ongoing communication with our employees and enhanced employee training.
Utility Segment Overview
At September 30, 2004, we operated our utility segment through the following six regulated natural gas utility divisions:
| Atmos Energy Colorado-Kansas Division, | |
| Atmos Energy Kentucky Division, | |
| Atmos Energy Louisiana Division, | |
| Atmos Energy Mid-States Division, | |
| Atmos Energy Texas Division (now known as the Atmos Energy West Texas Division) and | |
| Mississippi Valley Gas Company Division |
On October 1, 2004, we created the Atmos Energy Mid-Tex Division which represents the TXU Gas natural gas distribution operations we acquired as well as the Atmos Pipeline Texas Division which
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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 effect of weather that is above or below
normal are partially offset through weather normalization
adjustments, or WNA, in certain of our 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,
2004 we had, or had received regulatory approvals for, WNA in
the following service areas for the following periods, which
covered approximately 1.1 million of our meters in service:
November April
October May
November May
November April
October May
October May
October May
October May
(1) | Effective beginning in the 2004-2005 winter heating season. |
(2) | Effective beginning in April 2004. |
The TXU Gas operations we acquired do not have WNA. However, their operations benefit from a rate structure that combines a monthly customer charge with a declining block rate schedule to mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provides for the recovery of most of our fixed costs for such operations under most weather conditions.
We receive gas deliveries for our six historical divisions through 37 pipeline transportation companies, both interstate and intrastate, to satisfy our natural gas needs. 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.
We purchase our gas supply for our six historical divisions 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. Major suppliers for our historical operations during fiscal 2004 were Anadarko Energy Services, BP Energy Company, ChevronTexaco Natural Gas, Duke Energy Trading and Marketing, Enbridge Marketing (US) L.P., Pioneer Natural Resources, Prior
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The natural gas supply for our new Mid-Tex Division, formed from the TXU Gas operations we acquired, is delivered by the natural gas transmission and storage operations that we also acquired in the TXU Gas acquisition. This natural gas supply generally consists of a combination of base load, peaking and spot purchase agreements, as well as withdrawals of gas in storage held under gas storage capacity agreements. We estimate that the gas demand for the Mid-Tex Division for the upcoming winter heating season, assuming normal weather conditions, is approximately 113.0 Bcf. We have existing purchase agreements to cover a total gas demand of up to approximately 140.3 Bcf, consisting of approximately 40.5 Bcf under base load purchase agreements, up to approximately 47.2 Bcf under peaking purchase agreements, up to approximately 36.9 Bcf under spot purchase agreements and approximately 15.7 Bcf in storage. We anticipate that by the end of November 2004, additional amounts of gas totaling up to approximately 13.9 Bcf will be available under newly completed base load and peaking agreements and additional available gas in storage. The mixture of base load, peaking and spot purchase agreements, coupled with the withdrawal of storage gas, allows us the flexibility to adjust to changes in weather without requiring us to agree to excessive firm commitments. We anticipate that the natural gas supply for the upcoming winter heating season will consist of, in addition to withdrawals of gas in storage, a variety of suppliers, including independent producers, marketers and pipeline companies.
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. Our estimate of natural gas demand for our Mid-Tex division is not necessarily indicative of our ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering, storage and transmission systems, the duration and severity of cold weather, the availability of gas reserves from our suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Curtailment rights provide us flexibility to meet the human-needs requirements of our customers on a firm basis. Priority allocations imposed by federal and state regulatory agencies, as well as other factors beyond our control, may affect our ability to meet the demands of our customers.
We also contract for storage service in underground storage facilities on many of the interstate pipelines serving us.
We estimate the peak-day availability of natural gas supply from long-term contracts, short-term contracts and withdrawals from underground storage to be approximately 4.2 Bcf, including approximately 2.2 Bcf associated with the TXU Gas operations we acquired. The peak-day demand for our historical operations in fiscal 2004 was on January 6, 2004, when sales to customers reached approximately 1.8 Bcf. The peak-day demand for the TXU Gas operations in the 12 months ended September 30, 2004 was also on January 6, 2004 when sales to customers reached approximately 1.6 Bcf.
The following is a brief description of our six natural gas utility divisions as well as the Mid-Tex Division acquired in October 2004. Additional information for our six natural gas utility divisions we operated at September 30, 2004 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 states 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 is effective October through May of each year. Colorado Interstate Gas Company, Southern Star Central Pipeline, Public Service Company of Colorado and Northwest Pipeline are the principal transporters of the Colorado-Kansas Divisions gas supply requirements. Additionally, the Colorado-Kansas Division purchases substantial volumes from producers that are connected directly to its distribution system.
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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 will operate under a performance-based rate program through 2006. 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 Divisions gas supply is delivered primarily by Texas Gas Transmission LLC, Tennessee Gas Pipeline Company, Trunkline Gas Company and Midwestern Pipeline.
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 and are recognized in our natural gas marketing segment. Louisiana Intrastate Gas Company, Acadian Pipeline, Trans Louisiana Gas Pipeline, Inc., Gulf South and Texas Gas Transmission LLC pipelines provide most of the Louisiana Divisions 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 states public service commission. We operate 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. Beginning in July 2005, we will have WNA in Virginia that will cover the entire year. 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 West Texas Division. Our West Texas Division, formerly known as the Atmos Energy 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. During 2004, the West Texas Division received approval from the City of Lubbock, Texas and the 66 cities in our West Texas system, for WNA in these service areas, which will be effective October through May of each year, beginning with the 2004-2005 winter heating season. We also have WNA in our Amarillo service area. Our West Texas Division receives transportation service from ONEOK Pipeline. In addition, the West 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 divisions 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.
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Atmos Energy Mid-Tex Division. Our Mid-Tex Division, which represents the assets and operations that we acquired from TXU Gas on October 1, 2004, includes natural gas distribution operations that operate in the north-central, eastern and western parts of Texas and natural gas transmission and storage operations. This division purchases, distributes and sells natural gas to approximately 1.5 million residential and business customers in approximately 550 cities and towns, including the 11-county Dallas/ Fort Worth metropolitan area. Under a May 2004 rate filing, this division operates under a system-wide rate jurisdiction with the pipeline operations we acquired in the acquisition. Similar to our West Texas Division, the governing body of each municipality served through this division 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 Texas Railroad Commission has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality. This division does not have WNA. However, our operations benefit from a rate structure that mitigates the impact of warmer-than-normal weather on revenue. The majority of this divisions residential and business customers use natural gas for heating, and their needs are directly affected by the mildness or severity of the heating season.
The natural gas transmission and storage operations that we acquired in the TXU Gas acquisition, which will be operated in the Atmos Pipeline Texas Division, also transport natural gas to third parties and represent one of the largest intrastate pipeline operations in Texas. These operations include interconnected natural gas transmission lines, five underground storage reservoirs (including a salt dome facility), 24 compressor stations and related properties, all within Texas. These operations may create additional gas marketing and other opportunities for our non-regulated subsidiaries.
The gas distribution and transmission lines we acquired have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. In addition to being heavily concentrated in the established natural gas-producing areas of central, northern and eastern Texas, the intrastate pipeline system we acquired also extends into or near the major producing areas of the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are estimated to contain a substantial portion of the nations remaining onshore natural gas reserves. This pipeline system provides access to all of these basins. We believe that we are well situated to receive large volumes into this pipeline system at the major hubs, such as Katy, Waha and Carthage as well as from storage facilities where we maintain high delivery capabilities.
At closing of the acquisition, TXU Gas and some of its affiliates entered into transitional services agreements with us to provide call center, meter reading, customer billing, collections, information reporting, software, accounting, treasury, administrative and other services to the Mid-Tex Division. The initial term of each of these agreements will expire on October 1, 2005. Any particular service may be terminated during the initial term on 90 days notice, except for call center, customer billing, collections, information reporting, administrative and other services provided under our agreement with TXU Gas, which may not be terminated during the initial term. After the initial term, all of the service agreements continue on a month-to-month basis until canceled by either party with at least 30 days prior written notice. In addition, we have an option to extend the business services provided during the initial term by TXU Gas for a period of six months beyond the initial term, so long as we exercise our option at least 120 days before the expiration of the initial term. The agreements require us to pay the service providers costs for the services.
However, on November 4, 2004, we entered into an agreement with Capgemini Energy L.P. pursuant to which we will assume the operations of the Waco, Texas call center on April 1, 2005 and will close the purchase of the related assets on October 1, 2005. In connection therewith, all call center services provided by TXU Gas under the transitional services agreement will terminate on April 1, 2005.
Also at closing, we entered into a transitional access agreement with TXU Gas and some of its affiliates in order to allow the parties the same level of access to certain properties, facilities, software applications and other items that they were provided prior to the closing. The initial term of this agreement also expires on
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In connection with the TXU Gas acquisition, we acquired the franchises held by TXU Gas to provide natural gas utility services to cities, towns and other municipalities in Texas. As part of the TXU Gas acquisition, we determined, on the basis of representations and warranties in the acquisition agreement and our diligence, that we needed the consent of two such cities for the acquisition of their franchises and we received the necessary consents prior to closing. However, we have received letters from two other cities, including the City of Dallas, raising the issue of whether, under the terms of their franchises, we should have also obtained their consents. We are currently in discussions with the City of Dallas on this issue. As these discussions are at an early stage, we cannot predict the outcome, but one alternative suggested by the City of Dallas is that we consider renewing our non-exclusive franchise with the City of Dallas prior to its 2009 expiration date. We do not currently know what changes, if any, the City of Dallas might propose in the terms of the franchise, were we to agree to an early renewal, or whether the City of Dallas will take other action with respect to the franchise, were we not to do so. However, we believe that the costs to us associated with a renewal would not be material. We have not received any similar inquiries from other cities, towns or municipalities, but we cannot be certain that we will not receive similar inquiries in the future.
Natural Gas Marketing Segment Overview
Our natural gas marketing and other nonutility segments, which are organized under Atmos Energy Holdings, Inc. (AEH), 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 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. We use proprietary and customer-owned transportation and storage assets to provide the various services our customers request. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues for services we deliver.
We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we participate in natural gas storage transactions in which we seek to capture the pricing differences that occur over time. We purchase or sell physical natural gas and then sell or purchase financial contracts at a price sufficient to cover our carrying costs and provide a gross profit margin. Through the use of transportation and storage services and derivatives, we are able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
AEMs 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, 2004, Atmos Energy Marketing had a total of 638 industrial customers and 80 municipal customers. Atmos Energy Marketing 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.
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Other Nonutility Segment Overview
Our other nonutility segment consists primarily of the operations of Atmos Pipeline and Storage, L.L.C. and Atmos Energy Services, LLC, which are wholly-owned by our subsidiary, Atmos Energy Holdings, Inc. Through Atmos Pipeline and Storage, we own or have an interest in underground storage fields in Kentucky and Louisiana. Atmos Pipeline and Storages underground storage fields in Kansas were transferred to our Atmos Energy Colorado-Kansas utility division during fiscal 2004. Atmos Pipeline and Storage provides storage services to our customers and captures pricing arbitrage through the use of derivatives. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.
Through Atmos Energy Services, we provide natural gas management services to our utility operations. Prior to the second quarter of fiscal 2004, this entity conducted limited operations. However, beginning April 1, 2004, Atmos Energy Services began providing natural gas supply management services to our utility operations in a limited number of states. These services include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices. We have expanded these services to substantially all of our utility service areas as of the end of fiscal 2004.
Through January 20, 2004, United Cities Propane Gas, Inc., a wholly-owned subsidiary of Atmos Energy Holdings, Inc., owned an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies to own a limited partnership interest in Heritage Propane Partners, L.P. (Heritage), a publicly-traded marketer of propane through a nationwide retail distribution network. During fiscal 2004, we sold our interest in USP and Heritage. As a result of these transactions, we no longer have an interest in the propane business.
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Operating Statistics
The following tables present certain operating statistics for our historical utility, natural gas marketing and other nonutility segments for each of the five fiscal years from 2000 through 2004. These tables do not include data for the Mid-Tex Division acquired on October 1, 2004. However, note that based upon the number of meters in service in the Mid-Tex Division, approximately 90 percent of its customers are classified as residential, with approximately 9 percent commercial and industrial, which is substantially similar to that of our other six divisions.
Utility Sales and Statistical Data |
Year Ended September 30 | ||||||||||||||||||||||
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2004 | 2003 (1) | 2002 | 2001 (1) | 2000 | ||||||||||||||||||
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METERS IN SERVICE, end of year
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Residential
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1,506,777 | 1,498,586 | 1,247,247 | 1,243,625 | 970,873 | |||||||||||||||||
Commercial
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151,381 | 151,008 | 122,156 | 122,274 | 104,019 | |||||||||||||||||
Industrial
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2,436 | 3,799 | 2,118 | 1,838 | 1,878 | |||||||||||||||||
Agricultural
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8,397 | 9,514 | 10,576 | 11,182 | 12,381 | |||||||||||||||||
Public authority and other
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10,145 | 9,891 | 7,244 | 7,404 | 7,448 | |||||||||||||||||
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Total meters
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1,679,136 | 1,672,798 | 1,389,341 | 1,386,323 | 1,096,599 | |||||||||||||||||
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HEATING DEGREE DAYS
(2)
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Actual (weighted average)
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3,271 | 3,473 | 3,368 | 4,124 | 2,096 | |||||||||||||||||
Percent of normal
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96% | 101% | 94% | 115% | 82% | |||||||||||||||||
UTILITY SALES VOLUMES
MMcf
(3)
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Gas Sales Volumes
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Residential
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92,208 | 97,953 | 77,386 | 79,000 | 63,285 | |||||||||||||||||
Commercial
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44,226 | 45,611 | 35,796 | 36,922 | 30,707 | |||||||||||||||||
Industrial
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22,330 | 23,738 | 14,499 | 19,243 | 18,546 | |||||||||||||||||
Agricultural
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4,642 | 7,884 | 10,988 | 7,070 | 1,412 | |||||||||||||||||
Public authority and other
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9,813 | 9,326 | 5,875 | 6,892 | 5,520 | |||||||||||||||||
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Total gas sales volumes
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173,219 | 184,512 | 144,544 | 149,127 | 119,470 | |||||||||||||||||
Utility transportation volumes
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87,746 | 70,159 | 69,589 | 69,492 | 77,767 | |||||||||||||||||
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Total utility throughput
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260,965 | 254,671 | 214,133 | 218,619 | 197,237 | |||||||||||||||||
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UTILITY OPERATING REVENUES
(000s)
(3)
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Gas Sales Revenues
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Residential
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$ | 923,773 | $ | 873,375 | $ | 535,981 | $ | 788,902 | $ | 405,552 | ||||||||||||
Commercial
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400,704 | 367,961 | 221,728 | 342,945 | 176,712 | |||||||||||||||||
Industrial
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155,336 | 151,969 | 70,164 | 120,770 | 90,966 | |||||||||||||||||
Agricultural
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31,851 | 48,625 | 37,951 | 28,753 | 6,178 | |||||||||||||||||
Public authority and other
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77,178 | 65,921 | 31,731 | 58,539 | 27,198 | |||||||||||||||||
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Total utility gas sales revenues
|
1,588,842 | 1,507,851 | 897,555 | 1,339,909 | 706,606 | |||||||||||||||||
Transportation revenues
|
31,714 | 30,461 | 28,786 | 28,750 | 28,726 | |||||||||||||||||
Other gas revenues
|
17,172 | 15,770 | 11,185 | 11,489 | 4,619 | |||||||||||||||||
|
|
|
|
|
||||||||||||||||||
Total utility operating revenues
|
$ | 1,637,728 | $ | 1,554,082 | $ | 937,526 | $ | 1,380,148 | $ | 739,951 | ||||||||||||
|
|
|
|
|
||||||||||||||||||
Utility average transportation revenue per Mcf
|
$ | 0.36 | $ | 0.43 | $ | 0.41 | $ | 0.41 | $ | 0.37 | ||||||||||||
Utility average cost of gas per Mcf sold
|
$ | 6.55 | $ | 5.76 | $ | 3.87 | $ | 6.82 | $ | 3.67 | ||||||||||||
Employees
(4)
|
2,243 | 2,313 | 1,766 | 1,819 | 1,488 |
See footnotes following these tables.
9
Utility Sales and Statistical Data By Division (5) |
Year Ended September 30, 2004 | ||||||||||||||||||||||||||||||
|
||||||||||||||||||||||||||||||
Colorado- | Mid- | West | ||||||||||||||||||||||||||||
Kansas | Kentucky | Louisiana | States | Texas | Mississippi | Total Utility | ||||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
METERS IN SERVICE
|
||||||||||||||||||||||||||||||
Residential
|
205,028 | 159,214 | 348,390 | 274,662 | 270,854 | 248,629 | 1,506,777 | |||||||||||||||||||||||
Commercial
|
19,190 | 18,077 | 22,754 | 36,187 | 25,818 | 29,355 | 151,381 | |||||||||||||||||||||||
Industrial
|
85 | 409 | | 712 | 548 | 682 | 2,436 | |||||||||||||||||||||||
Agricultural
|
295 | | | | 8,102 | | 8,397 | |||||||||||||||||||||||
Public authority and other
|
1,757 | 1,655 | 931 | 880 | 2,158 | 2,764 | 10,145 | |||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
Total
|
226,355 | 179,355 | 372,075 | 312,441 | 307,480 | 281,430 | 1,679,136 | |||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
HEATING DEGREE DAYS
(2)
|
||||||||||||||||||||||||||||||
Actual
|
5,490 | 4,283 | 1,515 | 3,631 | 3,252 | 2,734 | 3,271 | |||||||||||||||||||||||
Percent of normal
|
99% | 98% | 93% | 95% | 101% | 90% | 96% | |||||||||||||||||||||||
SALES VOLUMES
MMcf
(3)
|
||||||||||||||||||||||||||||||
Gas Sales Volumes
|
||||||||||||||||||||||||||||||
Residential
|
16,271 | 10,980 | 14,997 | 17,257 | 18,402 | 14,301 | 92,208 | |||||||||||||||||||||||
Commercial
|
6,093 | 4,865 | 6,699 | 12,502 | 6,953 | 7,114 | 44,226 | |||||||||||||||||||||||
Industrial
|
304 | 1,713 | | 7,852 | 3,393 | 9,068 | 22,330 | |||||||||||||||||||||||
Agricultural
|
526 | | | | 4,116 | | 4,642 | |||||||||||||||||||||||
Public authority and other
|
1,491 | 1,451 | 814 | 249 | 2,157 | 3,651 | 9,813 | |||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
Total
|
24,685 | 19,009 | 22,510 | 37,860 | 35,021 | 34,134 | 173,219 | |||||||||||||||||||||||
Transportation Volumes
|
8,879 | 27,059 | 7,073 | 22,001 | 20,579 | 2,155 | 87,746 | |||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
Total Throughput
|
33,564 | 46,068 | 29,583 | 59,861 | 55,600 | 36,289 | 260,965 | |||||||||||||||||||||||
|
|
|
|
|
|
|
||||||||||||||||||||||||
OPERATING REVENUES
(000s)
(3)
|
$ | 220,486 | $ | 195,116 | $ | 265,708 | $ | 379,887 | $ | 301,667 | $ | 274,864 | $ | 1,637,728 | ||||||||||||||||
OTHER STATISTICS, at year end
|
||||||||||||||||||||||||||||||
Miles of pipe
|
6,405 | 3,851 | 8,063 | 7,878 | 15,125 | 6,294 | 47,616 | |||||||||||||||||||||||
Employees
(4)
|
278 | 239 | 431 | 427 | 349 | 519 | 2,243 |
See footnotes following these tables.
10
Year Ended September 30, 2003
Colorado-
Mid-
West
Kansas
Kentucky
Louisiana
States
Texas
Mississippi
Total Utility
199,853
159,024
346,866
274,025
271,198
247,620
1,498,586
18,759
18,077
22,843
35,889
26,228
29,212
151,008
36
406
729
933
1,695
3,799
413
9,101
9,514
1,584
1,661
930
750
2,208
2,758
9,891
220,645
179,168
370,639
311,393
309,668
281,285
1,672,798
5,704
4,364
1,735
3,843
3,487
2,243
3,473
101%
101%
106%
101%
97%
101%
101%
17,419
12,700
16,066
18,780
20,091
12,897
97,953
6,506
5,442
6,841
13,106
7,448
6,268
45,611
313
2,613
8,332
4,149
8,331
23,738
858
7,026
7,884
1,233
1,559
867
277
2,342
3,048
9,326
26,329
22,314
23,774
40,495
41,056
30,544
184,512
9,615
24,848
7,960
20,011
5,671
2,054
70,159
35,944
47,162
31,734
60,506
46,727
32,598
254,671
$
206,653
$
177,613
$
261,896
$
374,725
$
274,520
$
258,675
$
1,554,082
6,341
3,840
7,952
7,790
13,261
6,083
45,267
275
237
450
453
341
557
2,313
See footnotes following these tables.
11
Natural Gas Marketing and Other Nonutility Operations Sales and Statistical Data |
Year Ended September 30 | ||||||||||||||||||||||
|
||||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||||||||
|
|
|
|
|
||||||||||||||||||
CUSTOMERS, end of year
|
||||||||||||||||||||||
Industrial
(6)
|
638 | 644 | 641 | 531 | | |||||||||||||||||
Municipal
(6)
|
80 | 94 | 101 | 68 | | |||||||||||||||||
Other
(6)
|
237 | 202 | 117 | 125 | | |||||||||||||||||
|
|
|
|
|
||||||||||||||||||
Total
|
955 | 940 | 859 | 724 | | |||||||||||||||||
|
|
|
|
|
||||||||||||||||||
NATURAL GAS MARKETING SALES
VOLUMES MMcf
(3)(6)
|
265,090 | 294,785 | 273,692 | 98,869 | | |||||||||||||||||
PROPANE Gallons
(000s)
(7)
|
| | | | 19,329 | |||||||||||||||||
OPERATING REVENUES
(000s)
(3)
|
||||||||||||||||||||||
Natural gas marketing
|
$ | 1,618,602 | $ | 1,668,493 | $ | 1,031,874 | $ | 447,096 | $ | 929 | ||||||||||||
Other nonutility
|
23,151 | 21,630 | 24,705 | 59,436 | 95,376 | |||||||||||||||||
Propane revenues
(7)
|
| | | | 22,550 | |||||||||||||||||
|
|
|
|
|
||||||||||||||||||
Total operating revenues
|
$ | 1,641,753 | $ | 1,690,123 | $ | 1,056,579 | $ | 506,532 | $ | 118,855 | ||||||||||||
|
|
|
|
|
||||||||||||||||||
Equity in earnings of Woodward Marketing
L.L.C.
(6)
|
| | | $ | 8,062 | $ | 7,307 | |||||||||||||||
|
|
|
|
|
||||||||||||||||||
Employees, at year end
|
122 | 88 | 83 | 62 | 28 |
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 2001-2004 is adjusted for service areas that have weather normalized operations. Degree day information for 2000 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) | The number of utility employees excludes 499, 504, 489, 480 and 369 Atmos shared services employees and 122, 88, 83, 62 and 28 other segment employees in 2004, 2003, 2002, 2001 and 2000. |
(5) | 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. These tables do not include data for the Mid-Tex Division acquired on October 1, 2004. |
(6) | Through March 31, 2001, substantially all of our natural gas marketing revenues and expenses were shown on the equity basis. Beginning April 1, 2001 natural gas marketing revenues and expenses are fully consolidated. |
(7) | Represents propane gallons sold for the period from October 1999 to August 2000. For the period from August 2000 to November 2003, the results of our propane operations were shown on the equity basis; therefore, gallons sold have not been presented. We no longer have an interest in the propane business. |
12
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 jurisdictions 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 establishes rates which allow a utility company an opportunity to collect revenue from customers to recover the cost of providing utility service.
Generally, the regulatory authority reviews our rate request and establishes a rate structure intended to generate revenue sufficient to cover our costs of doing business and provide a reasonable return on invested capital.
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 utilitys 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 utilitys other costs, (ii) represents a large component of the utilitys cost of service and (iii) is generally outside the control of the gas utility. There is no gross profit 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 its customers.
The following table summarizes certain
information regarding our historical ratemaking jurisdictions.
This table does not summarize the ratemaking activities of the
Mid-Tex Division we acquired on October 1, 2004.
Rate Base
Allowed
Division
Jurisdiction
(thousands)
(1)
Return on Equity
(1)
Colorado
(2
)
11.25% 12.50%
Kansas
(2
)
(2)
Kentucky
(2
)
(2)
Louisiana
$
246,617
10.50% 11.50%
Georgia
38,451
11.50%
Illinois
24,564
11.56%
Iowa
5,000
11.00%
Missouri
(2
)
12.15%
Tennessee
(2
)
(2)
Virginia
30,672
10.00%
Amarillo
36,844
12.00%
Lubbock
43,300
11.25%
West Texas
87,500
10.50%
Mississippi
198,103
9.8%
(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. The equity component of allowed return on equity is computed by multiplying the rate base in each state by the capitalization ratio of Atmos Energy as a whole. |
(2) | A rate base or rate of return were not included in the respective state commissions final decision. |
13
Recent Ratemaking Activity |
Approximately 97 percent, 97 percent and 96 percent of our utility revenues in the fiscal years ended September 30, 2004, 2003 and 2002 were derived from sales at rates set by or subject to approval by local or state authorities. Net annual rate increases totaling $16.2 million and $18.6 million became effective in fiscal 2004 and fiscal 2003. There were no rate increases which became effective in fiscal 2002.
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. This table does not summarize the
ratemaking activities of the Mid-Tex Division we acquired on
October 1, 2004.
Amount
Effective
Amount
Received
Jurisdiction
Date
Requested
(Reduced)
(In thousands)
05/04/01
$
4,200
$
2,750
04/01/04
(a
)
(1,900
)
10/23/00
3,100
1,367
03/05/01
(a
)
(326
)
03/01/04
7,400
2,500
12/21/99
14,127
9,900
11/01/02
(a
)
364
(b)
11/01/02
(a
)
11,890
(c)
10/01/04
(a
)
225
(d
)
5,771
(d
)
11,593
10,545
12/01/00
9,827
3,011
01/01/00
4,354
2,200
09/01/03
5,118
2,825
03/01/04
3,000
1,525
05/01/04
7,700
3,200
04/01/01
2,100
(534
)
08/01/04
1,000
372
(a) | 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 commissions rules or (2) the commissions ruling was not the result of a rate filing initiated by us. See further information in the following discussion. |
(b) | 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. | |
(c) | 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. | |
(d) | The Mississippi Public Service Commission (MPSC) requires that we file for rate adjustments every six months. The rate filings are made in May and November of each year and the rate adjustments typically become effective in June and December. See further information in the following discussion. |
14
Atmos Energy Colorado-Kansas Division. In April 2004, the Colorado-Kansas Division agreed to provide a one-time credit to our Colorado customers of $1.9 million pending approval of the agreement by the Colorado Public Utility Commission. The agreement was a result of an inquiry by the Colorado Office of Consumer Counsel related to our earnings in Colorado. The staff of the Colorado Public Utility Commission was also a party to the agreement.
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. In January 2004, the Kansas Corporation Commission approved an agreement that allowed a $2.5 million increase in our rates effective March 1, 2004. Additionally, the agreement allows us to increase our monthly customer charges from $5 to $8 and provides that we will not file another full rate application prior to September 1, 2005. WNA became effective in Kansas in October 2003 in accordance with the Kansas Corporation Commissions ruling in May 2003.
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 Divisions gas cost adjustment clause and provides for the sharing of purchased gas cost savings between our customers and us. We recognized other income of $0.9 million, $1.3 million and $1.1 million under the Kentucky Performance-based-ratemaking mechanism in fiscal years 2004, 2003 and 2002.
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. During fiscal 2004, the Louisiana Public Service Commission approved tariff revisions for our LGS System totaling $0.2 million that became effective in October 2004.
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. On October 8, 2003, the commission unanimously voted in open session to approve an agreement that was reached with the commission staff to allow us 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 were required under this 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, resulted 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 provided 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.
15
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 result from the acquisition. The shared cost savings are 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. Since 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.
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 were revenue neutral, they 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 Divisions 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. This clause expired in fiscal 2003.
Atmos Energy Mid-States Division. In February 2004, the Mid-States Division filed a rate case with the Virginia Corporation Commission to request a $1.0 million increase in our base rates, WNA and recovery of the gas cost component of bad-debt expense. The Virginia Corporation Commission (VCC) granted a rate increase in November 2004 of $0.4 million that was retroactively effective to July 27, 2004. Additionally, the VCC authorized WNA beginning in July 2005 and the ability to recover the gas cost component of bad debt expense.
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, which 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 Virginia Corporation Commission requesting an increase in annual revenues of approximately $2.3 million. A revised filing was submitted in July 2000 requesting an increase in revenues of approximately $2.1 million. 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 West Texas Division. During fiscal 2004, our West Texas Division initiated compliance with new Gas Reliability Infrastructure Program (GRIP) legislation which became law in Texas in 2003 and allows us to expedite the recovery of capital expenditures incurred in the Lubbock, Amarillo and West Texas jurisdictions.
In October 2003, the West Texas Division filed a rate case in Lubbock requesting a $3.0 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. The City of Lubbock approved a $1.5 million increase effective March 1, 2004, as well as the proposed WNA.
In September 2003, the West Texas Division filed a rate case in its West Texas System to request a $7.7 million increase in annual revenues and WNA for its residential, commercial and public-authority customers. In May 2004, the 66 cities in its West Texas System approved an increase of $3.2 million in our annual utility revenues. The cities also approved a WNA Rider for residential, commercial, public-authority and state-institution customers. This Rider became effective in October 2004.
16
In June 2003, the West 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 for the period October through May of each year, which became effective in October 2003.
In August 1999, the West 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 West 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 West Texas Divisions 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). After a series of appeals, 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.
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 Service Commission (MPSC) issued a final order that denied our May 2003 request for a rate adjustment. We filed our second semiannual filing on November 5, 2003, and received an annual rate increase of $5.9 million effective on December 1, 2003. We filed our first semiannual filing for 2004 on May 5, 2004 and we received an annual rate increase of $4.7 million effective on June 1, 2004. However, in the same ruling, the MPSC disallowed certain deferred costs totaling $2.8 million. We are appealing the MPSCs decision regarding these deferred costs. We filed our second semiannual filing for 2004 on November 4, 2004.
Atmos Energy Mid-Tex Division. In May 2003, TXU Gas filed, for the first time, a system-wide rate case for the distribution and pipeline operations. The case was filed in all 437 incorporated cities served by the distribution operations, and at the Railroad Commission for the pipeline business and for unincorporated areas served by the distribution operations. The filing requested an annual revenue increase of $69.5 million or 7.24 percent. On May 25, 2004, TXU Gas received a decision from the Texas Railroad Commission that disallowed certain assets and liabilities for ratemaking purposes. However, the rate case is expected to prospectively increase the Mid-Tex Divisions revenue by approximately $11.7 million. The decision in the rate case was available and considered by us as we finalized our offer for the TXU Gas operations. Additionally, pursuant to its May 2004 rate order, the Mid-Tex Division now operates under a system-wide rate jurisdiction with the pipeline operations we acquired in connection with the TXU Gas acquisition. Similar to our West Texas Division, the Mid-Tex Division operates under the new GRIP regulations. The conditions imposed by the States of Iowa, Missouri and Virginia, in their approvals of the TXU Gas Company acquisition, require that we protect the customers of each state from any adverse effects of the acquisition with respect to rates and quality of service.
Other 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. Our environmental claims have arisen primarily from manufactured gas plant sites in
17
The TXU Gas operations we acquired are wholly intrastate in character and are subject to regulation by municipalities in Texas and the Texas Railroad Commission. These acquired operations do not include any certificated interstate transmission facilities subject to the jurisdiction of the Federal Energy Regulatory Commission (known as the FERC) under the Natural Gas Act, any sales for resale under the rate jurisdiction of the FERC or any transportation service that is subject to FERC jurisdiction under the Natural Gas Act. Since 1988, the FERC has allowed, pursuant to Section 311 of the Natural Gas Policy Act, gas transportation services through the intrastate transmission facilities we acquired on behalf of interstate pipelines or local distribution companies served by interstate pipelines, without subjecting the acquired operations to the jurisdiction of the FERC. We did not acquire any manufactured gas plant sites in the TXU Gas acquisition. Our acquisition agreement with TXU Gas addresses other environmental matters, which we do not expect to have a material adverse effect on us or our operations.
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. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. 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. However, higher gas prices, coupled with the electric utilities marketing efforts have increased competition for residential and commercial customers. In addition, our Natural Gas Marketing segment competes with other natural gas brokers in obtaining natural gas supplies for our customers.
Employees
At September 30, 2004, we had 2,864 employees, consisting of 2,742 employees in our utility segment and 122 employees in our other segments. The acquisition of the TXU Gas operations increased our number of employees by 1,344. See Operating Statistics Utility Sales and Statistical Data by Division for the number of employees by division.
Other Information
We post our filings with the Securities and Exchange Commission 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, in November 2003 the Board of Directors of the Company adopted the Companys Corporate Governance Guidelines and revised the Companys Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, the Board of Directors amended 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 Companys website.
18
Item 2. | Properties |
Distribution, transmission and related assets
At September 30, 2004 our utility segment owned an aggregate of 47,616 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. With the acquisition of the TXU gas operations, the number of miles of underground distribution mains increased by 26,431. Additionally, the acquisition added 6,162 miles of transmission and gathering lines to our system.
Our utility segment also holds franchises granted by the incorporated cities and towns that we serve. At September 30, 2004, we held 667 franchises having terms generally ranging from five to 25 years. We believe that each of our franchises will be renewed. With the acquisition of the TXU Gas operations, our number of franchises increased to 1,103. The additional franchises have initial terms generally ranging from ten to 35 years. We believe that each of these franchises will be renewed. A significant number of our franchises expire each year, which require renewal prior to the end of their terms.
19
Storage Assets
Our historical utility and other nonutility
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
Total
Delivery
capacity
Cushion Gas
Capacity
Capability
Facility
Location
(Mcf)
(Mcf)
(1)
(Mcf)
(Mcf)
Hopkins County, Ky
3,560,600
3,470,000
7,030,600
44,600
Montgomery County, Ks
2,800,000
2,000,000
4,800,000
40,000
Monroe County, Ms
743,998
1,393,280
2,137,278
18,000
Monroe County, Ms
800,635
788,457
1,589,092
30,000
Daviess County, Ky
778,600
1,300,000
2,078,600
24,000
Daviess County, Ky
451,600
850,000
1,301,600
24,000
Muscogee County, Ga
450,000
50,000
500,000
30,000
Montgomery County, Ks
439,000
300,000
739,000
5,000
Daviess County, Ky
305,400
350,000
655,400
4,500
Wilson County, Ks
200,000
180,000
380,000
5,000
Wilson County, Ks
200,000
160,000
360,000
5,000
Hopkins County, Ky
221,900
400,000
621,900
12,000
Total Utility Segment
10,951,733
11,241,737
22,193,470
242,100
Hopkins County, Ky
2,160,000
1,640,000
3,800,000
40,000
Hopkins County, Ky
1,278,900
1,600,000
2,878,900
30,000
Assumption Parish, La
438,583
300,973
739,556
56,000
Christian County, Ky
54,000
55,000
109,000
1,000
Total Other Nonutility Segment
3,931,483
3,595,973
7,527,456
127,000
14,883,216
14,837,710
29,720,926
369,100
(1) | Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. |
(2) | This field was transferred from the Other Nonutility segment to the Atmos Energy Colorado-Kansas Division during fiscal 2004. |
(3) | 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. |
(4) | The TXU Gas operations we acquired include five underground storage reservoirs (including a salt dome facility), all within Texas. Our total storage capacity in these storage reservoirs is approximately 51.9 Bcf. However, approximately 12.9 Bcf of this gas represents cushion gas to maintain reservoir pressure. The maximum daily delivery capability of these storage facilities is approximately 1,235,000 Mcf. |
20
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)
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
Texas Gas Transmission
3,841,150
41,060
Tennessee Gas Pipeline Company
1,313,538
22,698
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
Atmos Energy Marketing
2,173,543
19,634
Southern Natural Gas Company
1,423,374
28,741
Texas Eastern Transmission Company
1,165,734
19,636
Panhandle Eastern Pipeline
972,462
15,241
Tennessee Gas Pipeline Company
835,674
20,000
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 Pipeline Company
200,000
20,000
Egyptian Gas Storage Corp.
400,000
5,000
East Tennessee
339,900
52,633
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
ONEOK Texas Gas Storage LLP
1,125,000
50,000
21
Maximum
Maximum
Daily
Storage
Withdrawal
Quantity
Quantity
Division/Company
Contractor
(MMBtu)
(MMBtu)
(1)
Gulf South
1,237,500
61,875
Southern Natural Gas
1,049,436
21,191
Texas Gas Transmission
826,390
36,420
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
27,889,805
756,651
TCO
1,197,000
25,000
Virginia Gas Pipeline Company
170,000
17,000
Total Natural Gas Marketing Segment
1,367,000
42,000
Gulf South Pipeline Company
750,000
20,000
Bridgeline Gas Distribution LLC
300,000
30,000
Total Other Nonutility Segment
1,050,000
50,000
Total Contracted Storage Capacity
30,306,805
848,651
(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. |
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 nonutility operations are headquartered in Houston, Texas, with offices in Houston and other locations, primarily in leased facilities.
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 2004.
22
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain
information as of September 30, 2004, 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
57
7
Chairman, President and Chief Executive Officer
51
6
Senior Vice President and Chief Financial Officer
65
42
Senior Vice President, Utility Operations
54
3
Senior Vice President, Nonutility Operations
49
4
Senior Vice President and General Counsel
51
16
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.
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, Nonutility 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 was named 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.
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.
23
PART II
Item 5. | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
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 2004 and 2003 are listed below. The high and low prices
listed are the closing NYSE quotes for shares of our common
stock:
2004
2003
Dividends
Dividends
High
Low
paid
High
Low
paid
$
24.99
$
24.15
$
.305
$
23.63
$
20.70
$
.30
26.86
24.32
.305
24.20
20.95
.30
26.05
23.68
.305
25.45
21.43
.30
25.86
24.61
.305
25.07
23.20
.30
$
1.22
$
1.20
Dividend payments are payable at the discretion of our Board of Directors out of legally available funds and are also 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, 2004 was 27,555. We do not expect to change our current dividend policy as a result of the TXU Gas acquisition or the related financings. Future payments of dividends, and the amounts of these dividends, will depend on our financial condition, results of operations, capital requirements and other factors.
The following table sets forth the number of
securities authorized for issuance under our equity compensation
plans at September 30, 2004.
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
outstanding
options,
plans (excluding
options, warrants
warrants and
securities reflected
and rights
rights
in column (a))
(a)
(b)
(c)
1,492,177
$
22.10
1,760,627
300
15.50
168,550
1,492,477
22.10
1,929,177
1,492,477
$
22.10
1,929,177
24
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
2004
(1)
2003
(2)
2002
2001
(3)
2000
(4)
(In thousands, except per share data and ratios)
$
2,920,037
$
2,799,916
$
1,650,964
$
1,725,481
$
850,152
562,191
534,976
431,140
375,208
325,706
368,496
347,136
275,809
244,927
240,390
193,695
187,840
155,331
130,281
85,316
9,507
2,191
(1,321
)
6,188
14,744
65,437
63,660
59,174
47,011
43,823
137,765
126,371
94,836
89,458
56,237
(7,773
)
51,538
46,910
35,180
33,368
20,319
86,227
71,688
59,656
56,090
35,918
54,416
46,496
41,250
38,247
31,594
$
1.58
$
1.54
$
1.45
$
1.47
$
1.14
270,734
49,541
297,395
82,995
54,196
$
1.22
$
1.20
$
1.18
$
1.16
$
1.14
246,033
247,965
208,541
217,774
197,564
222,572
225,961
204,027
55,469
$
1,722,521
$
1,624,394
$
1,380,070
$
1,409,432
$
1,045,484
262,644
16,248
(139,150
)
(90,968
)
(185,267
)
2,869,883
2,625,495
2,059,631
2,108,841
1,410,668
5,908
127,940
167,771
221,942
267,613
1,133,459
857,517
573,235
583,864
392,466
861,311
862,500
668,959
691,026
361,970
1,994,770
1,720,017
1,242,194
1,274,890
754,436
190,285
159,439
132,252
113,109
75,557
56.7%
46.4%
40.7%
39.0%
38.4%
9.1%
9.9%
9.9%
10.4%
9.3%
(1) | Financial results for 2004 include a $5.9 million pre-tax gain on the sale of our interest in U.S. Propane, L.P. and Heritage Propane Partners, L.P. |
25
(2) | Financial results for fiscal 2003 include the results of MVG from December 3, 2002, the date of acquisition. |
(3) | 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. |
(4) | 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. |
(5) | We have reclassified our regulatory cost of removal obligation from accumulated depreciation to a liability. The amounts presented above for property, plant and equipment, working capital and total assets reflect this reclassification for all periods presented. These reclassifications did not impact our financial position, results of operations or cash flows as of and for the years ended September 30, 2003, 2002, 2001 and 2000. |
(6) | 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. We have reclassified our original issue discount costs from deferred charges and other assets to long-term debt. This reclassification did not materially impact our capitalization or our capitalization ratio as of September 30, 2003, 2002, 2001 and 2000. Note that as of October 1, 2004, in connection with the TXU Gas acquisition, the capitalization ratio decreased to 40.2%. |
(7) | 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. |
The following table presents a condensed income
statement by segment for the year ended September 30, 2004.
For the Year Ended September 30, 2004
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
1,636,636
$
1,279,424
$
3,977
$
$
2,920,037
1,092
339,178
19,174
(359,444
)
1,637,728
1,618,602
23,151
(359,444
)
2,920,037
1,134,594
1,571,971
9,383
(358,102
)
2,357,846
503,134
46,631
13,768
(1,342
)
562,191
92,954
2,089
1,604
96,647
250,290
16,816
6,119
(1,376
)
271,849
159,890
27,726
6,045
34
193,695
5,847
843
8,579
(5,762
)
9,507
65,399
2,711
3,055
(5,728
)
65,437
100,338
25,858
11,569
137,765
37,242
9,225
5,071
51,538
$
63,096
$
16,633
$
6,498
$
$
86,227
$
189,291
$
520
$
474
$
$
190,285
26
Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
Introduction
This section provides managements discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation with specific information on results of operations and liquidity and capital resources. It includes managements 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 Companys 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 Companys documents or oral presentations, the words anticipate, believe, expect, estimate, forecast, goal, intend, objective, plan, projection, seek, strategy 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 Companys 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 Companys utility service territories or colder than normal weather that 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; the Companys ability to continue to access the capital markets; the effects of inflation and changes in the availability and prices of natural gas, including the volatility of natural gas prices; increased competition from energy suppliers and alternative forms of energy; risks relating to the acquisition of the TXU Gas operations, including without limitation, the Companys increased indebtedness resulting from the acquisition and the successful integration of the TXU Gas operations; and other uncertainties discussed herein, 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 our 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 set out 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
27
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 in our natural gas marketing segment 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.
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. The determination of our net open position as of any day requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Net open positions may result in an adverse impact on our financial condition or results of operations if market prices move in an unfavorable manner.
Our utility segment uses a combination of storage and financial hedges to partially insulate us against volatility in gas prices and to help moderate the effects of higher customer accounts receivable caused by higher gas prices. Our natural gas marketing segment manages margins and limits risk exposure on the sale of
28
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.
Further, 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 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.
Our net periodic pension and other postretirement costs are subject to market risk as the fluctuation in the fair value of the assets used to fund our various benefit plans could lead to significant fluctuations in these costs.
Finally, we are subject to interest rate risk on our commercial paper borrowings and the floating rate debt we issued in October 2004 to fund the TXU Gas acquisition. We could experience higher interest expense if interest rates increase or increased volatility if short-term interest rates become volatile.
National, regional and local economic conditions have a direct impact on our operations. |
Our operations are 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, AEMs operations are concentrated in the natural gas industry, and its customers and suppliers may be subject to economic risks affecting that industry.
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 long-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, the increase in our indebtedness after the TXU Gas acquisition 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 2005.
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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 bypass our systems in favor of special competitive contracts with lower per-unit costs.
Risks Relating to the Acquisition of the TXU Gas Operations
In addition to the factors affecting our company and our industry, the risks outlined below relating to the TXU Gas acquisition could also adversely affect our business, financial condition or results of operations.
Our indebtedness and leverage increased materially with the TXU Gas acquisition. |
On October 22, 2004, we issued senior unsecured notes which generated net proceeds of approximately $1.39 billion. On October 27, 2004 we sold 16.1 million shares of common stock, which generated net proceeds of approximately $382.5 million before other offering costs. These financings were used to pay off the commercial paper that was issued to fund the TXU Gas acquisition. Assuming these financings had occurred on September 30, 2004, our total debt, as of September 30, 2004, would have increased from $867.2 million to $2.3 billion and our ratio of total debt to capitalization (including short-term debt and current maturities of long-term debt), as of September 30, 2004 would have increased from 43.3 percent to 59.8 percent. Our ratio of total debt to capitalization is expected to be greater during the current winter heating season as we make additional short-term borrowings to fund natural gas purchases and meet our working capital requirements. We also increased our working capital facility from $350.0 million to $600.0 million on October 22, 2004 to meet our increased working capital requirements as a result of the TXU Gas acquisition. This increase in our indebtedness could limit our flexibility in planning for, or reacting to, changes in our business or economic conditions.
Our long-term debt is currently rated as investment grade by Standard & Poors Corporation, Moodys Investors Service and Fitch Ratings, Inc., the three credit rating agencies that rate our long-term debt securities. There can be no assurance that these rating agencies will maintain investment grade ratings for our long-term debt. If we were to lose our investment-grade rating, the commercial paper markets and the commodity derivatives markets could become unavailable to us. This would increase our borrowing costs for working capital and reduce the borrowing capacity of our gas marketing affiliate. In addition, if our commercial paper ratings were lowered, it would increase the cost of commercial paper financing and could reduce or eliminate our ability to access the commercial paper markets. If we are unable to issue commercial paper, we intend to borrow under our bank credit facilities to meet our working capital needs. This would increase the cost of our working capital financing.
We may not be able to implement the TXU Gas acquisition successfully. |
The TXU Gas acquisition is larger than any of the nine other acquisitions we have made since 1986. In addition to operating the natural gas distribution system we acquired in the TXU Gas acquisition, we will manage pipeline operations on a scale greater than in the past. As a consequence, we may experience the need for additional management attention and resources, we may be required to develop relationships with additional regulatory authorities in the service areas of the TXU Gas operations we acquired or we may face unanticipated challenges or delays in integrating the TXU Gas operations we acquired into our business. In addition, employees important to the TXU Gas operations we acquired may decide not to continue employment with us. If these events occur, the acquired operations may not achieve the results or otherwise perform as expected.
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The TXU Gas operations we acquired are subject to their own risks, which we may not be able to manage successfully. |
The financial results of the TXU Gas operations we acquired are subject to many of the same factors that have historically affected our financial condition and results of operations, including weather sensitivity, extensive federal, state and local regulation, increasing gas costs, competition, market risks and national, regional and local economic conditions.
In addition, the TXU Gas distribution operations we acquired do not have weather-normalized rates. This means we will not be able to increase customers bills to offset lower gas usage when the weather is warmer than normal. However, their operations benefit from a rate structure that combines a monthly customer charge with a declining block rate schedule to mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provides for the recovery of most of our fixed costs for such operations under most weather conditions. As a result, the financial results for the TXU Gas operations we acquired may be adversely affected in the event of a warmer-than-normal heating season.
The TXU Gas transmission operations we acquired include interconnected natural gas transmission lines, underground storage reservoirs, compressor stations and related properties within Texas. The operation of these transmission facilities also involves risks. These include the possibility of breakdown or failure of equipment or pipelines, the impact of unusual or adverse weather conditions or other natural events and the risk of performance below expected levels of throughput or efficiency. Breakdown or reduced performance of a transmission facility may prevent the facility from performing under applicable sales agreements which, in certain situations, could result in termination of those agreements or incurring a liability for liquidated damages. Insurance, warranties, indemnities or performance guarantees may not cover any or all of the liquidated damages, lost revenues or increased expenses associated with a breakdown or reduction in performance of a transmission facility. If we are unsuccessful in managing these risks, our business, financial condition and results of operations could be adversely affected.
We have only limited recourse under the acquisition agreement for losses relating to the TXU Gas acquisition. |
The diligence conducted in connection with the TXU Gas acquisition and the indemnification provided in the acquisition agreement may not be sufficient to protect us from, or compensate us for, all losses resulting from the acquisition or TXU Gass prior operations. For example, under the terms of the acquisition agreement, the first $15 million of many indemnifiable losses are to be borne by us, and the agreement provides for sharing of losses with respect to unknown environmental matters that may affect the assets we acquired after we have borne $10 million in costs relating to such matters. In addition, under the terms of the acquisition agreement, the maximum aggregate amount of such losses for which TXU Gas will indemnify us is approximately $192.5 million. A material loss associated with the TXU Gas acquisition for which there is not adequate indemnification could negatively affect our results of operations, our financial condition and our reputation in the industry and reduce the anticipated benefits of the acquisition.
There may be other risks or costs resulting from the TXU Gas acquisition that are not known to us. |
We may not be aware of all of the risks associated with the TXU Gas acquisition. Any discovery of adverse information concerning the assets or operations we acquired could be material and, in many cases, would be subject to only limited rights of recovery. In addition, we will likely have to make capital expenditures, which may be significant, but which amount has not been fixed, to enhance or integrate the assets and operations we acquired.
Overview
| Our utility segment net income increased $1.0 million despite weather that was 4 percent warmer than normal during fiscal 2004. The increase reflects the full year impact of the Mississippi Valley Gas Company (MVG) operations and rate increases in Kansas, Texas and Mississippi, partially offset by a |
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decline in our irrigation business and a one time $1.2 million net of tax refund to customers in our Colorado service area. | ||
| Our natural gas marketing segment net income before the cumulative effect of an accounting change increased $9.8 million during fiscal 2004. This increase primarily was attributable to our continued efforts to amend contracts with third parties to transfer risk to our customers and to provide higher gross profit margins and improved position management during the current year. | |
| Our fiscal 2004 results reflect pretax gains from asset sales totaling $6.7 million attributable to the sale of our general and limited partnership interests in USP and the remaining limited partnership units in Heritage Propane Partners, L.P. formerly owned by USP during 2004 and the sale of real property. These asset sales provided $27.9 million in cash proceeds during 2004. | |
| In July 2004, we sold 9,939,393 shares of our common stock, including the underwriters exercise of their overallotment option. The offering price was $24.75 and generated net proceeds of approximately $235.7 million after offering costs. In October 2004, we used the net proceeds from this offering, together with issuances in October 2004 of commercial paper backstopped by the bridge financing facility to consummate the acquisition of the natural gas distribution and pipeline operations of TXU Gas. | |
| In August 2004, we filed a shelf registration statement with the SEC to issue, from time to time, up to $2.2 billion in new common stock and/or debt, which was declared effective on September 15, 2004. | |
| In October 2004, we sold 16.1 million common shares under the new shelf registration statement, including the underwriters exercise of their overallotment option generating net proceeds of approximately $382.5 million before other offering costs. Additionally, we issued senior unsecured debt under the new shelf registration statement which generated approximately $1.39 billion in net proceeds. These proceeds were used to refinance the $1.7 billion in commercial paper we issued on October 1, 2004 to fund the TXU Gas acquisition and for general corporate purposes. | |
| Our total debt to capitalization ratio at September 30, 2004 was 43.3 percent compared with 53.6 percent at September 30, 2003. The improvement in the debt to capitalization ratio was primarily attributable to the issuance of 9.9 million shares of our common stock in July 2004, and reduced short-term debt due to strong operating cash flow generated during fiscal 2004. Assuming the TXU Gas acquisition and financings described above had occurred on September 30, 2004, our debt-to-capitalization ratio would have increased to 59.8 percent. | |
| Our debt ratings were recently downgraded as a result of the TXU Gas acquisition; however, our ratings are still considered investment grade. |
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
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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.
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 utilitys 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 utilitys other costs, (ii) represents a large component of the utilitys cost of service and (iii) is generally outside the control of the gas utility. There is no gross profit 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 is generally not affected by fluctuations in the cost of gas due to the purchased gas adjustment mechanism. The effects of these purchased gas adjustment mechanisms are recorded as deferred gas costs on our balance sheet.
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 our collections experience. On certain other receivables where we are aware of a specific customers 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 In our utility segment, we use a combination of storage and financial derivatives to partially insulate us and our natural gas utility customers against gas price volatility during the winter heating season. The financial derivatives we use in our utility segment 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 these derivatives primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. However, because the costs of financial derivatives 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 derivatives. The changes in the assets and liabilities from
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Our natural gas marketing risk management activities are conducted through AEM. AEM is exposed to risks associated with changes in the market price of natural gas, which we manage through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. The use of these contracts is subject to our risk management policies, which are monitored for compliance on a daily basis.
We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase or sell physical natural gas and then sell or purchase financial contracts at a price sufficient to cover our carrying costs and provide a gross profit margin. Through the use of transportation and storage services and derivatives, we are able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market on a monthly basis using the inside FERC (iFERC) price at the end of each month. Changes in fair value are recognized as unrealized gains and losses in the period of change. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenue and the carrying value of the inventory as an associated purchased gas cost in our consolidated statement of income when we sell the gas and deliver it out of the storage facility.
Derivatives associated with our natural gas inventory are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The difference in the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) is reported as a component of revenue and can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction. In addition, we continually manage our positions to optimize value as market conditions and other circumstances change.
Similar to our inventory position, we attempt to mitigate substantially all of the commodity price risk associated with our fixed-price contracts with minimum volume requirements through the use of various offsetting derivatives. Prior to April 1, 2004, these derivatives were not designated as hedges under SFAS 133 because they naturally locked in the economic gross profit margin at the time we entered into the contract. The fixed-price forward and offsetting derivative contracts were marked to market each month with changes in fair value recognized as unrealized gains and losses recorded in revenue in our consolidated statement of income. The unrealized gains and losses were realized as a component of revenue in the period in which we fulfilled the requirements of the fixed-price contract and the derivatives settled. To the extent that the unrealized gains and losses of the fixed-price forward contracts and the offsetting derivatives did not offset exactly, our earnings experienced some volatility. At delivery, the gains and losses on the fixed-price contracts were offset by gains and losses on the derivatives, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction. In addition, we continually manage our positions to optimize value as market conditions and other circumstances change.
Effective April 1, 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales. As a result, we ceased marking the fixed-price forward contracts to market. We designated the offsetting derivative contracts as cash flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on these open derivative contracts are now recorded as a component of accumulated other comprehensive income and are recognized in earnings as a component of revenue when the hedged volumes are sold. This designation is expected to partially reduce the amount of volatility in our consolidated income
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During fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the anticipated issuance of $875 million of long-term debt. We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. Accordingly, to the extent effective, unrealized gains and losses associated with the Treasury lock agreements are recorded as a component of accumulated other comprehensive income. Unrealized gains are recorded when interest rates increase and unrealized losses are recorded when interest rates decline. These Treasury lock agreements were terminated in October 2004 and the $43.8 million unrealized loss will be recognized as a component of interest expense over the life of the related financing arrangement.
The fair value of our financial derivatives is determined through a combination of prices actively quoted on national exchanges, prices provided by other external sources and prices based on models and other valuation methods. Changes in the valuation of our financial derivatives primarily result from changes in market prices, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions, each of which directly affect the estimated fair value of our derivatives. We believe the market prices and models used to value these derivatives represent the best information available with respect to 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.
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 units 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 managements 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.
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Results of Operations
The following table presents our financial
highlights for the three fiscal years ended September 30,
2004:
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The following table shows our operating income by
utility division and by segment for the three fiscal years ended
September 30, 2004. The presentation of our utility
operating income is included for financial reporting purposes
and may not reflect operating income for ratemaking purposes.
Year ended September 30, 2004 compared
with year ended September 30, 2003
Our utility segment has historically contributed
70 to 85 percent of our consolidated net income. The
primary factors that impact the results of our 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
has historically been our most critical earnings quarter with an
average of approximately 68 percent of our consolidated 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, which 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 our
customers. Accordingly, we believe gross profit margin is a
better indicator of our financial performance than revenues.
However, higher gas costs may cause customers to conserve, or,
in the case of industrial customers, to use alternative energy
sources. Higher gas costs may also adversely impact our accounts
receivable collections, resulting in higher bad debt expense.
The effects of weather that is above or below
normal are partially offset through weather normalization
adjustments, or WNA, in certain of our 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.
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Utility gross profit margin increased to
$503.1 million for the year ended September 30, 2004
from $491.4 million for the year ended September 30,
2003. Total throughput for our utility business was
261.0 Bcf during the year compared to 254.7 Bcf in the
prior year. Excluding intercompany throughput, consolidated
throughput for our utility business was 246.0 Bcf during
the year, compared with 248.0 Bcf in the prior year.
The increase in utility gross profit margin
primarily reflects the impact of the acquisition of Mississippi
Valley Gas Company (MVG) whose operations are included for
the entire first quarter in fiscal year 2004, compared with one
month in the first quarter of the prior fiscal year resulting in
an increase in utility gross profit margin and total throughput
of $12.8 million and 5.0 Bcf. Utility gross profit
margin was also favorably impacted by rate increases received in
Kansas, Texas and Mississippi and a $10.2 million
year-over-year increase in the effect of WNA in our WNA service
areas. These increases were offset partially by the impact of
weather that was 6 percent warmer than that of the prior
year and 4 percent warmer than normal, resulting in a
decrease of approximately $13.8 million and lower
irrigation sales in our West Texas Division resulting in a
decrease of approximately $2.1 million. Warmer than normal
weather particularly impacted our service areas in our
Louisiana, Mid-States and West Texas divisions. The decrease in
throughput also reflects a decrease in consumption attributable
to the impact of conservation and the continued introduction of
more efficient gas appliances in our service areas. Finally, our
utility gross profit margin for the year ended
September 30, 2004 reflects a one-time reduction resulting
from a regulatory ruling to refund $1.9 million to our
customers in our Colorado service area.
Operating expenses, which include operation and
maintenance expense, provision for doubtful accounts,
depreciation and amortization expense and taxes other than
income taxes, increased 3.9 percent to $343.2 million
for the year ended September 30, 2004 from
$330.3 million for the year ended September 30, 2003.
Operation and maintenance expense increased, primarily due to
the addition of $6.1 million related to the MVG acquisition
in December 2002 and higher labor and benefit costs. Taxes other
than income taxes increased $1.5 million, primarily due to
additional franchise, payroll and property taxes associated with
the MVG assets acquired in December 2002. Franchise and state
gross receipts taxes are paid by our customers as a component of
their monthly bills; thus, these amounts are offset in revenues
through customer billings and have no effect on net income.
Depreciation and amortization expense increased
$9.1 million, which primarily reflects MVG depreciation for
the full year of fiscal 2004 compared with ten months in the
prior year. These increases were partially offset by a
$7.9 million reduction in our provision for doubtful
accounts attributable to continued improvement in accounts
receivable collections during fiscal 2004.
As a result of the aforementioned factors, our
utility segment operating income for the year ended
September 30, 2004 decreased to $159.9 million from
$161.1 million for the year ended September 30, 2003.
Miscellaneous income for the year ended
September 30, 2004 was $5.8 million, compared with
expense of $0.2 million for the year ended
September 30, 2003. The $6.0 million change was
attributable primarily to the absence in 2004 of weather
insurance amortization totaling $5.0 million, which was
recognized in the prior year due to the termination of our
weather insurance policy in the third quarter of fiscal 2003 and
the recognition of a $0.8 million gain on the sale of real
property during fiscal 2004.
Interest charges increased 3.5 percent for
the year ended September 30, 2004 to $65.4 million
from $63.2 million for the year ended September 30,
2003. The increase was attributable primarily to a higher
average outstanding debt balance resulting from the financing
obtained to fund the acquisition of MVG in December 2002.
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Our natural gas marketing segment aggregates and
purchases gas supply, arranges transportation and/or storage
logistics and ultimately delivers the gas to our customers at
competitive prices. To facilitate this process, we utilize
proprietary and customer-owned transportation and storage assets
to provide the various services our customers request, including
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. As a result, our revenues arise
from the types of commercial transactions we have structured
with our customers and include the value we extract by
optimizing the storage and transportation capacity we own or
control as well as revenues for services we deliver.
We participate in transactions in which we
combine the natural gas commodity and transportation costs to
minimize our costs incurred to serve our customers.
Additionally, we engage in natural gas storage transactions in
which we seek to find and profit from the pricing differences
that occur over time. We purchase or sell physical natural gas
and then sell or purchase financial contracts at a price
sufficient to cover our carrying costs and provide a gross
profit margin. Through the use of transportation and storage
services and derivatives, we are able to capture gross profit
margin through the arbitrage of pricing differences in various
locations and by recognizing pricing differences that occur over
time.
Gross profit margin for our natural gas marketing
segment consists primarily of marketing activities, which
represent the utilization of proprietary and customer-owned
transportation and storage assets to provide the various
services our customers request, and storage activities, which
are derived from the optimization of our managed proprietary and
third party storage and transportation assets.
Our natural gas marketing segments gross
profit margin was comprised of the following for the years ended
September 30, 2004 and 2003:
Our natural gas marketing segments gross
profit was $46.6 million for the year ended
September 30, 2004 compared to gross profit margin of
$24.2 million for the year ended September 30, 2003.
Natural gas marketing sales volumes were 265.1 Bcf during
the current year compared with 294.8 Bcf for the prior
year. Excluding intercompany sales volumes, natural gas
marketing sales volumes were 222.6 Bcf during the current
year compared with 226.0 Bcf in the prior year. The
decrease in consolidated natural gas marketing sales volumes was
primarily due to overall warmer temperatures during the
2003-2004 heating season compared with the prior-year period.
Our natural gas marketing gross profit margin for the year ended
September 30,
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The contribution to gross profit from our storage
activities was a loss of $1.5 million for the year ended
September 30, 2004 compared to a loss of $1.9 million
for the year ended September 30, 2003. The
$0.4 million improvement primarily was attributable to a
$5.4 million improvement in the realized storage
contribution for the year ended September 30, 2004 compared
to the prior year offset by a $5.0 million decrease in
unrealized income associated with our storage portfolio compared
to the prior-year period. The improvement in the realized
storage contribution for the year ended September 30, 2004
primarily was due to our inability during the 2002-2003 heating
season to withdraw planned volumes from storage to meet our
customer requirements caused by operational, contractual and
regulatory limitations relating to our storage facilities, which
reduced our realized storage contributions during fiscal 2003.
This situation did not recur in fiscal 2004. The decrease in
unrealized income in the current period was primarily
attributable to a less favorable movement during the year ended
September 30, 2004 in the forward indices used to value the
storage financial instruments than in the prior year combined
with slightly lower physical natural gas storage quantities at
September 30, 2004 compared to the prior year.
Our marketing activities contributed
$48.2 million to our gross profit margin for the year ended
September 30, 2004 compared to $26.1 million for the
year ended September 30, 2003. The increase in the
marketing contribution primarily was attributable to our
continued efforts to amend contracts with third parties to
transfer risk to our customers and to provide higher gross
profit margins and improved position management during the
current year.
Operating expenses, which include operation and
maintenance expense, provision for doubtful accounts,
depreciation and amortization expense and taxes other than
income taxes, increased to $18.9 million for the year ended
September 30, 2004 from $10.6 million for the year
ended September 30, 2003. The increase in operating expense
was attributable primarily to higher labor and benefit costs
resulting from the improvement in earnings for the fiscal year
and an increase in temporary and permanent personnel due to
systems and process improvements in the marketing segment.
The improved gross profit margin resulted in an
increase in our natural gas marketing segment operating income
to $27.7 million for the year ended September 30, 2004
compared with operating income of $13.6 million for the
year ended September 30, 2003.
Miscellaneous income for the year ended
September 30, 2004 was $0.8 million, compared with
income of $1.9 million for the year ended
September 30, 2003. The $1.1 million decrease was
attributable primarily to lower interest income earned on cash
held on deposit in margin accounts due to favorable valuations
on our financial derivatives, which reduced the need to deposit
cash into margin accounts.
Our other nonutility operating income decreased
to $6.0 million for the year ended September 30, 2004
from $13.1 million for the year ended September 30,
2003. The decrease in our other nonutility operating income was
attributable primarily to a decrease in demand charges
recognized by Atmos Pipeline and Storage for storage services
provided during the year ended September 30, 2004 compared
to the prior-year period and lower transported volumes of
approximately 2.3 Bcf by Atmos Pipeline and Storage due to
overall warmer weather during the winter heating season. The
decrease was also attributable to a $1.5 million decrease
in a monthly facilities fees charged by Trans Louisiana Gas
Pipeline, Inc. as a result of a settlement reached with the
Louisiana Public Service Commission in October 2003. Our other
nonutility operating income for the year ended
September 30, 2004 also included an unrealized loss on open
contracts of $1.1 million compared with no unrealized gain
our loss in the prior year as Atmos Pipeline and Storage started
to hedge its storage inventory during the fourth quarter of 2004.
40
Miscellaneous income for the year ended
September 30, 2004 was $8.6 million, compared with
income of $5.0 million for the year ended
September 30, 2003. The $3.6 million increase was
attributable primarily to a $5.9 million pretax gain
associated with the sale in January 2004 of our general and
limited partnership interests in USP and the sale in June 2004
of the remaining limited partnership units in Heritage Propane
Partners, L.P. formerly owned by USP. This increase was offset
partially by lower equity earnings from our investment in USP
resulting from the sale and the absence in 2004 of a
$3.9 million gain recorded in 2003 associated with a
sales-type lease of a distributed electric generation plant.
Interest charges increased to $3.1 million
for the year ended September 30, 2004 from
$2.0 million for the year ended September 30, 2003.
The increase was attributable to a higher average outstanding
debt balance resulting from increased third-party borrowings of
$5.0 million used to reduce AEHs intercompany
borrowings with Atmos Energy Corporation.
Year ended September 30, 2003 compared
with year ended September 30, 2002
Utility gross profit increased to
$491.4 million for the year ended September 30, 2003
from $377.6 million for the year ended September 30,
2002. Total throughput for our utility business was
254.7 billion cubic feet (Bcf) during the year ended
September 30, 2003 compared to 214.1 Bcf in the prior
year. Excluding intercompany throughput, total consolidated
throughput for our utility business was 248.0 Bcf during
fiscal 2003, compared with 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.
Operating expenses increased 31 percent to
$330.3 million for the year ended September 30, 2003
from $252.1 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, a $14.2 million increase in
the provision for doubtful accounts as a result of higher
revenues and gas prices and higher employee costs. 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.
As a result of the aforementioned factors, our
utility segment operating income for the year ended
September 30, 2003 increased to $161.1 million from
$125.5 million for the year ended September 30, 2002.
Miscellaneous expense for the year ended
September 30, 2003 was $0.2 million, compared with
income of $1.4 million for the year ended
September 30, 2002. The $1.6 million change was
attributable primarily to a $0.6 million charge associated
with the cancellation of our weather insurance policy during the
third quarter of fiscal 2003, which increased our total
insurance policy amortization to $5.0 million for fiscal
2003 compared with $4.4 million for fiscal 2002.
41
Interest charges increased seven percent for the
year ended September 30, 2003 to $63.2 million from
$58.8 million for the year ended September 30, 2002.
The increase was attributable primarily to a higher average
outstanding debt balance resulting from the financing obtained
to fund the acquisition of MVG in December 2002.
Our natural gas marketing segments gross
profit margin was comprised of the following for the years ended
September 30, 2003 and 2002:
Our total natural gas marketing segments
gross profit margin was $24.2 million for the year ended
September 30, 2003 compared to gross profit margin of
$37.6 million for the year ended September 30, 2002.
Natural gas marketing sales volumes were 294.8 Bcf during
the year ended September 30, 2003 compared to
273.7 Bcf for the prior year. Excluding intercompany sales
volumes, natural gas marketing sales volumes were 226.0 Bcf
during the year ended September 30, 2003 compared with
204.0 Bcf in the prior year. The increase in natural gas
marketing sales volumes was primarily due to overall colder
temperatures during the 2002-2003 heating season compared with
the prior year. Our natural gas marketing gross profit included
an unrealized gain on open contracts of $6.3 million in
fiscal 2003 compared with an unrealized loss on open contracts
of $10.5 million in fiscal 2002.
Our storage activities within the natural gas
marketing segment contributed a loss of $1.9 million to
gross profit margin for the year ended September 30, 2003
compared to a $4.8 million loss for the year ended
September 30, 2002. The $2.9 million improvement in
the contribution from our storage activities was primarily
attributable to a $15.3 million greater realized loss in
the current year due to our inability during the 2002-2003
heating season to withdraw planned volumes from storage to meet
our customer requirements caused by operational, contractual and
regulatory limitations relating to our storage facilities offset
by an $18.1 million increase in the unrealized storage
contributions in the current year compared to the prior year.
The greater unrealized contribution in the current year was
primarily attributable to a favorable movement during the year
ended September 30, 2003 in the forward indices used to
value the storage financial instruments than in the prior year
combined with higher physical natural gas storage quantities at
September 30, 2004 compared to the prior year.
Our marketing activities contributed
$26.1 million to our gross profit margin for the year ended
September 30, 2003 compared to $42.3 million for the
year ended September 30, 2002. The decrease in the
marketing contribution primarily was attributable to a
$14.9 million decrease in realized margin combined
42
Operating expenses decreased to
$10.6 million for the year ended September 30, 2003
from $16.9 million for the year ended September 30,
2002. The decrease in operating expenses primarily was
attributable to lower employee incentive compensation costs
during the current year.
As a result of the above, our natural gas
marketing segment generated operating income of
$13.6 million for the year ended September 30, 2003
compared with operating income of $20.6 million for the
year ended September 30, 2002.
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. We previously 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.
Our other nonutility segment operating income
increased to $13.1 million during the year ended
September 30, 2003 compared with $9.2 million for the
prior year. The increase in our nonutility segment operating
income 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.
Miscellaneous income for the year ended
September 30, 2003 was $5.0 million, compared with
income of $0.6 million for the year ended
September 30, 2002. The $4.4 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 Partners L.P.
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 2005.
We believe that these needs can be provided from the same
sources of capital.
43
Capitalization
The following presents our capitalization as of
September 30, 2004 and 2003:
Total debt as a percentage of total
capitalization, including short-term debt, was 43.3 percent
and 53.6 percent at September 30, 2004 and 2003. The
improvement in the debt to capitalization ratio was primarily
attributable to the issuance of 9.9 million shares of our
common stock in July 2004, and reduced short-term debt due to
strong operating cash flow generated during fiscal 2004.
Assuming the TXU Gas acquisition and related debt and equity
financings had occurred on September 30, 2004, our
debt-to-capitalization ratio would have increased to
59.8 percent. Our ratio of total debt to capitalization is
expected to be greater during the current winter heating season
as we make additional short-term borrowings to fund natural gas
purchases and meet our working capital requirements. Within
three to five years from the closing of the acquisition, we
intend to reduce our capitalization ratio to a target range of
53 to 55 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 equity capital markets and reduced annual maintenance and
capital expenditures.
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, the successful
integration of the natural gas distribution and pipeline
operations of TXU Gas we acquired and other factors.
Year-over-year changes in our operating cash
flows are attributable primarily to working capital changes
within our utility segment resulting from the impact of weather,
the price of natural gas and the timing of customer collections,
payments for natural gas purchases and deferred gas cost
recoveries.
For the year ended September 30, 2004, we
generated operating cash flow of $270.7 million compared
with $49.5 million in fiscal 2003 and $297.4 million
in fiscal 2002. The significant factors impacting our operating
cash flow for the last three fiscal years are summarized below.
Fiscal 2004 operating cash flows were favorably
impacted by several items. Improved customer collections during
fiscal 2004, compared with the prior year, resulted in a
$62.2 million increase in operating cash flow. Further,
cash used for natural gas inventories decreased by
$33.8 million compared with the prior year. The decrease
was attributable to lower injections of natural gas into
storage, partially offset by higher prices. The reduction in the
lag between the time period when we purchase our natural gas and
the period in which we can include this cost in our gas rates
improved operating cash flow by $65.7 million. Changes in
cash held on deposit in margin accounts resulted in an increase
in operating cash flow of $25.6 million. This account
represents deposits recorded to collateralize certain of our
financial derivatives purchased in support of our natural gas
marketing activities. The favorable change was attributable to
the fact that the fair value of financial instruments held by
AEM represented a net asset position at September 30, 2004,
which eliminated
44
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 was attributable to a
19 percent increase in consolidated utility throughput as a
result of the impact of our MVG acquisition. 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.
In fiscal 2002, operating cash flow was impacted
favorably by a $56.5 million reduction in cash held on
deposit in margin accounts. During the winter and spring of
2001, our cash deposit requirements increased as a result of
higher unrealized losses on our financial derivatives. 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.
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.
For the year ended September 30, 2004, we
invested $164.9 million compared with $233.4 million
for the year ended September 30, 2003 and
$158.2 million for the year ended September 30, 2002.
Capital expenditures were $190.3 million during the year
ended September 30, 2004 compared to $159.4 million
for the year ended September 30, 2003 and
$132.3 million for the year ended September 30, 2002.
Capital projects for fiscal years 2004, 2003 and 2002 include
expenditures for additional mains, services, meters and
equipment to grow our customer base. Additionally, capital
expenditures for 2004 include approximately $21.5 million
for Mississippi Valley Gas Company Division capital
expenditures. Fiscal 2002 cash flows from investing activities
also included $8.5 million for the acquisition of assets to
be leased to third parties.
Cash used for investing activities for the
current year includes the receipt of $27.9 million
generated from the sale of our limited and general partnership
interests in USP in January 2004 ($24.7 million), the sale
of the remaining limited partnership units in Heritage Propane
Partners, L.P. formerly owned by USP ($1.9 million) and the
sale of real property ($1.3 million).
Capital expenditures for fiscal 2005 are expected
to range from $250 million to $260 million. These
expenditures include additional mains, services, meters and
equipment. Of this amount, approximately $80 million is
expected to be incurred by the Mid-Tex Division.
45
Our cash used for investing activities for fiscal
2004 included approximately $2.0 million for the ComFurT
Gas Inc. acquisition in February 2004. Cash 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 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., a natural gas marketing company.
For the year ended September 30, 2004, our
financing activities provided $80.4 million in cash. Fiscal 2003
cash from financing activities provided cash of
$151.6 million, and in fiscal 2002 our financing activities
represented a use of $106.4 million. Our significant
financing activities for the three years ended
September 30, 2004 are summarized as follows:
46
During the year ended September 30, 2004, we
issued 11,323,925 shares of common stock. Of these shares,
9,939,393 shares were issued in July 2004 to provide cash to
partially fund the acquisition of the TXU Gas operations. The
following table shows the number of shares issued for the years
ended September 30, 2004, 2003 and 2002:
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. On January 16, 2003, we issued
$250.0 million of 5.125% Senior Notes due in 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 for general corporate purposes. Additionally,
we sold 4,100,000 shares of our common stock in connection with
our 2003 Offering under the registration statement to provide
additional funding for our Pension Account Plan. In July 2004,
we sold 9,939,393 shares of our common stock, including the
underwriters exercise of their overallotment option, which
exhausted the remaining availability under this shelf
registration statement.
In August 2004, we filed a shelf registration
statement with the SEC to issue, from time to time, up to
$2.2 billion in new common stock and/or debt, which became
effective on September 15, 2004. In October 2004, we sold
16.1 million common shares, including the
underwriters exercise of their overallotment option of
2.1 million shares, under the new shelf registration
statement, generating net proceeds of $382.5 million before
other offering costs. Additionally, we issued senior unsecured
debt under the shelf registration statement consisting of
$400 million of 4.00% senior notes due 2009,
$500 million of 4.95% senior notes due 2014,
$200 million of 5.95% senior notes due 2034 and
$300 million of floating rate senior notes due 2007. The
floating rate notes will bear interest at a rate equal to the
three-month LIBOR rate plus 0.375 percent per year. The
initial weighted average effective interest rate on these notes
is 4.76 percent. The net proceeds from the sale of these
senior notes was $1.39 billion.
The net proceeds from the October 2004 common
stock and senior notes offerings, combined with the net proceeds
from our July 2004 offering were used to pay off the
$1.7 billion in outstanding commercial paper backstopped by
a senior unsecured revolving credit agreement, which we entered
into on September 24, 2004 for bridge financing for the TXU
Gas acquisition. After issuing the debt and equity in October
2004 we have approximately $405.1 million of availability
remaining under the shelf registration statement.
47
Credit facilities
We maintain both committed and uncommitted credit
facilities. Borrowings under our uncommitted credit facilities
are made on a when-and-as-needed basis at the discretion of the
bank. 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 winter 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. Our cash needs for working capital and capital
expenditures will increase substantially as a result of the
acquisition of the natural gas distribution and pipeline
operations of TXU Gas. On October 22, 2004, we replaced our
$350.0 million credit facility with a new
$600.0 million committed credit facility that will serve as
a backup liquidity facility for our commercial paper program. We
believe this facility, combined with our operating cash flow
will be sufficient to fund these increased working capital
needs. These facilities are described in further detail in Note
6 to the consolidated financial statements.
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 nonutility businesses and the regulatory structures
that govern our rates in the states where we operate.
Our debt is rated by three rating agencies:
Standard & Poors Corporation (S&P), Moodys
Investors Service (Moodys) and Fitch Ratings, Inc.
(Fitch). Our current debt ratings are all considered investment
grade and are as follows:
These ratings reflect downgrades that each of the
three rating agencies issued us as a result of the TXU Gas
acquisition. Currently, S&P and Moodys maintains a
stable outlook and Fitch maintains a negative outlook. None of
our ratings are currently under review.
A credit rating is not a recommendation to buy,
sell or hold securities. All of our current ratings for
long-term debt are categorized as investment grade. The highest
investment grade credit rating for S&P is AAA, Moodys
is Aaa and Fitch is AAA. The lowest investment grade credit
rating for S&P is BBB-, Moodys is Baa3 and Fitch is
BBB-. Our credit ratings may be revised or withdrawn at any time
by the rating agencies, and each rating should be evaluated
independent 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.
Debt Covenants
In addition to the 70 percent limit on our
total debt-to-capitalization ratio imposed by our committed
credit facilities, 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 our
accumulated net income for periods after December 31, 1988,
plus $15.0 million. At September 30, 2004,
approximately $103.6 million of retained earnings was
unrestricted with respect to the payment of dividends.
We were in compliance with all of our debt
covenants as of September 30, 2004. If we do not comply
with our debt covenants, we may be required to repay our
outstanding balances on demand, provide additional
48
Except as described above, 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.
Contractual Obligations and Commercial
Commitments
The following tables provide information about
contractual obligations and commercial commitments at
September 30, 2004.
49
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,
2004, AEM was committed to purchase 55.7 Bcf within one
year and 11.1 Bcf between one to three years under indexed
contracts. AEM was committed to purchase 0.5 Bcf within one year
and 0.1 Bcf within one to three years under fixed price
contracts with prices ranging from $4.08 to $6.25.
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.
On September 22, 2004, we entered into a
senior unsecured revolving credit agreement with a third party
financing institution for bridge financing for the TXU Gas
acquisition. There were no amounts outstanding under the
facility at September 30, 2004. On October 1, 2004, we
issued $1.7 billion in commercial paper that was
backstopped by this facility. In October 2004, we repaid the
$1.7 billion in commercial paper with proceeds received
from our October 2004 debt and equity offerings and canceled the
facility.
Risk Management Activities
We conduct risk management activities through
both our utility and natural gas marketing segments. In our
utility segment, we use a combination of storage, fixed physical
contracts and fixed financial contracts to partially insulate us
and our customers against gas price volatility during the winter
heating season. In our natural gas marketing segment, we manage
our exposure to the risk of natural gas price changes and lock
in our gross profit margin through a combination of storage and
financial derivatives, including futures, over-the-counter and
exchange-traded options and swap contracts with counterparties.
Finally, during fiscal 2004, we entered into four Treasury lock
agreements to fix the Treasury yield component of the interest
cost of financing associated with the anticipated issuance of
$875 million of long-term debt. These Treasury lock
agreements were settled in October 2004 with a net
$43.8 million payment to the counterparties. Approximately
$11.6 million of the $43.8 million obligation will be
recognized as a component of interest expense over the next five
years, and the remaining amount, approximately $32.2 million,
will be recognized as a component of interest expense over the
next ten years. Our risk management activities and related
accounting treatment are described in further detail in Note 5
to the consolidated financial statements.
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. Substantially all of our
derivative financial instruments are valued using external
market quotes and indices. 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, 2004 (in thousands):
50
The fair value of our utility and natural gas
marketing derivative contracts at September 30, 2004, is
segregated below by time period and fair value source.
As of September 30, 2004, a significant
portion of AEMs stored gas inventory was scheduled to be
sold within six months. Since AEM actively manages and optimizes
its portfolio, it may change its scheduled injection and
withdrawal plans based on market conditions. Therefore, we
cannot predict that our actual inventory withdrawals will match
the planned schedule as of September 30, 2004. Generally,
differences between injection and withdrawal prices are
locked-in through the use of derivatives; therefore, there is
generally no significant permanent earnings impact associated
with changes in monthly prices in the interim between injections
and withdrawals. However, there may be significant quarterly
earnings volatility. Further, permanent earnings impacts may
arise if we experience operational or other issues which limit
our ability to optimally manage our stored gas positions. Any
change in the timing of planned injections or withdrawals from
one time period to another generally is conducted to enhance the
future profitability of the storage position. Additionally, AEM
monitors and adjusts the amount of storage capacity it holds on
a discretionary basis.
Pension and Postretirement Benefits
Obligations
For the fiscal year ended September 30,
2004, our total net periodic pension and other benefits costs
was $26.1 million, compared with $28.0 million and
$13.5 million for the period ended September 30, 2003
and 2002. A portion of these costs is capitalized into our
utility rate base, as these costs are recoverable through our
gas utility rates. Costs that are not capitalized are recorded
as a component of operation and maintenance expense.
The decrease in total net periodic pension and
other benefits cost during fiscal 2004 compared with fiscal 2003
primarily reflects the impact of adopting the provisions of the
Medicare Prescription Drug, Improvement and Modernization Act of
2003 (the Act), beginning with the second quarter of 2004, which
reduced our accumulated postretirement benefit obligation by
$24.3 million and our net postretirement benefit obligation
costs by $4.1 million. The total income statement impact
was $2.3 million as a portion of this benefit was
capitalized. Further, the expected return on plan assets, which
reduces the net periodic pension cost and other benefits cost,
increased as compared with the prior year primarily due to an
increase in total assets attributable to the full year effect of
the contributions we made to the Atmos Pension Account Plan in
fiscal 2003 and the inclusion of the MVG pension plan assets
during fiscal 2003 partially offset by a 25 basis point decrease
in the expected return on plan asset assumption used to
determine fiscal 2004 net periodic pension cost. These decreases
were partially offset by an increase in the service cost and the
recognized actuarial loss attributable to a 125 basis point
decrease in the discount rate used to determine the net periodic
pension and other benefits costs, resulting from a decrease in
interest rates at the time the assumptions were established.
The increase in total net periodic pension and
other benefits costs during fiscal 2003 compared with fiscal
2002 was primarily attributable to an increase in the service
cost and interest cost attributable to an increase in our
projected benefit obligations. The increase in the projected
benefit obligations reflected the 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 to determine the projected benefit obligation reflecting a
decline in market interest rates.
51
We did not contribute to our pension plans during
fiscal 2004. 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. 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 as of September 30, 2002 was eliminated as
of September 30, 2003. We are not required to make a
minimum funding contribution to our pension plans during fiscal
2005 nor do we intend to make voluntary contributions during
2005. We contributed $13.8 million, $18.6 million and
$5.9 million to our postretirement benefits plans for the
years ended September 30, 2004, 2003 and 2002. We
anticipate contributing $11.7 million to our postretirement
benefit plans during fiscal 2005.
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
discount rate used generally is based on rates of high grade
corporate bonds with maturities similar to the average period
over which benefits will be paid. The expected return on plan
assets is based on managements expectation of the
long-term return on the portfolio of plan assets. These rates
have generally declined since fiscal 2002 due to a decline in
interest rates and relatively weak market performance of the
underlying plan assets. The rate of compensation increase is
established based upon our internal budgets. The actuarial
assumptions used to determine the pension liability and net
periodic pension and other benefits costs are included in Note 9
to our consolidated financial statements.
We did not assume the existing employee benefit
liabilities or plans of TXU Gas. However, for purposes of
determining our annual pension cost we have agreed to give the
transitioned employees credit for years of TXU Gas service under
our pension plan. For purposes of our post-retirement medical
plan, we received a credit of $20 million (subject to
post-closing adjustment) against the purchase price to permit us
to provide partial past service credits for retiree medical
benefits under our retiree medical plan. The $20 million
credit approximates the actuarially determined present value of
the accumulated benefits related to the past service of the
transferred employees. As a result of the TXU Gas acquisition on
October 1, 2004, our pension and other postretirement
benefits costs should increase substantially during fiscal 2005.
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact
on our financial position, results of operations and cash flows
are described in Note 2 to the consolidated financial statements.
For the year ended September 30
2004
2003
2002
(In thousands, unless otherwise noted)
$
2,920,037
$
2,799,916
$
1,650,964
562,191
534,976
431,140
368,496
347,136
275,809
193,695
187,840
155,531
9,507
2,191
(1,321
)
65,437
63,660
59,174
137,765
126,371
94,836
(7,773
)
51,538
46,910
35,180
$
86,227
$
71,688
$
59,656
173,219
184,512
145,488
72,814
63,453
63,053
246,033
247,965
208,541
222,572
225,961
204,027
3,271
3,473
3,368
96%
101%
94%
$
0.42
$
0.47
$
0.58
$
6.55
$
5.71
$
3.78
(1)
Adjusted for service areas that have weather
normalized operations.
Table of Contents
2004
2003
2002
Heating
Heating
Heating
Degree
Degree
Degree
Days
Days
Days
Operating
Percent of
Operating
Percent of
Operating
Percent of
Income
Normal
(1)
Income
Normal
(1)
Income
Normal
(1)
(In thousands, except degree day information)
$
20,876
99
%
$
23,756
101
%
$
20,083
95
%
22,738
98
%
21,841
101
%
21,934
100
%
40,762
93
%
41,672
106
%
26,974
90
%
38,778
95
%
37,535
101
%
34,146
94
%
18,709
101
%
17,617
101
%
22,090
90
%
19,650
97
%
19,593
92
%
(4,063
)
(937
)
2,776
159,890
96
%
161,134
101
%
125,506
94
%
27,726
13,569
20,610
6,079
13,137
9,215
$
193,695
96
%
$
187,840
101
%
$
155,331
94
%
(1)
Adjusted for service areas that have weather
normalized operations.
Utility segment
Table of Contents
Operating income
Miscellaneous income (expense)
Interest charges
Table of Contents
Natural gas marketing segment
Operating income
September 30
2004
2003
(In thousands, except
storage balances)
$
(1,900
)
$
(7,250
)
357
5,362
(1,543
)
(1,888
)
51,347
25,077
(3,173
)
976
48,174
26,053
$
46,631
$
24,165
5.5
5.7
Table of Contents
Miscellaneous income
Other nonutility segment
Operating income
Table of Contents
Miscellaneous income
Interest charges
Utility segment
Operating income
Miscellaneous income (expense)
Table of Contents
Interest charges
Natural gas marketing segment
Operating income
September 30
2003
2002
(In thousands, except
storage balances)
$
(7,250
)
$
8,022
5,362
(12,776
)
(1,888
)
(4,754
)
25,077
40,021
976
2,289
26,053
42,310
$
24,165
$
37,556
5.7
5.0
Table of Contents
Cumulative effect of change in accounting
principle
Other nonutility segment
Operating income
Miscellaneous income
Table of Contents
September 30
2004
2003
(In thousands, except percentages)
$
$
118,595
6.4
%
867,219
43.3
%
871,845
47.2
%
1,133,459
56.7
%
857,517
46.4
%
$
2,000,678
100.0
%
$
1,847,957
100.0
%
Cash flows from operating
activities
Year ended September 30, 2004
Table of Contents
Year ended September 30, 2003
Year ended September 30, 2002
Cash flows from investing
activities
Table of Contents
Payments for acquisitions
Cash flows from financing
activities
In July 2004, we sold 9,939,393 shares of our
common stock, including the underwriters exercise of their
overallotment option. The offering price was $24.75 and
generated net proceeds of $235.7 million. In October 2004, we
used the net proceeds from this offering, together with
borrowings under the bridge financing facility to consummate the
acquisition of the natural gas distribution and pipeline
operations of TXU Gas. In June and July 2003, we sold a total of
4,100,000 shares of our common stock in a public offering, which
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 for general corporate purposes.
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 MVGs outstanding debt.
On January 16, 2003, we issued
$250.0 million of 5.125% 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, short-term debt under our commercial
paper program and for general corporate purposes.
During fiscal 2004, 2003 and 2002, total
short-term debt decreased by $118.6 million,
$27.2 million and $55.5 million due to improved
operating cash flow and working capital management in the last
three fiscal years.
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 2004 and 2002
payments on long-term debt were $9.7 million and
$20.7 million.
During fiscal 2004, we paid $66.7 million in
cash dividends compared with dividend payments of
$55.3 million and $48.6 million for fiscal 2003 and
2002. The increase in dividends paid over the preceding three
years reflects increases in the quarterly dividend rate and the
number of shares outstanding. Dividend payments in fiscal 2005
will increase substantially as a result of the July 2004 and
October 2004 equity offerings.
Table of Contents
For the year ended September 30
2004
2003
2002
556,856
585,743
505,202
320,313
360,725
326,335
498,230
181,429
50,465
6,000
13,000
3,133
2,969
2,429
9,939,393
3,386,287
1,169,700
4,100,000
11,323,925
9,799,853
884,431
Table of Contents
S&P
Moodys
Fitch
BBB
Baa3
BBB+
A-2
P-3
F-2
Table of Contents
Payments Due by Period
Less than
After 5
Total
1 year
1-3 years
3-5 years
years
(In thousands)
$
868,550
$
5,908
$
14,449
$
12,616
$
835,577
610,395
58,601
115,640
113,368
322,786
4,543
1,139
1,064
673
1,667
80,051
9,648
16,974
15,676
37,753
7,303
1,674
3,080
1,703
846
50,062
48,924
1,138
41,000
41,000
103,619
11,698
17,617
18,373
55,931
$
1,765,523
$
178,592
$
169,962
$
162,409
$
1,254,560
(1)
See Note 6 to the consolidated financial
statements. This line item excludes the debt maturities
associated with the $1.39 billion in senior unsecured notes
we sold in October 2004.
(2)
See Note 14 to the consolidated financial
statements.
(3)
Represents third party contractual demand fees
for contracted storage in our natural gas marketing and other
utility segments. Contractual demand fees for contracted storage
for our utility segment are excluded as these costs are fully
recoverable through our purchase gas adjustment mechanisms.
(4)
Represents liabilities for natural gas commodity
derivative contracts and our treasury lock agreements. The less
than one year amount includes the $43.8 million settlement
of our Treasury lock agreements in October 2004, which is not
subject to continuing market risk. The remaining liabilities
represent natural gas commodity derivative contracts that were
valued as of September 30, 2004. The ultimate settlement
amounts of these remaining liabilities are unknown because they
are subject to continuing market risk.
(5)
Represents the baseline contractual obligation
under our transitional services agreements we entered into in
connection with the TXU Gas acquisition for call center, meter
reading, customer billing, collections, information reporting,
software, accounting, treasury, administration and other
services.
(6)
Represents expected contributions to our
postretirement benefit plans.
Table of Contents
Natural Gas
Utility
Marketing
$
(7,739
)
$
10,144
(3,268
)
(2,882
)
(1,194
)
(797
)
3,589
6,553
$
(8,612
)
$
13,018
Table of Contents
Fair Value of Contracts at September 30, 2004
Maturity in years
Greater
Total Fair
Source of Fair Value
Less than 1
1-3
4-5
than 5
Value
(In thousands)
$
41,537
$
107
$
$
$
41,644
(36,513
)
(108
)
(36,621
)
(42
)
(575
)
(617
)
$
4,982
$
(576
)
$
$
$
4,406
Table of Contents
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest-rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business.
We conduct risk management activities through both our utility and natural gas marketing segments. In our utility segment, we use a combination of storage, fixed physical contracts and fixed financial contracts to partially insulate us and our customers against gas price volatility during the winter heating season. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial derivatives including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our risk management activities and related accounting treatment are described in further detail in Note 5 to the consolidated financial statements. Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper, our other short-term borrowings and, beginning in fiscal 2005, our new floating rate borrowings.
52
Commodity Price Risk
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. However, our utility operations have commodity price risk exposure to fluctuations in spot natural gas prices related to purchases for sales to our non-regulated energy services customers at fixed prices.
For our utility segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on these projected non-regulated gas sales, a hypothetical 10 percent increase in fixed prices based upon the September 30, 2004 three month market strip would increase our purchased gas cost by approximately $4.9 million in fiscal 2005.
Natural gas marketing segment |
Our natural gas marketing segment is also exposed to risks associated with changes in the market price of natural gas. For our natural gas marketing segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open position (including existing storage) at the end of each period. Based on AEHs net open position (including existing storage) at September 30, 2004 of 0.2 Bcf, a $0.50 change in the forward NYMEX price would have had less than a $0.1 million impact on our consolidated net income.
Interest Rate Risk
Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program, other short-term borrowings and, beginning in fiscal 2005, our new floating rate debt. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average of a one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings outstanding during fiscal 2004 increased by an average of one percent, our interest expense would have increased by approximately $1.7 million during 2004. As a result of the TXU Gas acquisition on October 1, 2004, our interest expense should increase substantially during fiscal 2005.
We also assess market risk for our fixed-rate, long-term obligations. We estimate market risk for our fixed-rate, long-term obligations as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates associated with these debt instruments. Fair value is estimated using a discounted cash flow analysis. Assuming this one percent hypothetical decrease, the fair value of our fixed-rate, long-term obligations outstanding as of September 30, 2004 would have increased by approximately $79.6 million.
As of September 30, 2004, we were not engaged in any 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.
53
Item 8. | Financial Statements and Supplementary Data |
Index to financial statements and financial statement schedule:
Page | |||||
|
|||||
Report of independent registered public
accounting firm
|
55 | ||||
Financial statements and supplementary data:
|
|||||
Consolidated balance sheets at September 30,
2004 and 2003
|
56 | ||||
Consolidated statements of income for the years
ended
September 30, 2004, 2003 and 2002 |
57 | ||||
Consolidated statements of shareholders
equity for the years ended
September 30, 2004, 2003 and 2002 |
58 | ||||
Consolidated statements of cash flows for the
years ended
September 30, 2004, 2003 and 2002 |
59 | ||||
Notes to consolidated financial statements
|
60 | ||||
Selected Quarterly Financial Data (unaudited)
|
112 | ||||
II. Valuation and Qualifying Accounts
|
118 |
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.
54
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors
We have audited the accompanying consolidated
balance sheets of Atmos Energy Corporation as of
September 30, 2004 and 2003, and the related consolidated
statements of income, shareholders equity, and cash flows
for each of the three years in the period ended
September 30, 2004. 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
Companys 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 the
standards of the Public Company Accounting Oversight Board
(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 financial statements referred
to above present fairly, in all material respects, the
consolidated financial position of Atmos Energy Corporation at
September 30, 2004 and 2003, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended September 30, 2004, in conformity with
U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the financial statements taken as a
whole, presents fairly, in all material respects, the financial
information set forth therein.
Dallas, Texas
55
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial
statements
56
ERNST & YOUNG LLP
Table of Contents
Table of Contents
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended September 30
2004
2003
2002
(In thousands, except per share data)
$
1,637,728
$
1,554,082
$
937,526
1,618,602
1,668,493
1,031,874
23,151
21,630
24,705
(359,444
)
(444,289
)
(343,141
)
2,920,037
2,799,916
1,650,964
1,134,594
1,062,679
559,891
1,571,971
1,644,328
994,318
9,383
1,540
8,022
(358,102
)
(443,607
)
(342,407
)
2,357,846
2,264,940
1,219,824
562,191
534,976
431,140
214,470
205,090
158,119
96,647
87,001
81,469
57,379
55,045
36,221
368,496
347,136
275,809
193,695
187,840
155,331
9,507
2,191
(1,321
)
65,437
63,660
59,174
137,765
126,371
94,836
51,538
46,910
35,180
86,227
79,461
59,656
(7,773
)
$
86,227
$
71,688
$
59,656
$
1.60
$
1.72
$
1.45
(.17
)
$
1.60
$
1.55
$
1.45
$
1.58
$
1.71
$
1.45
(.17
)
$
1.58
$
1.54
$
1.45
54,021
46,319
41,171
54,416
46,496
41,250
See accompanying notes to consolidated financial statements
57
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)
40,791,501
$
204
$
489,948
$
(1,420
)
$
95,132
$
583,864
59,656
59,656
(39,432
)
(39,432
)
(528
)
(528
)
19,696
(48,646
)
(48,646
)
505,202
2
10,546
10,548
326,335
2
7,137
7,139
50,465
579
579
2,429
55
55
41,675,932
208
508,265
(41,380
)
106,142
573,235
71,688
71,688
39,432
39,432
489
489
111,609
(55,291
)
(55,291
)
4,100,000
20
99,102
99,122
3,386,287
17
74,633
74,650
1,169,700
6
28,757
28,763
585,743
3
13,209
13,212
360,725
2
8,277
8,279
181,429
1
3,664
3,665
13,000
206
206
2,969
67
67
51,475,785
257
736,180
(1,459
)
122,539
857,517
86,227
86,227
615
615
(21,268
)
(21,268
)
7,583
7,583
73,157
(66,736
)
(66,736
)
9,939,393
50
235,419
235,469
556,856
3
13,726
13,729
320,313
2
8,300
8,302
498,230
2
11,848
11,850
6,000
94
94
3,133
77
77
62,799,710
$
314
$
1,005,644
$
(14,529
)
$
142,030
$
1,133,459
See accompanying notes to consolidated financial statements
58
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH
FLOWS
Year ended September 30
2004
2003
2002
(In thousands)
$
86,227
$
71,688
$
59,656
7,773
(6,700
)
96,647
87,001
81,469
1,465
2,193
2,452
36,997
53,867
14,509
(1,772
)
(5,885
)
(3,371
)
17,903
(7,711
)
56,474
2,158
(60,026
)
(12,181
)
(31,030
)
(64,875
)
(2,228
)
(9,233
)
(15,747
)
28,146
17,178
21,258
(33,515
)
4,586
19,417
52,302
48,877
(40,636
)
34,195
7,431
(18,866
)
19,487
270,734
49,451
297,395
(190,285
)
(159,439
)
(132,252
)
(1,957
)
(74,650
)
(15,747
)
(570
)
704
(1,725
)
(8,511
)
27,919
(164,893
)
(233,385
)
(158,235
)
(118,595
)
(27,196
)
(55,456
)
5,000
253,267
147,000
(147,000
)
(9,713
)
(73,165
)
(20,651
)
(70,938
)
(66,736
)
(55,291
)
(48,646
)
34,715
25,720
18,321
235,737
99,229
80,408
151,626
(106,432
)
186,249
(32,308
)
32,728
15,683
47,991
15,263
$
201,932
$
15,683
$
47,991
See accompanying notes to consolidated financial statements
59
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
Atmos Energy Corporation and its subsidiaries are
engaged primarily in the natural gas utility business as well as
other nonutility 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 covered the following service areas:
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 division is located in Dallas,
Texas, and our customer support centers are located in Amarillo,
Texas and Metairie, Louisiana.
As further described in Note 3, on
October 1, 2004, we completed our acquisition of the
natural gas distribution and pipeline operations of TXU Gas
Company (TXU Gas). The TXU Gas operations we acquired are
regulated businesses engaged in the purchase, transmission,
distribution and sale of natural gas in the north-central,
eastern and western parts of Texas. Through these newly acquired
operations, we provide gas distribution services to
approximately 1.5 million residential and business customers in
Texas, including the Dallas/ Fort Worth metropolitan area. We
also now own and operate a system consisting of 6,162 miles of
gas transmission and gathering lines and five underground
storage reservoirs, all within Texas.
Our nonutility businesses are organized under
Atmos Energy Holdings, Inc. (AEH), 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 customers, primarily in the southeastern
and midwestern states and to our Colorado-Kansas, Kentucky,
Louisiana and Mid-States divisions. These services consist
primarily 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 instruments.
Our other nonutility businesses consist primarily
of the operations of Atmos Pipeline and Storage, L.L.C. and
Atmos Energy Services, LLC (AES), which are wholly-owned by AEH.
Through Atmos Pipeline and Storage, L.L.C., we own or have an
interest in underground storage fields in Kentucky and
Louisiana. Through Atmos Pipeline and Storage, L.L.C. we provide
storage services to our customers, as well as capture pricing
60
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
arbitrage through the use of derivatives. Through
AES, we provide natural gas management services. Prior to the
second fiscal quarter of 2004, this entity conducted limited
operations. However, beginning, April 1, 2004, AES began
providing natural gas supply management services to our utility
operations in a limited number of states. As of
September 30, 2004 we had expanded these services to
substantially all of our utility service areas.
Prior to January 20, 2004, United Cities
Propane Gas, Inc., a wholly-owned subsidiary of AEH, owned an
approximate 19 percent membership interest in U.S. Propane
L.P. (USP), a joint venture formed in February 2000 with three
other utility companies. Through our ownership in USP, we owned
an approximate 5 percent indirect interest in Heritage Propane
Partners, L.P. (Heritage). During 2004, we sold our interest in
USP and Heritage. We received cash proceeds of
$26.6 million and recorded a pretax book gain of
$5.9 million with these transactions. We no longer have an
interest in the propane industry.
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.
Basis of
comparison
Certain
prior-year amounts have been reclassified to conform with the
current year presentation. Beginning in the second quarter of
2004 we have retroactively reclassified our regulatory removal
obligation from accumulated depreciation to a liability for all
periods presented. Additionally, beginning in the fourth quarter
of 2004 we have reclassified our original issue discount costs
from deferred charges and other assets to long-term debt. These
reclassifications did not impact our financial position, results
of operations, cash flows or ability to satisfy our financial
covenants contained in our various credit agreements.
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 as a component of
deferred charges and other assets for costs that have been
deferred for which future recovery through customer rates is
considered probable. Regulatory liabilities are recorded either
on the face of the balance sheet or as a component of current
liabilities, deferred income taxes or deferred credits and other
liabilities when it is probable that revenues will be reduced
for amounts that will
61
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be credited to customers through the ratemaking
process. Significant regulatory assets and liabilities as of
September 30, 2004 and 2003 included the following:
Currently authorized rates do not include a
return on certain of our merger and integration costs; however,
we recover the amortization of these costs. Merger and
integration costs, net, are generally amortized on a
straight-line basis over estimated useful lives ranging from 5
to 20 years. During the fiscal years ended
September 30, 2004, 2003 and 2002, we recognized
$8.2 million, $8.2 million and $6.3 million in
amortization expense related to these costs. Beginning in
December 2004, these amortization costs will decrease
substantially. Environmental costs have been deferred to future
rate filings in accordance with rulings received from various
regulatory commissions.
At September 30, 2004, we had a rate case
pending in our Virginia jurisdiction. In November 2004, the
Virginia Corporation Commission (VCC) granted a rate
increase of $0.4 million that was retroactively effective
to August 1, 2004. Additionally, the VCC authorized WNA
beginning in July 2005 and the ability to recover the gas cost
component of bad debt expense.
In our Mississippi Valley Company Division, we
filed our first semiannual filing for 2004 on May 5, 2004
and we received an annual rate increase of $4.7 million
effective on June 1, 2004. However, in the same ruling, the
Mississippi Public Service Commission (MPSC) disallowed certain
deferred costs totaling $2.8 million. We are appealing the
MPSCs decision regarding these deferred costs. We filed
our second semiannual filing for 2004 on November 4, 2004.
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.
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 utilitys 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
62
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
fluctuations compared to the utilitys other
costs, (ii) represents a large component of the
utilitys cost of service and (iii) is generally
outside the control of the gas utility. There is no gross profit
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 is generally not affected by fluctuations
in the cost of gas due to the purchased gas adjustment
mechanism. The effects of these purchased gas adjustment
mechanisms are recorded as deferred gas costs on our balance
sheet.
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, 2004, 2003 and 2002, we included unrealized
gains (losses) on open contracts of ($2.8) million,
$6.3 million and ($10.5) 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 our collections
experience. On certain other receivables where we are aware of a
specific customers 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, customer deposits and general
economic conditions. Accounts are written off once they are
deemed to be uncollectible.
Gas stored
underground
Our gas stored
underground is comprised of natural gas injected into storage to
support the winter season withdrawals for our utility operations
and natural gas held by our natural gas marketing and other
nonutility subsidiaries to conduct their operations. The average
cost method is used for all our utility divisions, except for
the Mid-States Division, where it is valued on the first-in
first-out method basis, in accordance with regulatory
requirements. The average gas cost method is used for our
natural gas marketing segment. 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 $1.2 million,
$0.8 million and $1.3 million was capitalized in 2004,
2003 and 2002.
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. These rates are approved
by our regulatory commissions and are comprised of two
components, one based on average service life and one based on
cost of removal. Accordingly, we
63
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
recognize our cost of removal expense as a
component of depreciation expense. The related cost of removal
accrual is reflected as a regulatory liability on the
consolidated balance sheet. At the time property, plant and
equipment is retired, removal expenses less salvage, are charged
to the regulatory cost of removal accrual. The composite
depreciation rate for the years ended September 30, 2004,
2003 and 2002 was 3.8 percent.
Nonutility property, plant and
equipment
Nonutility
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
obligations
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, 2004 and 2003, we have asset retirement
obligations; however, we cannot determine when the legal
obligation will be incurred.
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 assets 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 units 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
assets carrying value over its fair value is recorded. To
date, no impairment has been recognized.
Marketable securities
As of September 30, 2004 and
2003, all of our marketable securities were 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 funds purpose,
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.
64
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In our utility segment, we use a combination of
storage and financial derivatives to partially insulate us and
our natural gas utility customers against gas price volatility
during the winter heating season. The financial derivatives we
use in our utility segment 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 these derivatives primarily result from changes
in the valuation of the portfolio of contracts, maturity and
settlement of contracts and newly originated transactions.
However, because the gains or losses of financial derivatives
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 derivatives. The changes in
the assets and liabilities from risk management activities are
recognized in purchased gas cost in the income statement when
the related gain or loss is recovered through our rates.
Our natural gas marketing risk management
activities are conducted through AEM. AEM is exposed to risks
associated with changes in the market price of natural gas, and
we manage our exposure to the risk of natural gas price changes
through a combination of storage and financial derivatives,
including futures, over-the-counter and exchange-traded options
and swap contracts with counterparties. Option contracts provide
the right, but not the requirement, to buy or sell the commodity
at a fixed price. Swap contracts require receipt of payment for
the commodity based on the difference between a fixed price and
the market price on the settlement date. The use of these
contracts is subject to our risk management policies, which are
monitored for compliance on a daily basis.
We participate in transactions in which we
combine the natural gas commodity and transportation costs to
minimize our costs incurred to serve our customers.
Additionally, we engage in natural gas storage transactions in
which we seek to find and profit from pricing differences that
occur over time. We purchase or sell physical natural gas and
then sell or purchase financial contracts at a price sufficient
to cover our carrying costs and provide a gross profit margin.
Through the use of transportation and storage services and
derivatives, we are able to capture gross profit margin through
the arbitrage of pricing differences in various locations and by
recognizing pricing differences that occur over time.
Under SFAS 133, natural gas inventory is
designated as the hedged item in a fair-value hedge and is
marked to market on a monthly basis using the inside FERC
(iFERC) price at the end of each month. Changes in fair value
are recognized as unrealized gains and losses in revenue in the
period of change. Costs to store the gas are recognized in the
period the costs are incurred. We recognize revenue and the
carrying value of the inventory as an associated purchased gas
cost in our consolidated statement of income when we sell the
gas and deliver it out of the storage facility.
Derivatives associated with our natural gas
inventory are marked to market each month based upon the NYMEX
price with changes in fair value recognized as unrealized gains
and losses in the period of change. The difference in the
indices used to mark to market our physical inventory (iFERC)
and the related fair-value hedge (NYMEX) is reported as a
component of revenue and can result in volatility in our
reported net income. Over time, gains and losses on the sale of
storage gas inventory will be offset by gains and losses on the
fair-value hedges, resulting in the realization of the economic
gross profit margin we anticipated at the time we structured the
original transaction. In addition, we continually manage our
positions to optimize value as market conditions and other
circumstances change.
Similar to our inventory position, we attempt to
mitigate substantially all of the commodity price risk
associated with our fixed-price contracts with minimum volume
requirements through the use of various
65
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
offsetting derivatives. Prior to April 1,
2004, these derivatives were not designated as hedges under SFAS
133 because they naturally locked in the economic gross profit
margin at the time we entered into the contract. The fixed-price
forward and offsetting derivative contracts were marked to
market each month with changes in fair value recognized as
unrealized gains and losses recorded in revenue in our
consolidated statement of income. The unrealized gains and
losses are realized as a component of revenue in the period in
which we fulfill the requirements of the fixed-price contract
and the derivatives are settled. To the extent that the
unrealized gains and losses of the fixed-price forward contracts
and the offsetting derivatives do not offset exactly, our
earnings will experience some volatility. At delivery, the gains
and losses on the fixed-price contracts were offset by gains and
losses on the derivatives, resulting in the realization of the
economic gross profit margin we anticipated at the time we
structured the original transaction. In addition, we continually
manage our positions to optimize value as market conditions and
other circumstances change.
Effective April 1, 2004, we elected to treat
our fixed-price forward contracts as normal purchases and sales.
As a result, we ceased marking the fixed-price forward contracts
to market. We have designated the offsetting derivative
contracts as cash flow hedges of anticipated transactions. As a
result of this change, unrealized gains and losses on these open
derivative contracts are now recorded as a component of
accumulated other comprehensive income and are recognized in
earnings as a component of revenue when the hedged volumes are
sold. This designation is expected to partially reduce the
amount of volatility in our consolidated income statement and
better reflect the economics of this type of transaction. Hedge
ineffectiveness, to the extent incurred, is reported as a
component of revenues.
During fiscal 2004, we entered into four Treasury
lock agreements to fix the Treasury yield component of the
interest cost of financing associated with the anticipated
issuance of $875 million of long-term debt. We designated
these Treasury lock agreements as cash flow hedges of an
anticipated transaction. Accordingly, to the extent effective,
unrealized gains and losses associated with the Treasury lock
agreements are recorded as a component of accumulated other
comprehensive income. Unrealized gains are recorded when
interest rates increase and unrealized losses are recorded when
interest rates decline. These Treasury lock agreements were
terminated in October 2004 and the $43.8 million unrealized
loss will be recognized as a component of interest expense over
the life of the related financing arrangement.
The fair value of our financial derivatives is
determined through a combination of prices actively quoted on
national exchanges, prices provided by other external sources
and prices based on models and other valuation methods. Changes
in the valuation of our financial derivatives primarily result
from changes in market prices, the valuation of the portfolio of
our contracts, maturity and settlement of these contracts and
newly originated transactions, each of which directly affect the
estimated fair value of our derivatives. We believe the market
prices and models used to value these derivatives represent the
best information available with respect to 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.
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 managements 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.
66
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 and key employees: the 1998
Long-Term Incentive Plan and the Long-Term Stock Plan for the
Mid-States Division. Nonemployee directors are also eligible to
receive such stock-based compensation under the 1998 Long-Term
Incentive Plan. 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 valued at the
market price of the Companys 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.
Had compensation expense for our stock options
issued under the Long-Term Incentive Plan 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, 2004, 2003 and 2002 would
have been impacted as shown in the following table:
67
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accounting pronouncements
implemented
In January
2003, the Financial Accounting Standards Board
(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 to consolidate and which
business enterprises should consolidate the VIE. Under the
guidance of FIN 46, we are considered the primary beneficiary of
the Rabbi Trust used to fund our supplemental executive
retirement plan described in Note 9. However, since we already
consolidate these assets and related liabilities, the adoption
of this interpretation did not have a material impact on our
financial position, results of operations or net cash flows.
During 2003, the Emerging Issues Task Force (the
Task Force) added to its agenda Emerging Issues Task Force
(EITF) Issue 03-01,
The Meaning of Other-Than-Temporary
Impairment and Its Application to Certain Investments,
to
address the meaning of other-than-temporary
impairment and its application to certain investments carried at
cost. In November 2003, the Task Force developed new disclosure
requirements concerning unrealized losses on available-for-sale
debt and equity securities accounted for under SFAS 115,
Accounting for Certain Investments in Debt and Equity
Securities
. We have adopted the disclosure requirements
prescribed by EITF 03-01, which are contained in Note 9. In
March 2004, the Task Force defined the meaning of
other-than-temporary and issued guidance regarding
the measurement and recognition of an investment that had
experienced an other-than-temporary impairment.
However, in September 2004 the Task Force delayed the effective
date for the measurement and recognition criteria of EITF 03-01
while it considers additional questions pertaining to these
issues.
In December 2003, the FASB issued SFAS 132
(revised),
Employers Disclosures about Pensions and
Other Postretirement Benefits
. These revisions require
additional disclosures in annual reports on Form 10-K
concerning the assets, obligations, cash flows and net
periodic-benefit cost of defined-benefit pension plans and other
defined-benefit postretirement plans which became effective for
fiscal years ending after June 15, 2004. We have adopted
these disclosure requirements which are contained in Note 9.
In January 2004, the FASB issued FASB Staff
Position FAS (FSP) 106-1,
Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003,
which permitted a
plan sponsor to defer recognizing the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003
(the Act) in accounting for its plan under SFAS 106 and in
providing disclosures related to the plan required by SFAS 132
(revised). FSP 106-2, issued in March 2004, superseded FSP 106-1
and provided guidance on the accounting for the effects of the
Act for employers that sponsor a single-employer defined benefit
postretirement health care plan for which the employer has
concluded that prescription drug benefits available under the
plan are actuarially equivalent to the Medicare Part D benefit
and the expected subsidy will offset or reduce the
employers share of the cost of the benefit. We determined
that the prescription drug benefits of our plan were actuarially
equivalent to the Medicare Part D benefit. The implementation of
the Act reduced our accumulated postretirement benefit
obligation by $24.3 million and our fiscal 2004 net
postretirement benefit obligation costs by $4.1 million based
upon calculations prepared by our independent actuaries. The
total income statement impact for fiscal 2004 approximated
$2.3 million, as a portion of this benefit was capitalized.
3. Acquisitions
On October 1, 2004, we completed our
acquisition of the natural gas distribution and pipeline
operations of TXU Gas Company (TXU Gas). The TXU Gas operations
we acquired are regulated businesses engaged in the purchase,
transmission, distribution and sale of natural gas in the
north-central, eastern and western parts of Texas. Through these
newly acquired operations, we provide gas distribution services
to approximately 1.5 million residential and business
customers in Texas, including the Dallas/ Fort Worth
metropolitan area.
68
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We also now own and operate a system consisting
of 6,162 miles of gas transmission and gathering lines and five
underground storage reservoirs, all within Texas.
The purchase price for the TXU Gas acquisition
was approximately $1.905 billion (after preliminary closing
adjustments), which we paid in cash. We acquired approximately
$121 million of working capital of TXU Gas and did not
assume any indebtedness of TXU Gas in connection with the
acquisition. TXU Gas retained certain assets and provided for
the repayment of all of its indebtedness and redeemed all of its
preferred stock prior to closing and retained and agreed to pay
certain other liabilities under the terms of the acquisition
agreement. The purchase price is subject to further adjustment
sixty days after closing for the actual amount of working
capital we acquired and other specified matters. We anticipate
that any post-closing purchase price adjustments will not be
material.
We funded the purchase price for the TXU Gas
acquisition with approximately $235.7 million in net
proceeds from our offering of 9,939,393 shares of common stock,
which we completed on July 19, 2004, and approximately
$1.7 billion in net proceeds from our issuance on
October 1, 2004 of commercial paper backstopped by a senior
unsecured revolving credit agreement, which we entered into on
September 24, 2004 for bridge financing for the TXU Gas
acquisition. In October 2004, we paid off the outstanding
commercial paper used to fund the acquisition through the
issuance of senior unsecured notes on October 22, 2004,
which generated net proceeds of approximately
$1.39 billion, and the sale of 16.1 million shares of
common stock on October 27, 2004, which generated net
proceeds of $382.5 million before other offering costs.
The following table summarizes the fair values of
the assets acquired and liabilities assumed on October 1,
2004, in thousands:
The sale of TXU Gass assets was held
through a competitive bid process. We believe the resulting
goodwill is recoverable given the expected synergies we can
achieve as a result of the TXU Gas acquisition. To that end, the
TXU Gas acquisition significantly expands our existing utility
operations in Texas. The North Texas operations of TXU Gas
bridge our geographic operations between our existing utility
operations in West Texas and Louisiana. TXU Gass
headquarters and service area are centered in Dallas, Texas,
which is also the location of our corporate headquarters.
Further, the addition of the regulated pipelines in North Texas
may create additional gas marketing and other opportunities for
our non-regulated subsidiaries, which include gas marketing and
storage operations. The goodwill generated in the acquisition is
deductible for tax purposes.
69
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Our allocation of the purchase is preliminary and
is subject to change. The amount currently allocated to
property, plant and equipment represents our estimate of the
fair value of the assets acquired. We have based that estimate
on the amount we believe will ultimately be approved as rate
base for rate setting purposes.
The table below reflects the unaudited pro forma
results of the Company and TXU Gas for the year ended
September 30, 2004 as if the acquisition and related
financing had taken place at the beginning of fiscal 2004 (in
thousands, except per share data):
Effective March 1, 2004, we completed the
acquisition of the natural gas distribution assets of ComFurT
Gas Inc., a privately held natural gas utility and propane
distributor based in Buena Vista, Colorado, for approximately
$2.0 million in cash. This company served approximately 1,800
natural gas utility customers. The acquisition enabled us to
expand our contiguous service area in our Colorado-Kansas
division. Unaudited pro forma results of the Company and ComFurT
have not been presented as the acquisition was not material to
our financial position or results of operations.
On December 3, 2002, we completed the
acquisition of Mississippi Valley Gas Company (MVG),
Mississippis largest natural gas utility. The acquisition
of MVG enabled us to expand our service area into Mississippi.
MVG served approximately 261,500 residential, commercial,
industrial and other customers located primarily in the northern
and central regions of Mississippi. MVGs rate design
provides timely returns on capital investment and earnings
stability and enabled us to leverage our existing centralized
management structure, shared services organization and
information systems to manage costs in all of Atmos
Energys utility service areas over the long term.
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 MVGs outstanding debt. The results
of operations of MVG have been consolidated with our results of
operations from the acquisition date.
Goodwill and intangible assets were comprised of
the following as of September 30, 2004 and 2003.
70
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following presents our goodwill balance
allocated by segment and changes in the balance for the year
ended September 30, 2004:
Information regarding our intangible assets is
included in the following table. As of September 30, 2004
and 2003, we had no indefinite-lived intangible assets.
The following table presents actual amortization
expense recognized during 2004 and an estimate of future
amortization expense based upon our intangible assets at
September 30, 2004.
71
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We conduct risk management activities through
both our utility and natural gas marketing segments. 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. Our determination of the fair value of these
derivative financial instruments reflects the estimated amounts
that we would receive or pay to terminate or close the contracts
at the reporting date, taking into account the current
unrealized gains and losses on open contracts. In our
determination of fair value, we consider various factors,
including closing exchange and over-the-counter quotations, time
value and volatility factors underlying the contracts.
The following table shows the fair values of our
risk management assets and liabilities by segment at
September 30, 2004 and 2003:
We use a combination of storage, fixed physical
contracts and fixed financial contracts to partially insulate us
and our customers against gas price volatility during the winter
heating season. For the 2003-2004 heating season, we hedged
between 50 and 55 percent of our anticipated winter flowing
gas requirements at a weighted average cost of approximately
$5.36 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 covered our Texas and Louisiana
operations to protect against weather that was at least
7 percent warmer than normal for the entire heating season
of October through March, beginning with the 2001-2002 heating
season. The prepaid cost of the three-year policy was
$13.2 million and was amortized over the appropriate
heating seasons based on heating degree days. In the third
quarter of fiscal 2003, we cancelled this policy, primarily as a
result of rate relief in Louisiana and at that time, prospects
for weather normalization adjustments in Texas. During fiscal
2003 and 2002, we recognized amortization expense of
$5.0 million and $4.4 million. However, we did not
collect under this policy because weather was not at least
7 percent warmer than normal.
Out utility hedging activities also includes the
fair value of our treasury lock agreements which are described
in further detail below.
72
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the year ended September 30, 2004, the
increase in the deferred hedging gain in accumulated other
comprehensive income was attributable to the initiation of cash
flow hedge accounting treatment described above and increases in
future commodity prices relative to the commodity prices
stipulated in the derivative contracts, partially offset by the
recognition of $3.5 million in net deferred hedge gains in
net income when the derivatives matured according to their
terms. The net deferred hedge losses associated with open cash
flow hedges remain subject to market price fluctuations until
the positions are either settled under the terms of the hedge
contracts or terminated prior to settlement. Substantially all
of the deferred hedging gain as of September 30, 2004 is
expected to be recognized in net income within the next fiscal
year.
Under our risk management policies, we seek to
match our financial derivative positions to our physical storage
positions as well as our expected current and future sales and
purchase obligations to maintain no open positions at the end of
each trading day. The determination of our net open position as
of any day, however, requires us to make assumptions as to
future circumstances, including the use of gas by our customers
in relation to our anticipated storage and market positions.
Because the price risk associated with any net open position at
the end of each day may increase if the assumptions are not
realized, we review these assumptions as part of our daily
monitoring activities. We can also be affected by intraday
fluctuations of gas prices, since the price of natural gas
purchased or sold for future delivery earlier in the day may not
be hedged until later in the day. At times, limited net open
positions related to our existing and anticipated commitments
may occur. At the close of business on September 30, 2004,
AEH had a net open position (including existing storage) of 0.2
Bcf.
On October 25, 2002, EITF 02-03,
Accounting for Contracts Involved in Energy Trading and Risk
Management,
was issued. It 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.
Beginning January 1, 2003, we
have no longer marked our storage and transportation contracts
to market value each month in accordance with EITF 98-10 and
adopted EITF 02-03. As a result, we recorded a $7.8 million, net
of applicable income tax benefit, as a cumulative effect of a
change in accounting principle in fiscal 2003.
During fiscal 2004, we entered into four Treasury
lock agreements to fix the Treasury yield component of the
interest cost of financing associated with the anticipated
issuance of $875 million of long-term debt subsequent to
September 30, 2004. This long-term debt was issued on
October 22, 2004 and was used to repay a portion of the
commercial paper used to fund the TXU Gas acquisition, as
described in Note 3.
We designated these Treasury lock agreements as
cash flow hedges of an anticipated transaction. Accordingly, to
the extent effective, unrealized gains and losses associated
with the Treasury locks are recorded as a component of
accumulated other comprehensive income (loss). At
September 30, 2004, we recorded deferred hedging losses of
$21.3 million, net of tax, as a component of accumulated
other comprehensive income (loss) related to these Treasury
lock agreements due to a decline in the 5 and 10 year
Treasury rates between the inception of the Treasury locks and
September 30, 2004. These Treasury lock agreements were
settled in October 2004 with a net $43.8 million payment to
the counterparties. Approximately $11.6 million of the
$43.8 million obligation will be recognized as a component
of interest expense over the next five years, and the remaining
amount, approximately $32.2 million, will be recognized as
a component of interest expense over the next ten years.
73
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents our hedging
transactions that were recorded to other comprehensive income
(loss), net of taxes during the year ended September 30, 2004.
Prior to fiscal 2004, we did not designate any of our derivative
instruments as cash flow hedges.
The following amounts net of deferred taxes
represent the expected recognition into earnings for our
derivative instruments, based upon the fair values of these
derivatives as of September 30, 2004:
74
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
6. Debt
Long-term debt at September 30, 2004 and
2003 consisted of the following:
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 September 30, 2004, approximately
$103.6 million of retained earnings were unrestricted with
respect to the payment of dividends. We were in compliance with
all of our debt covenants as of September 30, 2004.
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 5.125% 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, we sold 4,100,000 shares of our common
stock in connection with our June and July 2003 Offering under
the registration statement to provide additional funding for our
Pension Account Plan. In July 2004, we sold
75
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
9,939,393 shares of our common stock, including
the underwriters exercise of their overallotment option.
We used the net proceeds from this offering, together with
borrowings under a bridge financing facility to consummate the
acquisition of substantially all of the assets of TXU Gas and
pay related fees and expenses. As a result of the offering, we
exhausted the remaining availability under our December 2001
shelf registration statement.
In August 2004, we filed another shelf
registration statement with the SEC to issue, from time to time,
up to $2.2 billion in new common stock and/or debt, which
became effective on September 15, 2004. In October 2004, we
sold 16.1 million common shares, including the
underwriters exercise of their overallotment option, under
the new shelf registration statement, generating net proceeds of
$382.5 million before other offering costs. Additionally,
we issued senior unsecured debt under the shelf registration
statement consisting of $400 million of 4.00% senior notes
due 2009, $500 million of 4.95% senior notes due 2014,
$200 million of 5.95% senior notes due 2034 and
$300 million of floating rate senior notes due 2007. The
floating rate notes will bear interest at a rate equal to the
three-month LIBOR rate plus 0.375 percent per year. The
initial weighted average effective interest rate on these notes
is 4.76 percent. The net proceeds from the sale of these
senior notes were $1.39 billion.
The net proceeds from the October 2004 common
stock and senior notes offerings, combined with the net proceeds
from our July 2004 offering were used to pay off the
$1.7 billion in outstanding commercial paper backstopped by
a senior unsecured revolving credit agreement, which we entered
into on September 24, 2004 for bridge financing for the TXU
Gas acquisition. After issuing the debt and equity in October
2004 we have approximately $405.1 million in availability
remaining under the shelf registration statement. Also, as a
result of this refinancing in October 2004, we canceled the
senior unsecured revolving credit facility.
As of September 30, 2004, all of the
Colorado-Kansas Division utility plant assets with a net book
value of approximately $219.7 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 $363.3 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, 2004 and 2003 is estimated, using discounted
cash flow analysis, to be $936.6 million and
$1,003.9 million.
Maturities of long-term debt at
September 30, 2004 were as follows (in thousands):
At September 30, 2004, there were no
short-term amounts outstanding under our commercial paper
program or bank credit facilities. At September 30, 2003,
short-term debt consisted of $118.6 million of commercial
paper. The weighted average interest rate on short-term
borrowings outstanding at September 30, 2003 was
1.7 percent.
76
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Credit facilities
We maintain both committed and uncommitted credit
facilities. Borrowings under our uncommitted credit facilities
are made on a when-and-as-needed basis at the discretion of the
bank. 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 winter 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.
As of September 30, 2004, we had two
short-term committed credit facilities totaling
$368.0 million, one of which was an unsecured facility for
$350.0 million that bore interest at the Eurodollar rate
plus 0.625 percent and served as a backup liquidity
facility for our commercial paper program. In July 2004, we
renewed this facility with substantially the same terms as those
of the existing facility that was set to expire in January 2005.
However, on October 22, 2004 we replaced this credit
facility with a new 364-day $600.0 million committed credit
facility that will serve as a backup liquidity facility for our
commercial paper program on terms that are substantially similar
to our $350.0 million facility.
We have a second unsecured facility in place for
$18.0 million that bears interest at the Fed Funds rate
plus 0.5 percent and is used for working-capital purposes.
At September 30, 2004, there were no amounts outstanding
under these credit facilities. These credit facilities are
negotiated at least annually. On April 1, 2004, the
$18.0 million working-capital credit facility was renewed
for an additional 12 months on terms substantially similar
to those of the prior facility.
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
MVGs existing debt. A total of $147.0 million was
borrowed under this credit facility during the first quarter of
fiscal 2003. This amount was paid off 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 in the respective
credit agreements, all of 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, at the end of each fiscal quarter, a ratio of total
debt to total capitalization of no greater than 70 percent.
At September 30, 2004, our total-debt-to-total-capitalization
ratio, as defined, was 45 percent. In addition, both the
interest margin over the Eurodollar rate and the fee that we pay
on unused amounts under our $350.0 million credit facility
are subject to adjustment depending upon our credit ratings. We
and our lead bank amended this facilitys terms prior to
closing the TXU Gas acquisition to accommodate the expected
increase in our debt to capital ratio that resulted from the
acquisition. Under this amendment, the total debt to total
capitalization ratio is calculated quarterly and up to
$200 million in short-term debt will be excluded from the
calculation as of December 31, 2004. This provision also
was incorporated into the new $600.0 million credit
facility that replaced the $350.0 million facility in
October 2004.
AEM has a $250.0 million uncommitted-demand
working capital credit facility that bears interest at the
Eurodollar rate plus 2.5 percent and expires on
March 31, 2005. 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, 2004, no
amounts were outstanding under this credit facility. AEM letters
of credit totaling $55.0 million have been issued under the
facility and reduce
77
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the amount available that can be borrowed. 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 AEM
under this credit facility was $62.1 million at
September 30, 2004.
We also have an unsecured short-term uncommitted
credit line for $25.0 million that is used for
working-capital and letter-of-credit purposes. There were no
borrowings under this uncommitted credit facility at
September 30, 2004, but Atmos Energy Corporation
(AEC) letters of credit reduced the amount available by
$3.8 million. 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.
In addition, AEM has a $100.0 million
intercompany credit facility with AEC through AEH for its
nonutility business which bears interest at the Eurodollar rate
plus 2.75 percent. Any outstanding amounts under this
facility are subordinated to AEMs $250.0 million
uncommitted-demand credit facility described above. This
facility is used to supplement AEMs $250.0 million
credit facility. This credit facility was renewed effective
July 1, 2004 on substantially the same terms as those of
the existing facility and has been approved by our state
regulators through December 31, 2004. However, there is no
assurance that our regulators will approve our use of this
credit facility after that time. At September 30, 2004,
$15.0 million was outstanding under this facility and is
eliminated in consolidation.
During the years ended September 30, 2004,
2003 and 2002 we issued 11,323,925, 9,799,853, and 884,431
shares of common stock.
On October 27, 2004, we completed the public
offering of 16,100,000 shares of our common stock including the
underwriters exercise of their overallotment option of
2,100,000 shares. The offering was priced at $24.75 and
generated net proceeds of approximately $382.5 million,
before other offering costs. On July 14, 2004, we completed
the public offering of 8,650,000 shares of our common stock. The
offering was priced at $24.75 and generated net proceeds of
approximately $205.1 million. We sold an additional
1,289,393 shares of our common stock when our underwriters
exercised their overallotment option, which generated net
proceeds of approximately $30.6 million.
We used the net proceeds from these offerings,
together with net proceeds of $1.39 billion received from
the issuance of senior unsecured notes to pay off the
$1.7 billion in outstanding commercial paper described in
Note 3.
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 (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 for other general corporate purposes
including the purchase of natural gas for storage.
On November 12, 1997, our Board of Directors
declared a dividend distribution of one right for each
outstanding share of our common stock to shareholders of record
at the close of business on May 10, 1998. Each right
entitles the registered holder to purchase from us a one-tenth
share of our common stock at a purchase price of $8.00 per
share, subject to adjustment. The description and terms of the
rights are set forth in a rights agreement between us and the
rights agent.
78
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Subject to exceptions specified in the rights
agreement, the rights will separate from our common stock and a
distribution date will occur upon the earlier of:
The rights expire on May 10, 2008, unless
extended prior thereto by our board or earlier if redeemed by
us. The rights will not have any voting rights. The exercise
price payable and the number of shares of our common stock or
other securities or property issuable upon exercise of the
rights are subject to adjustment from time to time to prevent
dilution. We issue rights when we issue our common stock until
the rights have separated from the common stock. After the
rights have separated from the common stock, we may issue
additional rights if the board of directors deems such issuance
to be necessary or appropriate. The rights have
anti-takeover effects and may cause substantial
dilution to a person or entity that attempts to acquire us on
terms not approved by our 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 our board of directors
because, prior to the time that the rights become exercisable or
transferable, we can redeem the rights at $.01 per right.
As part of the consideration for our Mississippi
Valley Gas Company acquisition in December 2002, we issued
shares of common stock under an exemption from registration
under the Securities Act of 1933, as amended. In the
transaction, we entered into a registration rights agreement
with the former stockholders of Mississippi Valley Gas Company
that requires us, on no more than two occasions, and with some
limitations, to file a registration statement under the
Securities Act within 60 days of their request for an
offering designed to achieve a wide distribution of shares
through underwriters selected by us. We also granted rights,
subject to some limitations, to participate in future registered
offerings of our securities to these shareholders. As of
September 30, 2004, 1,193,143 shares were covered by the
registration rights agreement. Each of these shareholders has
also agreed, for up to five years from the closing of the
acquisition, and with some exceptions, not to sell or transfer
shares representing more than 1 percent of our total
outstanding voting securities to any person or group or any
shares to a person or group who would hold more than
9.9 percent of our total outstanding voting securities
after the sale or transfer. This restriction, and other agreed
restrictions on the ability of these shareholders to acquire
additional shares, participate in proxy solicitations or act to
seek control, may be deemed to have an anti-takeover
effect.
In addition, in connection with our funding of
the Atmos Energy Corporation Pension Account Plan, we issued, in
June 2003, to the Atmos Energy Corporation Master Retirement
Trust, for the benefit of the Pension Account Plan, 1,169,700
shares of common stock under an exemption from registration
under the Securities Act. In the transaction, we entered into a
registration rights agreement with the asset manager of the
Pension Account Plan that requires us, on no more than three
occasions, and with some limitations, to file a registration
statement under the Securities Act within 60 days of its
request for an offering designed to
79
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
achieve a wide distribution of shares through
underwriters selected by us. We also granted rights, subject to
some limitations, to participate in future registered offerings
of our securities to the asset manager.
We have two stock-based compensation plans that
provide for the granting of incentive stock options,
nonqualified stock options, stock appreciation rights, bonus
stock, restricted stock and performance-based stock to officers
and key employees: the 1998 Long-Term Incentive Plan and the
Long-Term Stock Plan for the Mid-States Division. Nonemployee
directors are also eligible to receive such stock-based
compensation under the 1998 Long-Term Incentive Plan. 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.
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 our
shareholders. 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, 2004, non-qualified stock options, bonus
stock and restricted stock have been issued under this plan, and
1,760,627 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.
A summary of activity for grants of stock options
under the 1998 Long-Term Incentive Plan follows:
80
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Information about outstanding and exercisable
options under the Long-Term Incentive Plan, as of
September 30, 2004, follows:
The stock options had a weighted average fair
value per share on the date of grant of $3.82 in 2004, $3.32 in
2003 and $3.55 in 2002. We used the Black-Scholes pricing model
to estimate the fair value of each option granted with the
following weighted average assumptions for 2004, 2003 and 2002:
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, we 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 granted under this plan since 1996. During 2004, 6,000
options were exercised under the plan. At September 30,
2004, there were 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.
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. Certain of these awards vest
based upon the passage of time and other awards vest based upon
the passage of time and the achievement of specified performance
targets. The associated expense is recognized ratably over the
vesting period. 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
81
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
restrictions on the restricted stock awarded. The
following summarizes information regarding the restricted stock
plans:
We maintain a Direct Stock Purchase Plan which
allows participants to have all or part of their cash dividends
paid quarterly in additional shares of our common stock. Through
March 31, 2004, participants were permitted to reinvest
their cash dividends at a three percent discount from market
prices. Effective April 1, 2004, the three percent discount
on reinvested dividends was eliminated and the minimum initial
investment required to join the plan was increased to $1,250.
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.
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.
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 Companys Retirement Plan for
Non-Employee Directors. The plan provides non-employee directors
of Atmos with the opportunity to defer receipt, until
retirement, 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.
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 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.
82
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We have both funded and unfunded noncontributory
defined benefit plans that together cover substantially all of
our employees. We also maintain post-retirement plans that
provide health care benefits to retired employees. Finally, we
sponsor defined contribution plans which cover substantially all
employees. These plans are discussed in further detail below.
As of September 30, 2004, we maintained 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
Master 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 participants account at the end of each year
according to a formula based on the participants age,
service and total pay (excluding incentive pay).
The Plan also provides for an additional annual
allocation based upon a participants 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 participants
account will be credited with interest on the employees
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 (the MVG Plan). On
June 30, 2003, all retirees and the active non-union
employees became eligible to participate in the Plan. Active
union employees remained in the MVG 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. We did not contribute
to the Master Trust during fiscal 2004. In June 2003, we
contributed to the Master Trust for the benefit of the Plan
$48.6 million in cash and 1,169,700 shares of Atmos
restricted common stock with a value of $28.8 million. 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 as of September 30, 2002 was
eliminated as of September 30, 2003. We are not required to
make a minimum funding contribution during fiscal 2005 nor do we
anticipate making any voluntary contributions during fiscal 2005.
We manage the Master Trusts assets with the
objective of achieving a real rate of return of approximately
four percent per year. We make investment decisions and evaluate
performance on a medium
83
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
term horizon of at least three to five years. We
also consider our current financial status when making
recommendations and decisions regarding the Master Trusts
assets. Finally, we strive to ensure the Master Trusts
assets are appropriately invested to maintain an acceptable
level of risk and meet the Master Trusts long term asset
allocation policy.
To achieve these objectives, we invest the Master
Trusts assets in equity securities, fixed income
securities, interests in commingled pension trust funds and cash
and cash equivalents.
Investments in equity securities are diversified
among the markets various subsectors to diversify risk and
maximize returns. Fixed income securities are invested in
investment grade securities. Cash equivalents are invested in
securities that either are short term (less than 180 days)
or readily convertible to cash with modest risk.
The following table presents asset allocation
information for the Master Trust as of September 30, 2004
and 2003.
At September 30, 2004 and 2003, the Plan
held 1,169,700 shares of Atmos common stock, which represented
9.0 percent and 8.6 percent of total Master Trust
assets. These shares generated dividend income of approximately
$1.4 million and $0.4 million during fiscal 2004 and
2003.
The following table presents the Master
Trusts funded status for 2004 and 2003. The benefit
obligation and related plan assets used to determine the funded
status are determined as of June 30 of each fiscal year and
are based upon actuarial projections and assumptions, including
the discount rate, expected return on plan assets and the rate
of compensation increase. Discount rates used to determine the
projected benefit obligation and net periodic pension cost are
based on rates of high grade corporate bonds with maturities
similar to the average period over which benefits will be paid.
The expected return on plan assets is based on managements
expectation of the long-term return on the portfolio of plan
assets. These expectations are based upon the historical returns
earned by the Master Trusts assets, future market
projections and expectations and surveys of assumptions used by
other companies. The rate of compensation increase is
established based upon our internal budgets.
84
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The accumulated benefit obligation for our
employee pension plans was $305.1 million and
$323.7 million at September 30, 2004 and 2003.
During 2003, we changed the mortality table for
converting cash balance accounts into monthly annuities to
better reflect the anticipated life expectancy of participants
in the plan. The effects of this change are reflected in the
above table as plan amendment.
The actuarial assumptions used to determine the
pension liability for the Master Trust were determined as of
June 30, 2004 and 2003 as follows:
85
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net periodic pension cost for the Master Trust
for 2004, 2003 and 2002 is recorded as a component of operating
expense and included the following components:
The actuarial assumptions used to determine the
net periodic pension cost for the Master Trust were determined
as of June 30, 2003, 2002 and 2001 and are as follows:
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.
86
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the funded status of
the supplemental plans for 2004 and 2003:
The accumulated benefit obligation for our
supplemental executive plans was $64.8 million and
$62.6 million at September 30, 2004 and 2003. 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 were determined as
of June 30, 2004 and 2003 and are as follows:
87
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Assets for the supplemental plans are held in
separate rabbi trusts and comprise the following:
At September 30, 2004, we maintained
investments in domestic equity mutual funds that were in an
unrealized loss position as of September 30, 2004.
Information concerning these funds follows:
Because these funds are only used to fund the
supplemental plans, we evaluate investment performance over a
long-term horizon. Based upon our intent and ability to hold
these investments and to direct the source of the payments in
order to maximize the life of the portfolio, the improved
investment returns in the last year and the fact that the funds
continue to receive high ratings from mutual fund rating
companies, we consider this impairment to be temporary.
Net periodic pension cost for the supplemental
plans for 2004, 2003 and 2002 is recorded as a component of
operating expense and included the following components:
88
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The actuarial assumptions used to determine the
net periodic pension cost for the supplemental plans were
determined as of June 30, 2003, 2002 and 2001 and are as
follows:
The following summarizes key information for our
defined benefit plans with accumulated benefit obligations in
excess of plan assets. For fiscal 2003, the accumulated benefit
obligation for both the Plan and MVGs plan exceeded the
fair value of plan assets for each plan. For fiscal 2004, this
condition only existed for the MVG plan.
The following benefit payments for our defined
benefit plans, which reflect expected future service, as
appropriate, are expected to be paid in the following years:
We sponsor three postretirement plans other than
pensions that provide health care benefits to retired employees:
the Retiree Medical Plan for Retirees and Disabled Employees of
Atmos Energy Corporation, the Atmos Energy Corporation Retiree
Welfare Benefits Plan for Certain MVG Non-Union Employees and
the Atmos Energy Corporation Retiree Welfare Benefits Plan for
MVG Union 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.
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 annually as
considered necessary. Contributions are intended to provide not
only for benefits attributed
89
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
to service to date but also for those expected to
be earned in the future. We expect to contribute
$11.7 million to our postretirement benefits plans during
fiscal 2005.
We currently do not maintain a formal investment
policy with respect to the assets in our postretirement benefits
plans. However, we strive to ensure the assets funding the
postretirement benefit plans are appropriately invested to
maintain an acceptable level of risk. We also consider our
current financial status when making recommendations and
decisions regarding the postretirement benefits plans.
We currently invest the assets funding our
postretirement benefit plans in money market funds, equity
mutual funds, fixed income funds and a balanced fund. The
following table presents asset allocation information for the
postretirement benefit plan assets as of September 30, 2004
and 2003.
The following table presents the funding status
for the postretirement plans for 2004 and 2003. The benefit
obligation and related plan assets used to determine the funded
status are determined as of June 30 of each fiscal year and
are based upon actuarial projection and assumptions, including
the discount rate, expected return on plan assets and the rate
of compensation increase. Discount rates used to determine the
benefit obligation and net periodic pension cost are based on
rates of high grade corporate bonds with maturities similar to
the average period over which benefits will be paid. The
expected return on plan assets is based on managements
expectation of the long-term return on the portfolio of plan
assets. These expectations are based upon the historical returns
earned by the plans assets, future market projections and
expectations and surveys of assumptions used by other companies.
90
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
The actuarial assumptions used to determine the
liability for the post-retirement plans were determined as of
June 30, 2004 and 2003 and are as follows:
91
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Net periodic postretirement cost for 2004, 2003
and 2002 is recorded as a component of operating expense and
included the following components. The 2004 amounts reflect the
impact of adopting the provisions of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the Act)
beginning in the second quarter of fiscal 2004 as the plan is
considered actuarially equivalent to Medicare
Part D.
The actuarial assumptions used to determine the
net periodic benefit cost for the postretirement plans were
determined as of June 30, 2003, 2002 and 2001 and are as
follows:
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:
We are currently recovering other postretirement
benefits costs through our regulated rates under SFAS 106
accrual accounting in substantially all of our service areas.
Other postretirement benefits costs have been specifically
addressed in rate orders in each jurisdiction served by our
Mid-States Division and our Mississippi Valley Gas Company
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.
92
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following benefit payments paid by us and
retirees for our postretirement benefit plans, which reflect
expected future service, as appropriate, are expected to be paid
in the following years:
As of September 30, 2004, we maintained two
contribution benefit plans: the Atmos Energy Corporation
Retirement Savings Plan and Trust (the Retirement Savings Plan)
and the Mississippi Valley Gas Company Savings Plan for Union
Employees (the MVG 401K Plan).
The Retirement Savings Plan covers substantially
all employees and 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 participants 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
participants contributions, limited to four percent of the
participants salary, in Atmos common stock. However,
participants have the option to immediately transfer this
matching contribution into other funds held within the plan.
Participants are also permitted to take out loans against their
accounts subject to certain restrictions.
The MVG 401K Plan covers substantially all
employees who are members of the International Chemical Workers
Union Council, United Food and Commercial Workers Union
International (Union) and is subject to the provisions of
Section 401(k) of the Internal Revenue Code. Employees of
the Union automatically become participants of the MVG 401K plan
on the date of union employment. We match 50 percent of a
participants contribution, limited to six percent of the
participants eligible contribution. Participants are also
permitted to take out loans against their accounts subject to
certain restrictions.
Matching contributions to our defined
contribution plans are expensed as incurred and amounted to
$4.6 million, $4.1 million, and $3.6 million for
2004, 2003 and 2002. 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 2004, 2003 or 2002. At September 30, 2004 and
2003, the Retirement Savings Plan held 3.7 percent and
4.4 percent of our common stock.
93
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables provide additional
information regarding the composition of certain of our balance
sheet captions.
Accounts receivable was comprised of the
following at September 30, 2004 and 2003:
Other current assets as of September 30,
2004 and 2003 were comprised of the following accounts.
94
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Property, plant and equipment was comprised of
the following as of September 30, 2004 and 2003:
Deferred charges and other assets as of
September 30, 2004 and 2003 were comprised of the following
accounts.
95
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other current liabilities as of
September 30, 2004 and 2003 were comprised of the following
accounts.
Deferred credits and other liabilities as of
September 30, 2004 and 2003 were comprised of the following
accounts.
96
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Basic and diluted earnings per share at
September 30 are calculated as follows:
There were approximately 3,000, 601,500 and
1,118,167 out-of-the-money options excluded from the computation
of diluted earnings per share for the years ended
September 30, 2004, 2003 and 2002 as their exercise price
was greater than the average market price of the common stock
during that period.
97
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The components of income tax expense from
continuing operations for 2004, 2003 and 2002 were as follows:
The provision (benefit) for income taxes is
included in the consolidated financial statements as follows:
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 2004, 2003 and 2002 are set forth
below:
98
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, 2004
and 2003 are presented below:
We have tax carryforwards amounting to
$15.8 million. The tax carryforwards include capital losses
for federal purposes amounting to $0.5 million and state
net operating losses amounting to $0.5 million. The federal
capital loss carryforwards will expire in 2007. 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
$14.8 million in alternative minimum tax credits which do
not expire.
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.
We are a defendant in a lawsuit filed by Quinque
Operating Company, Tom Boles and Robert Ditto on
September 23, 1999 in the District Court of Stevens County,
Kansas against more than 200 companies in the
99
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
natural gas industry as well as in another
similar lawsuit entitled
In Re Natural Gas Royalties Qui Tam
Litigation,
which was remanded to the same court in January
2001. The plaintiffs in these two lawsuits that have now been
consolidated, who purport to represent a class of royalty
owners, allege that the defendants have underpaid royalties on
gas taken from wells situated on non-federal and non-Indian
lands in Kansas, Colorado, and Wyoming, predicated upon
allegations that the defendants gas measurements are
inaccurate. The plaintiffs have not specifically alleged an
amount of damages. The District Court denied an earlier motion
in these proceedings to certify a class but gave plaintiffs
permission to try to seek certification of a revised class,
which we intend to oppose. We believe that the plaintiffs
claims are lacking in merit, and we intend 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 affect on our
financial condition, results of operations, or net cash flows.
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 arose 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.
During fiscal 2004, we reached a settlement with the
plaintiffs attorneys in this case. The settlement
agreement was approved by the court and then by the plaintiffs
as a class. Substantially all of the material terms of the
settlement were implemented during fiscal 2004. The settlement
did 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. We have settled a portion of our
claims with the parties and will continue to pursue recovery of
the remaining claims, which we believe are fully recoverable. We
are proceeding with discovery in this case, which has been set
for trial in 2005.
United Cities Propane Gas, Inc., one of our
wholly-owned subsidiaries, is a party to an action filed in June
2000 that 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. This case has been set for trial in the
Spring of 2005. 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 party to other litigation and claims
that arose in the ordinary course of our business, including
certain litigation and claims that arose in the ordinary course
of the business of TXU Gas Company, the natural gas distribution
and pipeline operations we acquired on October 1, 2004.
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.
100
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 byproducts 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
fiscal 1997, which we continued through September 30, 2004.
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 completed a risk assessment report that has been approved by
the TDEC as well as a feasibility study for this site, which was
submitted to the TDEC 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 that
would be 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 we 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 requested that the focused removal action be
conducted pursuant to a voluntary agreement. On April 13,
2004, we entered into a voluntary consent agreement with the
TDEC for the performance of the removal action and anticipate
completing such removal action prior to the end of calendar year
2004.
On July 22, 1998, we entered into an
Abatement Order on Consent with the Missouri Department of
Natural Resources to address the former manufactured gas plant
located in Hannibal, Missouri. We agreed to perform a removal
action and 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 approved 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
addition, we have installed a geosynthetic liner over the
surface of the site.
In 1995, United Cities Gas Company entered into
an agreement with a third party to resolve its share of the
costs of additional investigations and environmental-response
actions for soil contamination at a former manufactured gas
plant in Keokuk, Iowa. However, the extent of groundwater
contamination at the site, if any, which is not covered by the
agreement, has yet to be determined.
As of September 30, 2004, 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 $0.5 million, which is recorded as a component of
other current liabilities.
101
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. During fiscal 2004, we received a letter from
the KDHE, stating that we fulfilled the terms of the Consent
Orders.
We are a party to other environmental matters and
claims that arose in the ordinary course of our business,
including certain environmental matters and claims that arose in
the ordinary course of the business of TXU Gas Company, the
natural gas distribution and pipeline operations we acquired on
October 1, 2004. 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.
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,
2004, AEM was committed to purchase 55.7 Bcf within
one year and 11.1 Bcf within one to three years under
indexed contracts. AEM is committed to purchase 0.5 Bcf
within one year and 0.1 Bcf within one to three years under
fixed-price contracts with prices ranging from $4.08 to $6.25.
Purchases under these contracts totaled $1,252.2 million,
$1,454.8 million and $725.6 million for 2004, 2003 and
2002.
Our utility segment maintains supply contracts
with several vendors, generally for 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.
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, 2004 and 2003, we
recorded receivables of $25.5 million and
102
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$28.4 million and recorded income of
$1.9 million, $2.0 million and $0.7 million for
fiscal years 2004, 2003 and 2002. The future minimum lease
payments to be received for each of the five succeeding years
are as follows:
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 20 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
$5.8 million and $5.2 million at September 30,
2004 and 2003. Accumulated depreciation for these capital leases
totaled $2.4 million and $2.2 million at
September 30, 2004 and 2003. 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, 2004 were as follows:
Consolidated lease and rental expense amounted to
$8.1 million, $8.9 million and $8.1 million for
fiscal 2004, 2003 and 2002.
Credit risk is the risk of financial loss to us
if a customer fails to perform its contractual obligations. We
engage in transactions for the purchase and sale of products and
services with major companies in the energy industry and with
industrial, commercial, residential and municipal energy
consumers. These transactions principally occur in the southern
and midwestern 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 for the utility segment is
mitigated by the large number of individual customers and
103
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
diversity in customer base. Due to minimal
receivables, the credit risk for our other nonutility segment is
not significant.
The diversification in AEMs customers helps
mitigate its credit exposure. AEM maintains credit policies with
respect to its counterparties that it believes minimizes overall
credit risk. Where appropriate, such policies include the
evaluation of a prospective counterpartys financial
condition, collateral requirements and the use of standardized
agreements that facilitate the netting of cash flows associated
with a single counterparty. AEM also monitors the financial
condition of existing counterparties on an ongoing basis.
Customers not meeting minimum standards are required to provide
adequate assurance of financial performance.
AEM maintains 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.
AEMs estimated credit exposure is monitored
in terms of the percentage of its customers that are rated as
investment grade versus non-investment grade. Credit exposure is
defined as the total of (1) accounts receivable,
(2) delivered, but unbilled physical sales and
(3) mark-to-market exposure for sales and purchases.
Investment grade determinations are set internally by the credit
department, but are primarily based on external ratings provided
by Moodys Investor Service and/or Standard &
Poors Rating Service. For non-rated entities, the default
rating for municipalities is investment grade, while the default
rating for non-guaranteed industrials and commercials is
non-investment grade. The table below shows the percentages
related to the investment ratings as of September 30, 2004
and 2003. As indicated below, a majority of AEMs customers
are rated as investment grade.
The following table presents our derivative
counterparty credit exposure by operating segment based upon the
unrealized fair value of our derivative contracts that represent
assets as of September 30, 2004. Investment grade
counterparties have minimum credit ratings of BBB-, assigned by
Standard & Poors Rating Group; or Baa3, assigned
by Moodys Investor Service. Non-investment grade
counterparties are composed of counterparties that are below
investment grade or 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
composed of numerous smaller counterparties, none of which is
individually significant.
104
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Supplemental disclosures of cash flow information
for 2004, 2003 and 2002 are presented below.
There were no significant noncash transactions
during fiscal 2004. 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
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.
Atmos Energy Corporation and its subsidiaries are
engaged primarily in the natural gas utility business as well as
certain nonutility 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 covered service areas located in
12 states. In addition, we transport natural gas for others
through our distribution system.
Through our nonutility businesses, we provide
natural gas management and marketing services to industrial
customers, municipalities and other local distribution companies
located in 18 states.
Our operations are divided into three segments:
105
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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.
106
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
107
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes our revenues by
products and services for the year ended September 30.
108
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Balance sheet information at September 30,
2004 and 2003 by segment is presented in the following tables:
109
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
110
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
partially insulate us and our customers from gas price
volatility.
Atmos Pipeline and Storage (APS) provides
asset management services for certain of our utility storage
fields in exchange for a contractually negotiated demand charge.
Atmos Energy Services (AES) provides natural
gas management services for our own utility operations. Prior to
the second quarter of fiscal 2004, this entity conducted limited
operations. However, beginning April 1, 2004, AES began
providing natural gas supply management services to our utility
operations in a limited number of states. These services include
aggregating and purchasing gas supply, arranging transportation
and storage logistics and ultimately delivering the gas to our
utility service areas at competitive prices. We have expanded
these services to substantially all of our utility service areas
as of the end of fiscal 2004.
The following summarizes our significant
affiliate transactions with AEM, APS and AES.
JD Woodward became Senior Vice President,
Nonutility 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 2004, 2003 and 2002, our utility division
leased office space and vehicles from our natural gas marketing
and other nonutility segments. Base lease payments were
$1.2 million in 2004 and 2003 and $1.4 million in 2002.
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.
111
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
Managements Discussion and Analysis of Financial
Condition and Results of Operations section herein.
112
1.
Nature of Business
Division
Service Area
Colorado, Kansas, Missouri
(1)
Kentucky
Louisiana
Georgia
(1)
, Illinois
(1)
,
Iowa
(1)
, Missouri
(1)
, Tennessee,
Virginia
(1)
Texas
Mississippi
(1)
Denotes locations where we have more limited
service areas.
(2)
The name of this division was changed from the
Atmos Energy Texas Division in November 2004.
(3)
Acquired in December 2002.
Table of Contents
2.
Summary of Significant Accounting
Policies
Table of Contents
September 30
2004
2003
(In thousands)
$
$
308
15,484
23,380
751
4,645
4,057
4,057
4,441
2,509
$
24,733
$
34,899
$
39,097
$
111,232
108,405
1,962
1,883
$
152,291
$
110,288
Table of Contents
Table of Contents
Table of Contents
Utility Segment
Natural Gas Marketing Segment
Table of Contents
Treasury Activities
Table of Contents
Year ended September 30
2004
2003
2002
(In thousands, except per share data)
$
86,227
$
71,688
$
59,656
978
370
487
(2,092
)
(1,362
)
(974
)
$
85,113
$
70,696
$
59,169
$
1.60
$
1.55
$
1.45
$
1.57
$
1.53
$
1.44
$
1.58
$
1.54
$
1.45
$
1.56
$
1.52
$
1.43
Table of Contents
TXU Gas Company
Table of Contents
$
1,905,000
7,540
$
1,912,540
$
1,496,453
62,737
148,902
16,843
465,188
39,548
(44,359
)
(68,463
)
(138,991
)
(65,318
)
$
1,912,540
Table of Contents
Year ended
September 30,
2004
$
4,174,500
118,746
$
1.68
ComFurT Gas Inc.
Mississippi Valley Gas
Company
4.
Goodwill and Intangible Assets
September 30
2004
2003
(In thousands)
$
234,112
$
268,469
4,160
5,030
$
238,272
$
273,499
Table of Contents
Natural Gas
Other
Utility
Marketing
Nonutility
Segment
Segment
Segment
Total
(In thousands)
$
233,741
$
22,600
$
12,128
$
268,469
1,250
1,250
(39,933
)
1,408
(38,525
)
1,698
(1,698
)
2,644
274
2,918
$
199,400
$
24,282
$
10,430
$
234,112
(1)
During the preparation of the fiscal 2004 tax
provision, we adjusted certain deferred taxes recorded in
connection with a fiscal 2001 acquisition which resulted in a
decrease to goodwill and deferred tax liabilities of
$38.5 million.
(2)
During 2004, we transferred Atmos Pipeline and
Storages underground storage fields in Kansas to our Atmos
Energy Colorado-Kansas utility division. As a result of the
transfer, approximately $1.7 million in goodwill was
transferred from the other nonutility segment to the utility
segment.
September 30, 2004
September 30, 2003
Useful
Gross
Gross
Life
Carrying
Accumulated
Carrying
Accumulated
(Years)
Amount
Amortization
Net
Amount
Amortization
Net
(In thousands)
10
$
6,521
$
(2,361
)
$
4,160
$
6,521
$
(1,574
)
$
4,947
3
250
(250
)
250
(167
)
83
$
6,771
$
(2,611
)
$
4,160
$
6,771
$
(1,741
)
$
5,030
Table of Contents
5.
Derivative Instruments and Hedging
Activities
Natural Gas
Utility
Marketing
Total
(In thousands)
$
25,692
$
18,748
$
44,440
562
562
(34,304
)
(5,154
)
(39,458
)
(1,138
)
(1,138
)
$
(8,612
)
$
13,018
$
4,406
$
202
$
22,057
$
22,259
1,699
1,699
(7,941
)
(12,849
)
(20,790
)
(763
)
(763
)
$
(7,739
)
$
10,144
$
2,405
Utility Hedging Activities
Table of Contents
Nonutility Hedging Activities
Adoption of EITF 02-03
Treasury Activities
Table of Contents
Year Ended
September 30,
2004
(In thousands)
$
(21,268
)
11,078
(3,495
)
$
(13,685
)
(1)
Utilizing an income tax rate of approximately 38%
comprised of the effective rates in each taxing jurisdiction.
Treasury
lock
Forward
agreements
Contracts
Total
(In thousands)
$
(2,839
)
$
7,159
$
4,320
(2,839
)
417
(2,422
)
(2,839
)
7
(2,832
)
(2,839
)
(2,839
)
(2,839
)
(2,839
)
(7,073
)
(7,073
)
$
(21,268
)
$
7,583
$
(13,685
)
Table of Contents
Long-term debt
2004
2003
(In thousands)
$
2,303
$
2,303
350,000
350,000
250,000
250,000
10,000
10,000
10,000
10,000
150,000
150,000
17,000
17,000
11,250
13,750
16,000
17,000
2,160
18,000
18,000
20,000
20,000
4,167
6,733
9,830
6,317
868,550
873,263
(1,331
)
(1,418
)
(5,908
)
(9,345
)
$
861,311
$
862,500
Table of Contents
$
5,908
7,055
7,394
7,206
5,410
835,577
$
868,550
Short-term debt
Table of Contents
Committed credit facilities
Uncommitted credit facilities
Table of Contents
7.
Shareholders Equity
Stock Issuances
Shareholder Rights Plan
Table of Contents
ten business days following a public announcement
that a person or group of affiliated or associated persons has
acquired, or obtained the right to acquire, beneficial ownership
of 15 percent or more of the outstanding shares of our
common stock, other than as a result of repurchases of stock by
us or specified inadvertent actions by institutional or other
shareholders;
ten business days, or such later date as our
Board of Directors shall determine, following the commencement
of a tender offer or exchange offer that would result in a
person or group having acquired, or obtained the right to
acquire, beneficial ownership of 15 percent or more of the
outstanding shares of our common stock; or
ten business days after our Board of Directors
shall declare any person to be an adverse person within the
meaning of the rights plan.
Registration Rights and Other
Agreements
Table of Contents
8.
Stock and Other Compensation Plans
Stock-Based Compensation
Plans
1998 Long-Term Incentive Plan
2004
2003
2002
Weighted
Weighted
Weighted
Average
Average
Average
Number of
Exercise
Number of
Exercise
Number of
Exercise
Options
Price
Options
Price
Options
Price
1,827,310
$
21.91
1,557,606
$
21.87
1,009,330
$
21.43
8,118
24.44
411,860
21.37
607,877
22.35
(342,252
)
20.91
(92,989
)
17.79
(19,102
)
16.69
(999
)
22.49
(49,167
)
23.89
(40,499
)
20.53
1,492,177
$
22.10
1,827,310
$
21.91
1,557,606
$
21.87
1,006,859
$
22.23
868,199
$
21.69
532,729
$
21.81
Table of Contents
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
100,498
5.5
$
15.79
100,498
$
15.79
20,000
5.9
$
19.66
20,000
$
19.66
905,028
7.7
$
21.92
434,628
$
22.09
466,651
5.8
$
23.91
451,733
$
23.91
1,492,177
7.0
$
22.10
1,006,859
$
22.23
Year ended
September 30
2004
2003
2002
7
7
7
4.3
%
4.0
%
3.9
%
22.8
%
23.3
%
24.2
%
4.8
%
4.8
%
4.8
%
Long-Term Stock Plan for the Mid-States
Division
Restricted Stock Plans
Table of Contents
Year ended September 30
2004
2003
2002
134,257
82,933
22,204
$24.76
$21.34
$
21.30
$ 978
$ 370
$
487
239,919
101,486
54,079
Other Plans
Direct Stock Purchase Plan
Outside Directors Stock-For-Fee Plan
Equity Incentive and Deferred Compensation
Plan for Non-Employee Directors
Variable Pay Plan
Table of Contents
9.
Retirement and Post-Retirement Employee
Benefit Plans
Defined benefit plans
Employee Pension Plans
Table of Contents
Actual
Allocation
September 30,
Targeted
Security Class
Allocation Range
2004
2003
45% - 55%
49.8
%
47.5
%
10% - 20%
17.1
%
15.9
%
25% - 45%
32.1
%
36.5
%
NA
1.0
%
0.1
%
Table of Contents
2004
2003
(In thousands)
$
330,344
$
226,197
7,696
6,693
19,691
19,044
(16,803
)
47,410
52,210
(1,771
)
(27,931
)
(19,439
)
312,997
330,344
322,703
209,941
51,390
8,513
46,326
77,362
(27,931
)
(19,439
)
346,162
322,703
33,165
(7,641
)
(6,967
)
(7,995
)
87,668
132,332
$
113,866
$
116,696
2004
2003
6.25
%
6.00
%
4.00
%
4.00
%
8.75
%
9.00
%
Table of Contents
Year Ended September 30
2004
2003
2002
(In thousands)
$
7,696
$
6,693
$
5,247
19,691
19,044
15,544
(30,097
)
(23,950
)
(23,298
)
(72
)
(1,028
)
(883
)
(883
)
6,555
1,756
$
2,817
$
2,660
$
(3,462
)
2004
2003
2002
6.00
%
7.25
%
7.50
%
4.00
%
4.00
%
4.00
%
9.00
%
9.25
%
10.00
%
Supplemental Executive Benefits
Plans
Table of Contents
2004
2003
(In thousands)
$
71,659
$
59,152
2,037
1,548
4,324
4,294
(682
)
9,900
(3,340
)
(3,235
)
73,998
71,659
3,340
3,235
(3,340
)
(3,235
)
(73,998
)
(71,659
)
4
100
3,728
4,750
20,987
24,349
$
(49,279
)
$
(42,460
)
2004
2003
6.25
%
6.00
%
4.00
%
4.00
%
NA
NA
Table of Contents
Unrealized
Holding
Market
Cost
Gain (Loss)
Value
(In thousands)
$
29,894
$
(1,537
)
$
28,357
3,279
298
3,577
$
33,173
$
(1,239
)
$
31,934
$
28,540
$
(2,359
)
$
26,181
3,195
9
3,204
$
31,735
$
(2,350
)
$
29,385
Less than 12 months
12 months or more
Unrealized
Unrealized
Fair Value
Loss
Fair Value
Loss
(In thousands)
$
3,445
$
(240
)
$
16,600
$
(1,867
)
$
3,445
$
(240
)
$
16,600
$
(1,867
)
Year Ended September 30
2004
2003
2002
(In thousands)
$
2,037
$
1,548
$
1,028
4,324
4,294
3,938
96
96
96
1,022
1,022
1,022
1,516
772
542
$
8,995
$
7,732
$
6,626
Table of Contents
2004
2003
2002
6.00
%
7.25
%
7.50
%
4.00
%
4.00
%
4.00
%
NA
NA
NA
Supplemental Disclosures For Defined Benefit
Plans with Accumulated Benefit Obligations in Excess of Plan
Assets
Employee Pension
Supplemental
Plans
Plans
2004
2003
2004
2003
(In thousands)
$
8,840
$
330,344
$
73,998
$
71,659
6,555
323,663
64,754
62,642
4,482
322,703
Estimated Future Benefit Payments
Pension
Supplemental
Plans
Plans
(In thousands)
$
25,723
$
3,249
25,070
3,205
26,064
3,564
26,042
3,709
27,484
3,696
145,213
23,627
Postretirement Benefits
Table of Contents
Actual
Allocation
September 30
Security Class
2004
2003
82.0
%
84.3
%
9.9
%
5.0
%
4.3
%
4.9
%
3.8
%
5.8
%
(1)
This fund invests in a diversified portfolio of
common stocks, preferred stocks and fixed income securities. It
may invest up to 75 percent of assets in common stocks and
convertible securities.
Table of Contents
2004
2003
(In thousands)
$
137,285
$
112,295
5,941
5,902
7,355
9,078
1,900
306
(17,038
)
5,786
13,647
(10,254
)
(9,729
)
125,189
137,285
26,310
16,250
4,695
(4,056
)
13,757
18,618
1,900
306
4,921
(10,254
)
(9,729
)
36,408
26,310
(88,781
)
(110,975
)
14,176
15,687
780
1,166
12,981
38,543
$
(60,844
)
$
(55,579
)
2004
2003
6.25
%
6.00
%
5.30
%
5.30
%
10.00
%
9.00
%
5.00
%
5.00
%
2010
2008
Table of Contents
Year Ended September 30
2004
2003
2002
(In thousands)
$
5,941
$
5,902
$
2,891
7,355
9,078
6,199
(1,523
)
(1,012
)
(759
)
1,511
1,511
1,511
386
368
520
635
1,778
$
14,305
$
17,625
$
10,362
2004
2003
2002
6.19
%
7.25
%
7.50
%
5.30
%
5.30
%
5.30
%
9.00
%
10.00
%
7.00
%
5.00
%
5.00
%
5.00
%
2008
2008
2003
1-Percentage
1-Percentage
Point Increase
Point Decrease
(In thousands)
$
1,093
$
(957
)
$
4,269
$
(3,736
)
Table of Contents
Estimated Future Benefit Payments
Total
Company
Retiree
Postretirement
Payments
Payments
Benefits
(In thousands)
$
11,698
$
2,811
$
14,509
9,144
3,144
12,288
8,473
3,284
11,757
8,920
3,550
12,470
9,453
3,859
13,312
55,931
22,328
78,259
Defined Contribution Plans
Table of Contents
10.
Details of Selected Consolidated Balance Sheet
Captions
Accounts receivable
September 30
2004
2003
(In thousands)
$
187,306
$
197,341
15,991
22,325
15,727
10,168
219,024
229,834
(7,214
)
(13,051
)
$
211,810
$
216,783
Other current assets
September 30
2004
2003
(In thousands)
$
44,440
$
22,259
9,194
8,187
2,973
2,973
2,626
3,917
308
4,003
1,219
$
63,236
$
38,863
Table of Contents
Property, plant and equipment
September 30
2004
2003
(In thousands)
$
4,288
$
8,003
58,075
64,714
134,174
122,014
1,971,124
1,851,228
382,220
376,777
45,493
41,256
2,595,374
2,463,992
38,277
16,147
2,633,651
2,480,139
(911,130
)
(855,745
)
$
1,722,521
$
1,624,394
Deferred charges and other
assets
September 30
2004
2003
(In thousands)
$
113,866
$
116,696
31,934
29,385
22,511
25,403
21,071
24,733
34,591
11,746
11,746
14,588
16,322
562
1,699
12,038
12,692
$
231,978
$
269,605
Table of Contents
Other current liabilities
September 30
2004
2003
(In thousands)
$
44,474
$
41,068
15,729
11,480
39,097
21,893
20,972
39,458
20,790
22,930
9,746
5,300
5,300
7,653
6,034
26,731
18,567
$
223,265
$
133,957
Deferred credits and other
liabilities
September 30
2004
2003
(In thousands)
$
51,772
$
50,334
48,448
42,327
14,120
13,701
1,138
763
7,021
12,197
20,637
18,686
$
143,136
$
138,008
Table of Contents
11.
Earnings Per Share
2004
2003
2002
(In thousands, except per share data)
$
86,227
$
79,461
$
59,656
(7,773
)
$
86,227
$
71,688
$
59,656
54,021
46,319
41,171
281
109
54
114
68
25
54,416
46,496
41,250
$
1.60
$
1.72
$
1.45
(.17
)
$
1.60
$
1.55
$
1.45
$
1.58
$
1.71
$
1.45
(.17
)
$
1.58
$
1.54
$
1.45
Table of Contents
12.
Income Taxes
2004
2003
2002
(In thousands)
$
9,003
$
(13,446
)
$
17,638
2,021
(441
)
3,575
35,970
54,656
12,964
5,079
6,690
1,420
(535
)
(549
)
(417
)
$
51,538
$
46,910
$
35,180
2004
2003
2002
(In thousands)
$
51,538
$
46,910
$
35,180
(5,117
)
$
51,538
$
41,793
$
35,180
2004
2003
2002
(In thousands)
$
48,218
$
44,230
$
33,193
(985
)
(993
)
(707
)
4,615
4,062
3,489
(310
)
(389
)
(795
)
$
51,538
$
46,910
$
35,180
Table of Contents
2004
2003
(In thousands)
$
1,029
$
2,336
8,563
5,254
5,579
6,158
21,171
17,435
21,665
21,186
13,035
1,000
564
1,192
1,271
15,761
29,257
14,858
4,373
7,198
108,226
90,659
(264,239
)
(257,679
)
(43,798
)
(42,681
)
(429
)
(3,154
)
(3,154
)
(7,288
)
(8,054
)
(3,677
)
(2,012
)
(322,156
)
(314,009
)
$
(213,930
)
$
(223,350
)
$
2,457
$
2,080
13.
Commitments and Contingencies
Litigation
Colorado-Kansas Division
Table of Contents
West Texas Division
United Cities Propane Gas, Inc.
Table of Contents
Environmental Matters
Manufactured Gas Plant Sites
Table of Contents
Mercury Contamination Sites
Purchase Commitments
14.
Leases
Leasing Operations
Table of Contents
Minimum
Lease Receipts
(In thousands)
$
2,973
2,973
2,973
2,973
2,973
10,619
$
25,484
Capital and Operating Leases
Capital
Operating
Leases
Leases
(In thousands)
$
1,139
$
9,648
631
8,726
433
8,248
362
8,197
311
7,479
1,667
37,753
4,543
$
80,051
(1,753
)
$
2,790
15.
Concentration of Credit Risk
Table of Contents
September 30,
September 30,
2004
2003
55
%
59
%
45
%
41
%
100
%
100
%
At September 30, 2004
Natural Gas
Other
Utility
Marketing
Nonutility
Segment
(1)
Segment
Segment
Consolidated
(In thousands)
$
25,692
$
18,888
$
$
44,580
422
422
$
25,692
$
19,310
$
$
45,002
(1)
Counterparty risk for our utility segment is
minimized because hedging gains and losses are passed through to
our customers.
Table of Contents
16.
Supplemental Cash Flow Disclosures
2004
2003
2002
(In thousands)
$
65,700
$
62,088
$
59,639
$
1,677
$
408
$
16,588
17.
Segment Information
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 nonutility segment, which includes all
of our other nonutility operations.
Table of Contents
For the Year Ended September 30, 2004
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
1,636,636
$
1,279,424
$
3,977
$
$
2,920,037
1,092
339,178
19,174
(359,444
)
1,637,728
1,618,602
23,151
(359,444
)
2,920,037
1,134,594
1,571,971
9,383
(358,102
)
2,357,846
503,134
46,631
13,768
(1,342
)
562,191
92,954
2,089
1,604
96,647
250,290
16,816
6,119
(1,376
)
271,849
159,890
27,726
6,045
34
193,695
5,847
843
8,579
(5,762
)
9,507
65,399
2,711
3,055
(5,728
)
65,437
100,338
25,858
11,569
137,765
37,242
9,225
5,071
51,538
$
63,096
$
16,633
$
6,498
$
$
86,227
$
189,291
$
520
$
474
$
$
190,285
Table of Contents
For the Year Ended September 30, 2003
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
1,552,857
$
1,234,447
$
12,612
$
$
2,799,916
1,225
434,046
9,018
(444,289
)
1,554,082
1,668,493
21,630
(444,289
)
2,799,916
1,062,679
1,644,328
1,540
(443,607
)
2,264,940
491,403
24,165
20,090
(682
)
534,976
83,849
1,261
1,891
87,001
246,420
9,335
5,062
(682
)
260,135
161,134
13,569
13,137
187,840
(218
)
1,855
5,004
(4,450
)
2,191
63,226
2,864
2,020
(4,450
)
63,660
97,690
12,560
16,121
126,371
35,553
5,757
5,600
46,910
62,137
6,803
10,521
79,461
(7,773
)
(7,773
)
$
62,137
$
(970
)
$
10,521
$
$
71,688
$
154,777
$
1,884
$
2,778
$
$
159,439
Table of Contents
For the Year Ended September 30, 2002
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
$
936,054
$
700,519
$
14,391
$
$
1,650,964
1,472
331,355
10,314
(343,141
)
937,526
1,031,874
24,705
(343,141
)
1,650,964
559,891
994,318
8,022
(342,407
)
1,219,824
377,635
37,556
16,683
(734
)
431,140
77,704
2,069
1,696
81,469
174,425
14,877
5,772
(734
)
194,340
125,506
20,610
9,215
155,331
1,427
1,331
554
(4,633
)
(1,321
)
58,796
2,866
2,145
(4,633
)
59,174
68,137
19,075
7,624
94,836
25,143
6,461
3,576
35,180
$
42,994
$
12,614
$
4,048
$
$
59,656
$
129,632
$
779
$
1,841
$
$
132,252
2004
2003
2002
(In thousands)
$
923,773
$
873,375
$
535,981
400,704
367,961
221,728
77,178
65,921
31,731
187,187
192,676
98,765
1,588,842
1,499,933
888,205
30,622
29,583
36,591
17,172
23,341
11,258
1,636,636
1,552,857
936,054
1,279,424
1,234,447
700,519
3,977
12,612
14,391
$
2,920,037
$
2,799,916
$
1,650,964
Table of Contents
At September 30, 2004
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
ASSETS
$
1,669,304
$
7,875
$
45,342
$
$
1,722,521
164,300
(1,484
)
(162,816
)
182,846
18,734
352
201,932
25,692
24,412
(5,664
)
44,440
253,829
170,363
32,288
(25,740
)
430,740
1,995
7,911
(9,906
)
464,362
213,509
40,551
(41,310
)
677,112
4,160
4,160
199,400
24,282
10,430
234,112
734
(172
)
562
207,019
1,661
22,736
231,416
$
2,704,385
$
250,737
$
119,059
$
(204,298
)
$
2,869,883
CAPITALIZATION AND LIABILITIES
$
1,133,459
$
103,376
$
60,924
$
(164,300
)
$
1,133,459
853,472
7,839
861,311
1,986,931
103,376
68,763
(164,300
)
1,994,770
3,917
1,991
5,908
34,304
11,407
(6,253
)
39,458
236,257
124,577
31,572
(23,304
)
369,102
9,906
(9,906
)
274,478
145,890
33,563
(39,463
)
414,468
208,325
(3,360
)
8,938
27
213,930
1,700
(562
)
1,138
103,579
103,579
131,072
3,131
7,795
141,998
$
2,704,385
$
250,737
$
119,059
$
(204,298
)
$
2,869,883
Table of Contents
At September 30, 2003
Natural Gas
Other
Utility
Marketing
Nonutility
Eliminations
Consolidated
(In thousands)
ASSETS
$
1,555,381
$
9,288
$
59,725
$
$
1,624,394
133,586
(2,662
)
(130,924
)
14,880
803
15,683
202
22,941
(884
)
22,259
230,609
197,239
85,119
(92,912
)
420,055
114,550
(114,550
)
345,361
235,060
85,922
(208,346
)
457,997
5,030
5,030
233,741
22,600
12,128
268,469
1,896
(197
)
1,699
21,071
21,071
218,840
2,214
25,781
246,835
$
2,486,909
$
273,426
$
204,627
$
(339,467
)
$
2,625,495
CAPITALIZATION AND LIABILITIES
$
857,517
$
74,759
$
58,827
$
(133,586
)
$
857,517
857,302
5,198
862,500
1,714,819
74,759
64,025
(133,586
)
1,720,017
8,227
1,118
9,345
118,595
118,595
7,941
13,400
(551
)
20,790
190,399
183,082
10,008
(90,470
)
293,019
5,549
109,001
(114,550
)
325,162
202,031
120,127
(205,571
)
441,749
221,912
(9,498
)
11,081
(145
)
223,350
928
(165
)
763
102,371
102,371
122,645
5,206
9,394
137,245
$
2,486,909
$
273,426
$
204,627
$
(339,467
)
$
2,625,495
Table of Contents
18.
Related Party Transactions
2004
2003
2002
(In thousands, unless otherwise indicated)
$
235,320
$
333,390
$
190,594
42,518
62,729
67,657
$
5.53
$
5.31
$
2.82
$
2,765
$
4,236
$
4,305
$
682
$
$
(1)
Gas purchases are made in a competitive bidding
process, reflect market prices and exclude demand and other
charges.
Table of Contents
19.
Selected Quarterly Financial Data
(Unaudited)
Quarter Ended
December 31
March 31
June 30
September 30
(In thousands, except per share data)
$
460,488
$
708,282
$
256,252
$
212,706
373,829
517,218
364,339
363,216
3,628
10,654
6,210
2,659
(74,329
)
(118,669
)
(80,743
)
(85,703
)
763,616
1,117,485
546,058
492,878
159,053
206,126
107,492
89,520
63,541
105,414
21,460
3,280
29,541
58,305
4,765
(6,384
)
$
0.57
$
1.12
$
0.09
$
(0.11
)
$
0.57
$
1.12
$
0.09
$
(0.11
)
$
399,968
$
696,561
$
245,998
$
211,555
343,498
620,402
374,832
329,761
2,900
9,657
3,685
5,388
(65,934
)
(132,478
)
(136,045
)
(109,832
)
680,432
1,194,142
488,470
436,872
137,166
202,968
95,064
99,778
52,624
107,878
14,056
13,282
25,793
56,305
(201
)
(2,436
)
(7,773
)
25,793
48,532
(201
)
(2,436
)
$
.60
$
1.24
$
(.00
)
$
(.05
)
$
$
(.17
)
$
$
$
.60
$
1.07
$
(.00
)
$
(.05
)
Table of Contents
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 2004 that has materially affected or is reasonably likely to materially affect the Companys internal control over financial reporting.
Item 9B. Other Information
None.
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 Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005. 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 Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005.
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 Companys Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Companys principal executive officer and senior financial officers. A copy of the Companys Code of Conduct is posted on the Companys website at www.atmosenergy.com under Corporate Governance. In addition, any amendment to or waiver granted from, a provision of the Companys Code of Conduct will be posted on the Companys website under Corporate Governance.
Item 11. | Executive Compensation |
Incorporated herein by reference from the Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005.
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Incorporated herein by reference from the Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005.
113
Item 13. | Certain Relationships and Related Transactions |
Incorporated herein by reference from the Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005.
Item 14. | Principal Accountant Fees and Services |
Incorporated herein by reference from the Companys Definitive Proxy Statement for the Annual Meeting of Shareholders on February 9, 2005.
PART IV
Item 15. | Exhibits and Financial Statement Schedules |
(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 10.8(a) through 10.19(b) are management contracts or compensatory plans or arrangements.
114
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 19, 2004
115
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
Robert W. Best |
Chairman, President and Chief Executive Officer | November 19, 2004 | ||||
/s/ JOHN P. REDDY
John P. Reddy |
Senior Vice President and Chief Financial Officer | November 19, 2004 | ||||
/s/ F.E. MEISENHEIMER
F.E. Meisenheimer |
Vice President and Controller (Principal Accounting Officer) | November 19, 2004 | ||||
/s/ TRAVIS W. BAIN, II
Travis W. Bain, II |
Director | November 19, 2004 | ||||
/s/ DAN BUSBEE
Dan Busbee |
Director | November 19, 2004 | ||||
/s/ RICHARD W. CARDIN
Richard W. Cardin |
Director | November 19, 2004 | ||||
/s/ THOMAS J. GARLAND
Thomas J. Garland |
Director | November 19, 2004 | ||||
/s/ RICHARD K. GORDON
Richard K. Gordon |
Director | November 19, 2004 | ||||
/s/ GENE C. KOONCE
Gene C. Koonce |
Director | November 19, 2004 | ||||
/s/ THOMAS C. MEREDITH
Thomas C. Meredith |
Director | November 19, 2004 | ||||
/s/ PHILLIP E. NICHOL
Phillip E. Nichol |
Director | November 19, 2004 |
116
/s/ NANCY K. QUINN
Nancy K. Quinn |
Director | November 19, 2004 | ||||
/s/ CHARLES K. VAUGHAN
Charles K. Vaughan |
Director | November 19, 2004 | ||||
/s/ RICHARD WARE II
Richard Ware II |
Director | November 19, 2004 |
117
SCHEDULE II
ATMOS ENERGY CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
Additions
Balance at
Charged to
Charged to
Balance
Beginning
cost &
other
at End
of Period
expenses
accounts
Deductions
of Period
$
13,051
$
5,379
$
$
11,216
(2)
$
7,214
$
10,509
$
13,249
$
$
10,707
(2)
$
13,051
$
16,151
$
$
1,500
(1)
$
7,142
(2)
$
10,509
(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. |
118
EXHIBITS INDEX
Page Number or | ||||||
Exhibit | Incorporation by | |||||
Number | Description | Reference to | ||||
|
|
|
||||
Plan of Reorganization | ||||||
2 | .1 | Purchase and Sale Agreement (Louisiana Gas Operations), by and among Citizens Utilities Company (now known as Citizens Communications Company), LGS Natural Gas Company and Atmos Energy Corporation, dated as of April 13, 2000 | Exhibit 2.1 to Registration Statement on Form S-3/A filed November 6, 2000 (File No. 333-73705) | |||
2 | .2 | Agreement and Plan of Merger and Reorganization dated as of September 21, 2001, by and among Atmos Energy Corporation, Mississippi Valley Gas Company and the Shareholders Named on the Signature Pages hereto | Exhibit 2.2 of Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042) | |||
2 | .3(a) | Agreement and Plan of Merger by and between TXU Gas Company and LSG Acquisition Corporation dated June 17, 2004 | Exhibit 2.1 of Form 8-K dated June 17, 2004 (File No. 1-10042) | |||
2 | .3(b) | Amendment No. 1 to Merger Agreement, dated as of September 30, 2004, by and between LSG Acquisition Corporation and TXU Gas Company LP | Exhibit 2.1 of Form 8-K dated September 30, 2004 (File No. 1-10042) | |||
Articles of Incorporation and Bylaws | ||||||
3 | .1 | Amended and Restated Articles of Incorporation of Atmos Energy Corporation (as of February 10, 1999) | Exhibit 4.1 of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
3 | .2 | Amended and Restated Bylaws of Atmos Energy Corporation (as of August 13, 2003) | Exhibit 4.2 of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
Instruments Defining Rights of Security Holders | ||||||
4 | .1 | Specimen Common Stock Certificate (Atmos Energy Corporation) | Exhibit (4)(b) of Form 10-K for fiscal year ended September 30, 1988 (File No. 1-10042) | |||
4 | .2 | Rights Agreement, dated as of November 12, 1997, between the Company and BankBoston, N.A., as Rights Agent | Exhibit 4.1 of Form 8-K dated November 12, 1997 (File No. 1-10042) | |||
4 | .3 | First Amendment to Rights Agreement dated as of August 11, 1999, between the Company and BankBoston, N.A., as Rights Agent | Exhibit 2 of Form 8-A, Amendment No. 1, dated August 12, 1999 (File No. 1-10042) | |||
4 | .4 | Second Amendment to Rights Agreement dated as of February 13, 2002, between the Company and EquiServe Trust Company, N.A., fka BankBoston, N.A., as Rights Agent | Exhibit 4 of Form 10-Q for quarter ended December 31, 2001 (File No. 1-10042) | |||
4 | .5 | Registration Rights Agreement, dated as of June 30, 2003, between Atmos Energy Corporation and Gary A. Morris, as Asset Manager | Exhibit 4.1 of Form 10-Q for quarter ended June 30, 2003 (File No. 1-10042) | |||
4 | .6 | Registration Rights Agreement, dated as of December 3, 2002, by and among Atmos Energy Corporation and the Shareholders of Mississippi Valley Gas Company | Exhibit 99.2 of Form 8-K/A, dated December 3, 2002 (File No. 110042) | |||
4 | .7 | Standstill Agreement, dated as of December 3, 2002, by and among Atmos Energy Corporation and the Shareholders of Mississippi Valley Gas Company | Exhibit 99.3 of Form 8-K/A, dated December 3, 2002 (File No. 1-10042) | |||
4 | .8 | Indenture dated as of July 15, 1998 between Atmos Energy Corporation and U.S. Bank Trust National Association, Trustee | Exhibit 4.8 of Form S-3 dated August 31, 2004 (File No. 333-118706) |
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4 | .9 | Indenture between Atmos Energy Corporation, as Issuer, and Suntrust Bank, Trustee dated as of May 22, 2001 | Exhibit 99.3 of Form 8-K dated May 15, 2001 (File No. 1-10042) | |||
4 | .10(a) | Indenture of Mortgage, dated as of July 15, 1959, from United Cities Gas Company to First Trust of Illinois, National Association, and M.J. Kruger, as Trustees, as amended and supplemented through December 1, 1992 (the Indenture of Mortgage through the 20th Supplemental Indenture) | Exhibit to Registration Statement of United Cities Gas Company on Form S-3 (File No. 33-56983) | |||
4 | .10(b) | Twenty-First Supplemental Indenture dated as of February 5, 1997 by and among United 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 | Exhibit 10.7(a) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042) | |||
4 | .10(c) | Twenty-Second Supplemental Indenture dated as of July 29, 1997 by and among Atmos Energy Corporation and First Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959 | Exhibit 4.10(c) of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
4 | .11(a) | Indenture between United Cities Gas Company and Bank of America Illinois, as Trustee dated as of November 15, 1995 | Exhibit 4.11(a) of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
4 | .11(b) | First Supplemental Indenture between Atmos Energy Corporation and Bank of America Illinois, as Trustee dated as of July 29, 1997 | Exhibit 4.11(b) of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
4 | .12(a) | Seventh Supplemental Indenture, dated as of October 1, 1983 between Greeley Gas Company (The Greeley Gas Division) and the Central Bank of Denver, N.A. (Central Bank) | Exhibit 10.1 of Form 10-Q for quarter ended June 30, 1994 (File No. 1-10042) | |||
4 | .12(b) | Ninth Supplemental Indenture, dated as of April 1, 1991, between Greeley Gas Company and Central Bank Denver, N.A | Exhibit 4.12(b) of Form S-3 dated August 31, 2004 (File No. 333-118706) | |||
4 | .12(c) | Tenth Supplemental Indenture, dated as of December 1, 1993, between the Company and Colorado National Bank, formerly Central Bank | Exhibit 10.4 of Form 10-Q for quarter ended June 30, 1994 (File No. 1-10042) | |||
9 | Not Applicable | |||||
Material Contracts | ||||||
10 | .1 | Bond Purchase Agreement, dated as of April 1, 1991, between the Greeley Division and Central Bank | Exhibit 10.3 of Form 10-Q for quarter ended June 30, 1994 (File No. 1-10042) | |||
10 | .2(a) | Debenture Certificate for the 6 3/4% Debentures due 2028 | Exhibit 99.2 of Form 8-K dated July 22, 1998 (File No. 1-10042) | |||
10 | .2(b) | Global Security for the 7 3/8% Senior Notes due 2011 | Exhibit 99.2 of Form 8-K dated May 15, 2001 (File No. 1-10042) | |||
10 | .2(c) | Global Security for the 5 1/8% Senior Notes due 2013 | ||||
10 | .2(d) | Global Security for the Floating Rate Senior Notes due 2007 | ||||
10 | .2(e) | Global Security for the 4.00% Senior Notes due 2009 | ||||
10 | .2(f) | Global Security for the 4.95% Senior Notes due 2014 | ||||
10 | .2(g) | Global Security for the 5.95% Senior Notes due 2034 |
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10 | .3 | Revolving Credit Agreement, dated as of October 22, 2004, among Atmos Energy Corporation, Bank One, NA, as Administrative Agent, SunTrust Bank, as Syndication Agent and Bank of America, N.A., Wachovia Bank, National Association and Societe Generale, as Co-Documentation Agents, and the lenders identified therein | Exhibit 10.1 of Form 8-K dated October 21, 2004 (File No. 1-10042) | |||
10 | .4 | 364-Day Revolving Credit Agreement, dated as of September 24, 2004, by and among Atmos Energy Corporation, Bank One, NA, as Administrative Agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated , as Syndication Agent and Lead Arranger and Book Runner, Bank of America, N.A. and Suntrust Bank, as Co-Documentation Agents, and the Lenders identified therein | Exhibit 10.1 of Form 8-K dated September 24, 2004 (File No. 1-10042) | |||
10 | .5 | Guaranty of Atmos Energy Corporation dated June 17, 2004 | Exhibit 10.2 of Form 8-K dated June 17, 2004 (File No. 1-10042) | |||
10 | .6(a) | Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation and TXU Gas Company LP | Exhibit 10.1 of Form 8-K dated September 30, 2004 (File No. 1-10042) | |||
10 | .6(b) | Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation, Oncor Utility Solutions (Texas) Company and TXU Electric Delivery Company | Exhibit 10.2 of Form 8-K dated September 30, 2004 (File No. 1-10042) | |||
10 | .6(c) | Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation and TXU Business Services Company (Exhibit A to Schedule 2 containing listing of employee credit and procurement cards is omitted, to be supplementally furnished to the Commission upon request) | Exhibit 10.3 of Form 8-K dated September 30, 2004 (File No. 1-10042) | |||
10 | .6(d) | Transitional Access Agreement, dated as of October 1, 2004, by and among Atmos Energy Corporation and TXU Energy Retail Company LP, TXU Business Services Company, TXU Properties Company and TXU Electric Delivery Company | Exhibit 10.4 of Form 8-K dated September 30, 2004 (File No. 1-10042) | |||
10 | .7(a) | Uncommitted Amended and Restated Credit Agreement, dated to be effective 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 10.1 of Form 10-Q for quarter ended June 30, 2002 (File No. 1-10042) | |||
10 | . 7(b) | First Amendment, entered into effective as of December 23, 2002, 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 | Exhibit 10.1 of Form 10-Q for quarter ended March 31, 2003 (File No. 1-10042) | |||
10 | .7(c) | Second Amendment, entered into effective as of February 7, 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 | Exhibit 10.2 of Form 10-Q for quarter ended March 31, 2003 (File No. 1-10042) |
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10 | .7(d) | Third Amendment, entered into effective as of February 28, 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 | Exhibit 10.3 of Form 10-Q for quarter ended March 31, 2003 (File No. 1-10042) | |||
10 | .7(e) | Fourth Amendment, entered into effective as of March 31, 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 | Exhibit 10.4 of Form 10-Q for quarter ended March 31, 2003 (File No. 1-10042) | |||
10 | .7(f) | Fifth Amendment and Waiver, entered into effective as of April 28, 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 | Exhibit 10.5 of Form 10-Q for quarter ended March 31, 2003 (File No. 1-10042) | |||
10 | .7(g) | Sixth Amendment to Credit Agreement, Global Amendment to Loan Documents and Waiver, entered 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 | Exhibit 10.3(h) of Form 10-K for fiscal year ended September 30, 2003 (File No. 1-10042) | |||
10 | .7(h) | Seventh Amendment and Joinder Agreement, dated as of December 19, 2003, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC (formerly known as Woodward Marketing, L.L.C.), the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas | Exhibit 10.1 of Form 10-Q for quarter ended December 31, 2003 (File No. 1-10042) | |||
10 | .7(i) | Eighth Amendment and Joinder Agreement to Credit Agreement and First Amendment to Subordination, dated as of February 18, 2004, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC, the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas | Exhibit 10.1 of Form 10-Q for quarter ended March 31, 2004 (File No. 1-10042) | |||
10 | .7(j) | Ninth Amendment to Credit Agreement, dated as of March 31, 2004, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC, the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas | Exhibit 10.2 of Form 10-Q for quarter ended March 31, 2004 (File No. 1-10042) | |||
10 | .7 (k) | Tenth Amendment to Credit Agreement and First Amendment to Support Agreement, dated as of September 17, 2004, in respect of(i) the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC, the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas, and (ii) the Support Agreement, dated as of July 1, 2002, of Atmos Energy Corporation |
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Executive Compensation Plans and Arrangements | ||||||
10 | .8(a)* | Form of Atmos Energy Corporation Change in Control Severance Agreement Tier I | Exhibit 10.21(b) of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042) | |||
10 | .8(b)* | Form of Atmos Energy Corporation Change in Control Severance Agreement Tier II | Exhibit 10.21(c) of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042) | |||
10 | .9* | Atmos Energy Corporation Long-Term Stock Plan for the United Cities Gas Company Division | Exhibit 99.1 of Form S-8 filed July 29, 1997 (File No. 333-32343) | |||
10 | .10(a)* | Atmos Energy Corporation Executive Retiree Life Plan | Exhibit 10.31 of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042) | |||
10 | .10(b)* | Amendment No. 1 to the Atmos Energy Corporation Executive Retiree Life Plan | Exhibit 10.31(a) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042) | |||
10 | .11(a)* | Description of Financial and Estate Planning Program | Exhibit 10.25(b) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042) | |||
10 | .11(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 | .12(a)* | Atmos Energy Corporation Supplemental Executive Benefits Plan, Amended and Restated in its Entirety August 12, 1998 | Exhibit 10.26 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042) | |||
10 | .12(b)* | Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan, Effective Date August 12, 1998 | Exhibit 10.32 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042) | |||
10 | .12(c)* | Amendment No. One to the Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan, Effective Date January 1, 1999 | Exhibit 10.2 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042) | |||
10 | .12(d)* | Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000 | Exhibit 10.1 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042) | |||
10 | .12(e)* | Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan | Exhibit 10.3 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042) | |||
10 | .13* | Atmos Energy Corporation Restricted Stock Grant Plan (Amended and Restated as of February 12, 1998) | Exhibit 99.1 of Form S-8 filed February 13, 1998 (File No. 333-46337) | |||
10 | .14* | Atmos Energy Corporation Executive Nonqualified Deferred Compensation Plan | Exhibit 10.33 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042) | |||
10 | .15(a)* | Mini-Med/ Dental Benefit Extension Agreement dated October 1, 1994 | Exhibit 10.28(f) of Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042) | |||
10 | .15(b)* | Amendment No. 1 to Mini-Med/ Dental Benefit Extension Agreement dated August 14, 2001 | Exhibit 10.28(g) of Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042) | |||
10 | .15(c)* | Amendment No. 2 to Mini-Med/ Dental Benefit Extension Agreement dated December 31, 2002 | Exhibit 10.1 of Form 10-Q for quarter ended December 31, 2002 (File No. 1-10042) |
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10 | .16* | Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors | Exhibit C of Definitive Proxy Statement on Schedule 14A filed December 30, 1998 (File No. 1-10042) | |||
10 | .17(a)* | Atmos Energy Corporation Retirement Plan for Outside Directors | Exhibit 10(y) of Form 10-K for fiscal year ended September 30, 1992 (File No. 1-10042) | |||
10 | .17(b)* | Amendment No. 1 to the Atmos Energy Corporation Retirement Plan for Outside Directors | Exhibit 10.2 of Form 10-Q for quarter ended December 31, 1996 (File No. 1-10042) | |||
10 | .18* | Atmos Energy Corporation Outside Directors Stock-for-Fee Plan (Amended and Restated as of November 12, 1997) | Exhibit 10.28 of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042) | |||
10 | .19(a)* | Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated February 14, 2002) | Exhibit 10.1 of Form 10-Q for quarter ended March 31, 2002 (File No. 1-10042) | |||
10 | .19(b)* | Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 14, 2002) | Exhibit 10.2 of Form 10-Q for quarter ended March 31, 2002 (File No. 1-10042) | |||
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, 2004 | ||||
31 | Rule 13a-14(a)/15d-14(a) Certifications | |||||
32 | Section 1350 Certifications ** | |||||
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 Companys Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 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. |
124
EXHIBIT 10.2(c)
THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITORY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SECURITY IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITORY OR ITS NOMINEE EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE.
UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND SUCH CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY, ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL, SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
ATMOS ENERGY CORPORATION
5 1/8% Senior Notes due 2013
No. 1 CUSIP NO. 049560 AC 9
Atmos Energy Corporation, a Texas and Virginia corporation (herein called the "Company", which term includes any successor entity under the Indenture, hereinafter defined), for value received, hereby promises to pay to Cede & Co. or registered assigns the principal sum of TWO HUNDRED FIFTY MILLION DOLLARS ($250,000,000) on January 15, 2013 (the "Maturity Date"), at the office or agency of the Company referred to below, and to pay interest thereon from January 16, 2003, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semiannually on January 15 and July 15 in each year (each, an "Interest Payment Date"), commencing July 15, 2003 at 5 1/8% per annum until the principal hereof is paid or duly provided for.
Any payment of principal or interest required to be made on a day that is not a Business Day need not be made on such day, but may be made on the next succeeding Business Day with the same force and effect as if made on such day and no interest shall accrue as a result of such delayed payment. Interest payable on each Interest Payment Date will include interest accrued from and including January 16, 2003, or from and including the most recent Interest Payment Date to which interest has been paid or duly provided for, as the case may be, to but excluding such Interest Payment Date. Interest will be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person (the "Holder") in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the January 1 or July 1 (whether or not a Business Day) next preceding such Interest Payment Date (a "Regular Record Date"). Any such interest not so punctually paid or duly provided for ("Defaulted Interest") will forthwith cease to be payable to the Holder on such Regular Record Date and either may be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a special record date (the "Special Record Date") for the payment of such Defaulted Interest to be fixed by the Trustee (referred to herein), notice whereof shall be given to the Holder of this Security not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner, all as more fully provided in the Indenture.
For purposes of this Security, "Business Day" means any day that, in the city of the principal Corporate Trust Office of the Trustee and in the City of New York, is neither a Saturday, Sunday, or legal holiday nor a day on which banking institutions are authorized or required by law or regulation to close.
Payment of the principal of (and premium, if any) and interest on this Security will be made at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, or at such other office or agency of the Company as may be maintained for such purpose, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. So long as this Security remains in book-entry form, all payments of principal and interest will be made by the Company in immediately available funds.
Unless the certificate of authentication hereon has been duly executed by the Trustee by manual signature, this Security shall not be entitled to any benefit under the Indenture, or be valid or obligatory for any purpose.
This Security is one of a duly authorized series of securities of the Company, designated as the 5 1/8% Senior Notes due 2013 (the "Securities"), issued under an Indenture dated as of May 22, 2001, as it may be supplemented from time to time (referred to herein as the "Indenture"), between the Company and SunTrust Bank, as trustee (referred to herein as the "Trustee", which term includes any successor trustee under the Indenture with respect to the series of which this Security is a part). A reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties, obligations and immunities thereunder of the Company, the Trustee and the Holders of the Securities, and of the terms upon which the Securities are, and are to be, authenticated and delivered, except as otherwise provided herein.
The Securities are initially limited to $250,000,000 aggregate principal amount. The Company may, at any time, without the consent of the Holders of the Securities, create and issue additional securities having the same ranking, interest rate, maturity and other terms as the Securities. Any such additional securities shall be consolidated and form the same series of the Securities having the same terms as to status, redemption and otherwise as the Securities under the Indenture.
Events of Default. If an Event of Default shall occur and be continuing, the principal of all the Securities may be declared due and payable in the manner and with the effect provided in the Indenture.
Optional Redemption. The Securities will be redeemable, in whole or in part, at the Company's option, at any time at a Redemption Price equal to the greater of:
(a) 100% of the principal amount of the Securities to be redeemed, or
(b) as determined by the Quotation Agent, the sum of the present values of the Remaining Scheduled Payments of principal and interest on the Securities to be redeemed discounted to the Redemption Date on a semi-annual basis assuming a 360-day year consisting of twelve 30 day months at the Adjusted Treasury Rate plus 15 basis points;
plus, in either case, accrued and unpaid interest on the principal amount of Securities being redeemed to the Redemption Date.
"Adjusted Treasury Rate" means, for any Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for that Redemption Date.
"Comparable Treasury Issue" means the United States treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the Securities to be redeemed that would be used, at the time of a selection and in accordance with customary
financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Securities.
"Comparable Treasury Price" means, for any Redemption Date, the Reference Treasury Dealer Quotation for that Redemption Date.
"Quotation Agent" means the Reference Treasury Dealer appointed by the Company.
"Reference Treasury Dealer" means Banc One Capital Markets, Inc. and its successors; provided, however, if Banc One Capital Markets, Inc. ceases to be a primary U.S. government securities dealer in New York City, the Company will replace Banc One Capital Markets, Inc. as Reference Treasury Dealer with an entity that is a primary U.S. government securities dealer in New York City.
"Reference Treasury Dealer Quotation" means, with respect to any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed, in each case, as a percentage of its principal amount) quoted in writing to the Trustee by the Reference Treasury Dealer by 5:00 p.m. on the third business day preceding the Redemption Date.
"Remaining Scheduled Payments" means, with respect to each Security to be redeemed, the remaining scheduled payments of the principal and interest on such Security that would be due after the related Redemption Date but for such redemption; provided, however, that if such Redemption Date is not an Interest Payment Date, the amount of the next succeeding scheduled interest payment on such Security will be reduced by the amount of interest accrued on such Security to such Redemption Date.
In the event that less than all of the Securities are to be redeemed at any time, selection of such Securities for redemption will be made by The Depository Trust Company ("DTC") during any period the Securities are issued in the form of a global security registered in the name of DTC or a nominee thereof; provided that during any period the Securities are issued in certificated form, the selection of such Securities for redemption will be made by the Trustee by lot or by such other method as the Trustee in its sole discretion shall deem fair and appropriate. In no event shall Securities of a principal amount of $1,000 or less be redeemed in part. Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less than 30 nor more than 60 days before the Redemption Date, to each Holder of Securities to be redeemed, at its address as shown in the Security Register. If the Securities are to be redeemed in part only, the notice of redemption that relates to such Securities shall state the portion of the principal amount thereof to be redeemed. A new Security in a principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon surrender for cancellation of the original Security. On and after the Redemption Date, interest will cease to accrue on Securities or portions thereof called for redemption unless the Company defaults in the payment of the Redemption Price.
Sinking Fund. This Security does not have the benefit of any sinking fund obligations.
Modification and Waivers; Obligations of the Company Absolute. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of each series. Certain limited amendments may be effected under the Indenture at any time by the Company and the Trustee without the consent of the Holders of the Securities. Certain other amendments may only be effected under the Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities of such series at the time Outstanding and affected thereby. The Indenture also contains provisions permitting the Holders of not less than a majority in principal amount of the Securities at the time Outstanding, on behalf of the Holders of all Outstanding Securities, to waive compliance by the Company with certain provisions of the Indenture. Furthermore, provisions in the Indenture permit the Holders of not less than a majority in principal amount of the Outstanding Securities of individual series to waive on behalf of all of the Holders of Securities of such individual series certain past defaults under the Indenture and their consequences. Any such consent or waiver by or on behalf of the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof whether or not notation of such consent or waiver is made upon this Security.
No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of (and premium, if any) and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.
Defeasance and Covenant Defeasance. The Indenture contains provisions for defeasance at any time of (a) the entire indebtedness of the Company represented by this Security and (b) certain restrictive covenants and the related Defaults and Events of Default, upon compliance by the Company with certain conditions set forth therein, which provisions apply to this Security.
Authorized Denominations. The Securities are issuable only in registered form, without coupons in denominations of $1,000 and any integral multiple thereof.
Registration of Transfer or Exchange. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable on the Security Register of the Company, upon surrender of this Security for registration of transfer at the office or agency of the Company, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. At the date of the original issuance of this Security such office or agency of the Company is maintained by SunTrust Bank, Corporate Trust Division, 25 Park Place, 24th Floor, Atlanta, GA 30303-2900.
As provided in the Indenture and subject to certain limitations therein set forth, the Securities are exchangeable for a like aggregate principal amount of Securities of a different authorized denomination, as requested by the Holder surrendering the same.
No service charge shall be made for any registration of transfer or exchange or redemption of Securities, but the Company may require payment of a sum sufficient to pay all documentary, stamp or similar issue or transfer taxes or other governmental charges payable in connection with any registration of transfer or exchange.
Prior to the time of due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any agent shall be affected by notice to the contrary.
Modifications to the Indenture pursuant to Section 301 of the Indenture. The following modifications to the Indenture shall be applicable with respect to the Securities:
(a) The defined term "Principal Property" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Principal Property" means any natural gas distribution property located in the United States, except any such property that in the opinion of the Board of Directors of the Company is not of material importance to the total business conducted by the Company and its consolidated Subsidiaries.
(b) The defined term "Restricted Subsidiary" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Restricted Subsidiary" means any Subsidiary the amount of Consolidated Net Tangible Assets of which constitutes more than 10% of the aggregate amount of Consolidated Net Tangible Assets of the Company and its Subsidiaries.
Defined Terms. Subject to the modifications to the Indenture set forth above, all capitalized terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
Governing Laws. This Security, the Indenture and the foregoing modifications to the Indenture shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles that would apply any other law.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
ATMOS ENERGY CORPORATION
By: /s/ LAURIE M. SHERWOOD ---------------------------------- Name: Laurie M. Sherwood Title: Vice President, Corporate Development and Treasurer Attest: By: /s/ LOUIS P. GREGORY ----------------------------- Name: Louis P. Gregory Title: Senior Vice President and General Counsel |
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated: January 16, 2003 SUNTRUST BANK, as Trustee
By: /s/ JACK ELLERIN ------------------------ Authorized Officer |
ASSIGNMENT FORM
To assign this Security, fill in the form below:
(I) or (we) assign and transfer this Security to
Date: Signature: --------------- --------------------------------------------- (sign exactly as name appears on the other side of this Security) |
Signature guaranteed by: ______________________________
EXHIBIT 10.2(d)
THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITORY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SECURITY IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITORY OR ITS NOMINEE EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE.
UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND SUCH CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY, ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL, SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
ATMOS ENERGY CORPORATION
Floating Rate Senior Notes due 2007
No. 1 CUSIP NO. 049560 AD 7
Atmos Energy Corporation, a Texas and Virginia corporation (herein called the "Company", which term includes any successor entity under the Indenture, hereinafter defined), for value received, hereby promises to pay to Cede & Co. or registered assigns the principal sum of THREE HUNDRED MILLION DOLLARS ($300,000,000) on October 15, 2007 (the "Maturity Date"), at the office or agency of the Company referred to below, and to pay interest thereon from October 22, 2004, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, quarterly on January 15, April 15, July 15 and October 15 in each year (each, an "Interest Payment Date"), commencing January 15, 2005 at the Three-Month LIBOR Rate plus 0.375%, as determined by the Calculation Agent in accordance with the next succeeding paragraph, until the principal hereof is paid or duly provided for. The Three-Month LIBOR Rate will be reset quarterly on each Interest Payment Date (each of these such dates is referred to as an "Interest Reset Date"), beginning on January 15, 2005. The interest rate for the first Interest Period shall be 2.465%. Interest payable on each Interest Payment Date will include interest accrued from and including October 22, 2004, or from and including the most recent Interest Payment Date to which interest has been paid or duly provided for, as the case may be, to but excluding such Interest Payment Date.
Interest will be computed on the basis of a 360-day year and the actual number of days in an Interest Period. All percentages resulting from any calculation of the interest rate with respect to these Securities will be rounded, if necessary, to the nearest one-hundred thousandth of a percentage point, with five one-millionths of a percentage point rounded upwards (for example, 9.876545% (or .09876545) being rounded to 9.87655% (or .0987655) and 9.876544% (or .09876544) being rounded to 9.87654% (or .0987654)), and all dollar amounts in or resulting from any such calculation will be rounded to the nearest cent (with one-half cent being rounded upwards). The interest rate for these Securities will in no event be higher than the maximum rate permitted by New York law as the same may be modified by United States law of general application.
Promptly upon determination, the Calculation Agent shall inform the Trustee and the Company of the interest rate for the next Interest Period. The Calculation Agent will, upon the request of any Holder of these Securities, provide the interest rate then in effect, and, if determined, the interest rate with regards to such Security which will become effective with respect to the next Interest Period. All calculations made by the Calculation Agent in the absence of manifest error shall be conclusive for all purposes and binding on the Company and the Holders of these Securities.
"Three-Month LIBOR Rate" means the rate for deposits in U.S. dollars for the three-month period commencing on the applicable Interest Reset Date which appears on Telerate Page 3750 at approximately 11:00 a.m., London time, on the second London Banking Day prior to the applicable Interest Reset Date. If this rate does not appear on Telerate Page 3750, the Calculation Agent will determine the rate on the basis of the rates at which deposits in U.S. dollars are offered by four major banks in the London interbank market (selected by the Calculation Agent) at approximately 11:00 a.m., London time, on the second London Banking Day prior to the applicable Interest Reset Date to prime banks in the London interbank market for a period of three months commencing on that Interest Reset Date and in a principal amount equal to an amount not less than $1,000,000 that is representative for a single transaction in such market at such time. In such case, the Calculation Agent will request the principal London office
of each of the aforesaid major banks to provide a quotation of such rate. If at least two such quotations are provided, the rate for that Interest Reset Date will be the arithmetic mean of the quotations, and, if fewer than two quotations are provided as requested, the rate for that Interest Reset Date will be the arithmetic mean of the rates quoted by major banks in New York City, selected by the Calculation Agent, at approximately 11:00 a.m., New York City time, on the second London Banking Day prior to the applicable Interest Reset Date for loans in U.S. dollars to leading European banks for a period of three months commencing on that Interest Reset Date and in a principal amount equal to an amount not less than $1,000,000 that is representative for a single transaction in such market at such time. "London Banking Day" means any business day in which dealings in U.S. dollars are transacted in the London interbank market.
"Telerate Page 3750" means the display page so designated on the Moneyline Telerate, Inc. (or such other page as may replace such page on that service or any successor service for the purpose of displaying London interbank offered rates of major banks).
"Calculation Agent" is SunTrust Bank until such time as the Company appoints a successor calculation agent.
"Interest Period" means the period commencing on and including the Interest Payment Date and ending on and including the day immediately preceding the next succeeding Interest Payment Date with the exception that the first Interest Period shall commence on October 22, 2004 and end on January 14, 2005.
Any payment of principal or interest required to be made on a day that is not a Business Day need not be made on such day, but may be made on the next succeeding Business Day with the same force and effect as if made on such day and no interest shall accrue as a result of such delayed payment.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person (the "Holder") in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the January 1, April 1, July 1 or October 1 (whether or not a Business Day) next preceding such Interest Payment Date (a "Regular Record Date"). Any such interest not so punctually paid or duly provided for ("Defaulted Interest") will forthwith cease to be payable to the Holder on such Regular Record Date and either may be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a special record date (the "Special Record Date") for the payment of such Defaulted Interest to be fixed by the Trustee (referred to herein), notice whereof shall be given to the Holder of this Security not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner, all as more fully provided in the Indenture.
For purposes of this Security, "Business Day" means any day that, in the city of the principal Corporate Trust Office of the Trustee and in the City of New York, is neither a Saturday, Sunday, or legal holiday nor a day on which banking institutions are authorized or required by law or regulation to close.
Payment of the principal of (and premium, if any) and interest on this Security will be made at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, or at such other office or agency of the Company as may be maintained for such purpose, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. So long as this Security remains in book-entry form, all payments of principal and interest will be made by the Company in immediately available funds.
Unless the certificate of authentication hereon has been duly executed by the Trustee by manual signature, this Security shall not be entitled to any benefit under the Indenture, or be valid or obligatory for any purpose.
This Security is one of a duly authorized series of securities of the Company, designated as the Floating Rate Senior Notes due 2007 (the "Securities"), issued under an Indenture dated as of May 22, 2001, as it may be supplemented from time to time (referred to herein as the "Indenture"), between the Company and SunTrust Bank, as trustee (referred to herein as the "Trustee", which term includes any successor trustee under the Indenture with respect to the series of which this Security is a part). A reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties, obligations and immunities thereunder of the Company, the Trustee and the Holders of the Securities, and of the terms upon which the Securities are, and are to be, authenticated and delivered, except as otherwise provided herein.
The Securities are initially limited to $300,000,000 aggregate principal amount. The Company may, at any time, without the consent of the Holders of the Securities, create and issue additional securities having the same ranking, interest rate, maturity and other terms as the Securities. Any such additional securities shall be consolidated and form the same series of the Securities having the same terms as to status, redemption and otherwise as the Securities under the Indenture.
Events of Default. If an Event of Default shall occur and be continuing, the principal of all the Securities may be declared due and payable in the manner and with the effect provided in the Indenture.
Optional Redemption. The Securities will be redeemable, in whole or in part, at the Company's option, on any Interest Payment Date, on or after April 15, 2006, at a redemption price equal to 100% of the principal amount of the Securities to be redeemed plus accrued and unpaid interest on the principal amount of Securities being redeemed to the Redemption Date.
In the event that less than all of the Securities are to be redeemed at any time, selection of such Securities for redemption will be made by The Depository Trust Company ("DTC") during any period the Securities are issued in the form of a global security registered in the name of DTC or a nominee thereof; provided that during any period the Securities are issued in certificated form, the selection of such Securities for redemption will be made by the Trustee by lot or by such other method as the Trustee in its sole discretion shall deem fair and appropriate. In no event shall Securities of a principal amount of $1,000 or less be redeemed in part. Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less
than 30 nor more than 60 days before the Redemption Date, to each Holder of Securities to be redeemed, at its address as shown in the Security Register. If the Securities are to be redeemed in part only, the notice of redemption that relates to such Securities shall state the portion of the principal amount thereof to be redeemed. A new Security in a principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon surrender for cancellation of the original Security. On and after the Redemption Date, interest will cease to accrue on Securities or portions thereof called for redemption unless the Company defaults in the payment of the Redemption Price.
Sinking Fund. This Security does not have the benefit of any sinking fund obligations.
Modification and Waivers; Obligations of the Company Absolute. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities. Certain limited amendments may be effected under the Indenture at any time by the Company and the Trustee without the consent of any Holders of the Securities. Certain other amendments affecting the Securities may only be effected under the Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities at the time Outstanding. The Indenture also contains provisions permitting the Holders of not less than a majority in principal amount of the Securities at the time Outstanding, on behalf of the Holders of all Outstanding Securities, to waive compliance by the Company with certain provisions of the Indenture affecting the Securities. Furthermore, provisions in the Indenture permit the Holders of not less than a majority in principal amount of the Outstanding Securities to waive on behalf of all of the Holders of all Outstanding Securities certain past defaults under the Indenture in respect of the Securities and their consequences. Any such consent or waiver by or on behalf of the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof whether or not notation of such consent or waiver is made upon this Security.
No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of (and premium, if any) and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.
Defeasance and Covenant Defeasance. The Indenture contains provisions for defeasance at any time of (a) the entire indebtedness of the Company represented by this Security and (b) certain restrictive covenants and the related Defaults and Events of Default, upon compliance by the Company with certain conditions set forth therein, which provisions apply to this Security.
Authorized Denominations. The Securities are issuable only in registered form, without coupons in denominations of $1,000 and any integral multiple thereof.
Registration of Transfer or Exchange. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable on the Security
Register of the Company, upon surrender of this Security for registration of transfer at the office or agency of the Company, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. At the date of the original issuance of this Security such office or agency of the Company is maintained by SunTrust Bank, Corporate Trust Division, 25 Park Place, 24th Floor, Atlanta, GA 30303-2900.
As provided in the Indenture and subject to certain limitations therein set forth, the Securities are exchangeable for a like aggregate principal amount of Securities of a different authorized denomination, as requested by the Holder surrendering the same.
No service charge shall be made for any registration of transfer or exchange or redemption of Securities, but the Company may require payment of a sum sufficient to pay all documentary, stamp or similar issue or transfer taxes or other governmental charges payable in connection with any registration of transfer or exchange.
Prior to the time of due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any agent shall be affected by notice to the contrary.
Modifications to the Indenture pursuant to Section 301 of the Indenture. The following modifications to the Indenture shall be applicable with respect to the Securities:
(a) The defined term "Principal Property" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Principal Property" means any natural gas distribution property located in the United States, except any such property that in the opinion of the Board of Directors of the Company is not of material importance to the total business conducted by the Company and its consolidated Subsidiaries.
(b) The defined term "Restricted Subsidiary" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Restricted Subsidiary" means any Subsidiary the amount of Consolidated Net Tangible Assets of which constitutes more than 10% of the aggregate amount of Consolidated Net Tangible Assets of the Company and its Subsidiaries.
Defined Terms. Subject to the modifications to the Indenture set forth above, all capitalized terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
Governing Laws. This Security, the Indenture and the foregoing modifications to the Indenture shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles that would apply any other law.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
ATMOS ENERGY CORPORATION
By: /s/ LOUIS P. GREGORY ------------------------------------------ Name: Louis P. Gregory Title: Senior Vice President and General Counsel Attest: By: /s/ DWALA KUHN ------------------------------ Name: Dwala Kuhn Title: Corporate Secretary |
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated: October 22, 2004 SUNTRUST BANK, as Trustee
By: /s/ JACK ELLERIN ------------------------- Authorized Officer |
ASSIGNMENT FORM
To assign this Security, fill in the form below:
(I) or (we) assign and transfer this Security to
Date: Signature: ---------------- ---------------------------------------------- (sign exactly as name appears on the other side of this Security) |
Signature guaranteed by: ______________________________
EXHIBIT 10.2(e)
THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITORY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SECURITY IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITORY OR ITS NOMINEE EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE.
UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND SUCH CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY, ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL, SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
ATMOS ENERGY CORPORATION
4.0% Senior Notes due 2009
No. 1 CUSIP NO. 049560 AE 5
Atmos Energy Corporation, a Texas and Virginia corporation (herein called the "Company", which term includes any successor entity under the Indenture, hereinafter defined), for value received, hereby promises to pay to Cede & Co. or registered assigns the principal sum of FOUR HUNDRED MILLION DOLLARS ($400,000,000) on October 15, 2009 (the "Maturity Date"), at the office or agency of the Company referred to below, and to pay interest thereon from October 22, 2004, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semiannually on April 15 and October 15 in each year (each, an "Interest Payment Date"), commencing April 15, 2005 at 4.0% per annum until the principal hereof is paid or duly provided for.
Any payment of principal or interest required to be made on a day that is not a Business Day need not be made on such day, but may be made on the next succeeding Business Day with the same force and effect as if made on such day and no interest shall accrue as a result of such delayed payment. Interest payable on each Interest Payment Date will include interest accrued from and including October 22, 2004, or from and including the most recent Interest Payment Date to which interest has been paid or duly provided for, as the case may be, to but excluding such Interest Payment Date. Interest will be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person (the "Holder") in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the April 1 or October 1 (whether or not a Business Day) next preceding such Interest Payment Date (a "Regular Record Date"). Any such interest not so punctually paid or duly provided for ("Defaulted Interest") will forthwith cease to be payable to the Holder on such Regular Record Date and either may be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a special record date (the "Special Record Date") for the payment of such Defaulted Interest to be fixed by the Trustee (referred to herein), notice whereof shall be given to the Holder of this Security not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner, all as more fully provided in the Indenture.
For purposes of this Security, "Business Day" means any day that, in the city of the principal Corporate Trust Office of the Trustee and in the City of New York, is neither a Saturday, Sunday, or legal holiday nor a day on which banking institutions are authorized or required by law or regulation to close.
Payment of the principal of (and premium, if any) and interest on this Security will be made at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, or at such other office or agency of the Company as may be maintained for such purpose, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. So long as this Security remains in book-entry form, all payments of principal and interest will be made by the Company in immediately available funds.
Unless the certificate of authentication hereon has been duly executed by the Trustee by manual signature, this Security shall not be entitled to any benefit under the Indenture, or be valid or obligatory for any purpose.
This Security is one of a duly authorized series of securities of the Company, designated as the 4.0% Senior Notes due 2009 (the "Securities"), issued under an Indenture dated as of May 22, 2001, as it may be supplemented from time to time (referred to herein as the "Indenture"), between the Company and SunTrust Bank, as trustee (referred to herein as the "Trustee", which term includes any successor trustee under the Indenture with respect to the series of which this Security is a part). A reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties, obligations and immunities thereunder of the Company, the Trustee and the Holders of the Securities, and of the terms upon which the Securities are, and are to be, authenticated and delivered, except as otherwise provided herein.
The Securities are initially limited to $400,000,000 aggregate principal amount. The Company may, at any time, without the consent of the Holders of the Securities, create and issue additional securities having the same ranking, interest rate, maturity and other terms as the Securities. Any such additional securities shall be consolidated and form the same series of the Securities having the same terms as to status, redemption and otherwise as the Securities under the Indenture.
Events of Default. If an Event of Default shall occur and be continuing, the principal of all the Securities may be declared due and payable in the manner and with the effect provided in the Indenture.
Optional Redemption. The Securities will be redeemable, in whole or in part, at the Company's option, at any time at a Redemption Price equal to the greater of:
(a) 100% of the principal amount of the Securities to be redeemed, or
(b) as determined by the Quotation Agent, the sum of the present values of the Remaining Scheduled Payments of principal and interest on the Securities to be redeemed discounted to the Redemption Date on a semi-annual basis assuming a 360-day year consisting of twelve 30 day months at the Adjusted Treasury Rate plus 15 basis points;
plus, in either case, accrued and unpaid interest on the principal amount of Securities being redeemed to the Redemption Date.
"Adjusted Treasury Rate" means, for any Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for that Redemption Date.
"Comparable Treasury Issue" means the United States treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the Securities to be redeemed that would be used, at the time of a selection and in accordance with customary
financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Securities to be redeemed.
"Comparable Treasury Price" means, for any Redemption Date, the Reference Treasury Dealer Quotation for that Redemption Date.
"Quotation Agent" means the Reference Treasury Dealer appointed by the Company.
"Reference Treasury Dealer" means Merrill Lynch, Pierce, Fenner & Smith Incorporated and its successors; provided, however, if Merrill Lynch, Pierce, Fenner & Smith Incorporated ceases to be a primary U.S. government securities dealer in New York City, the Company will replace Merrill Lynch, Pierce, Fenner & Smith Incorporated as Reference Treasury Dealer with an entity that is a primary U.S. government securities dealer in New York City.
"Reference Treasury Dealer Quotation" means, with respect to any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed, in each case, as a percentage of its principal amount) quoted in writing to the Trustee by the Reference Treasury Dealer by 5:00 p.m. on the third business day preceding the Redemption Date.
"Remaining Scheduled Payments" means, with respect to each Security to be redeemed, the remaining scheduled payments of the principal and interest on such Security that would be due after the related Redemption Date but for such redemption; provided, however, that if such Redemption Date is not an Interest Payment Date, the amount of the next succeeding scheduled interest payment on such Security will be reduced by the amount of interest accrued on such Security to such Redemption Date.
In the event that less than all of the Securities are to be redeemed at any time, selection of such Securities for redemption will be made by The Depository Trust Company ("DTC") during any period the Securities are issued in the form of a global security registered in the name of DTC or a nominee thereof; provided that during any period the Securities are issued in certificated form, the selection of such Securities for redemption will be made by the Trustee by lot or by such other method as the Trustee in its sole discretion shall deem fair and appropriate. In no event shall Securities of a principal amount of $1,000 or less be redeemed in part. Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less than 30 nor more than 60 days before the Redemption Date, to each Holder of Securities to be redeemed, at its address as shown in the Security Register. If the Securities are to be redeemed in part only, the notice of redemption that relates to such Securities shall state the portion of the principal amount thereof to be redeemed. A new Security in a principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon surrender for cancellation of the original Security. On and after the Redemption Date, interest will cease to accrue on Securities or portions thereof called for redemption unless the Company defaults in the payment of the Redemption Price.
Sinking Fund. This Security does not have the benefit of any sinking fund obligations.
Modification and Waivers; Obligations of the Company Absolute. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities. Certain limited amendments may be effected under the Indenture at any time by the Company and the Trustee without the consent of any Holders of the Securities. Certain other amendments affecting the Securities may only be effected under the Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities at the time Outstanding. The Indenture also contains provisions permitting the Holders of not less than a majority in principal amount of the Securities at the time Outstanding, on behalf of the Holders of all Outstanding Securities, to waive compliance by the Company with certain provisions of the Indenture affecting the Securities. Furthermore, provisions in the Indenture permit the Holders of not less than a majority in principal amount of the Outstanding Securities to waive on behalf of all of the Holders of all Outstanding Securities certain past defaults under the Indenture in respect of the Securities and their consequences. Any such consent or waiver by or on behalf of the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof whether or not notation of such consent or waiver is made upon this Security.
No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of (and premium, if any) and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.
Defeasance and Covenant Defeasance. The Indenture contains provisions for defeasance at any time of (a) the entire indebtedness of the Company represented by this Security and (b) certain restrictive covenants and the related Defaults and Events of Default, upon compliance by the Company with certain conditions set forth therein, which provisions apply to this Security.
Authorized Denominations. The Securities are issuable only in registered form, without coupons in denominations of $1,000 and any integral multiple thereof.
Registration of Transfer or Exchange. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable on the Security Register of the Company, upon surrender of this Security for registration of transfer at the office or agency of the Company, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. At the date of the original issuance of this Security such office or agency of the Company is maintained by SunTrust Bank, Corporate Trust Division, 25 Park Place, 24th Floor, Atlanta, GA 30303-2900.
As provided in the Indenture and subject to certain limitations therein set forth, the Securities are exchangeable for a like aggregate principal amount of Securities of a different authorized denomination, as requested by the Holder surrendering the same.
No service charge shall be made for any registration of transfer or exchange or redemption of Securities, but the Company may require payment of a sum sufficient to pay all documentary, stamp or similar issue or transfer taxes or other governmental charges payable in connection with any registration of transfer or exchange.
Prior to the time of due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any agent shall be affected by notice to the contrary.
Modifications to the Indenture pursuant to Section 301 of the Indenture. The following modifications to the Indenture shall be applicable with respect to the Securities:
(a) The defined term "Principal Property" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Principal Property" means any natural gas distribution property located in the United States, except any such property that in the opinion of the Board of Directors of the Company is not of material importance to the total business conducted by the Company and its consolidated Subsidiaries.
(b) The defined term "Restricted Subsidiary" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Restricted Subsidiary" means any Subsidiary the amount of Consolidated Net Tangible Assets of which constitutes more than 10% of the aggregate amount of Consolidated Net Tangible Assets of the Company and its Subsidiaries.
Defined Terms. Subject to the modifications to the Indenture set forth above, all capitalized terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
Governing Laws. This Security, the Indenture and the foregoing modifications to the Indenture shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles that would apply any other law.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
ATMOS ENERGY CORPORATION
By: /s/ LOUIS P. GREGORY -------------------------- Name: Louis P. Gregory Title: Senior Vice President and General Counsel Attest: By: /s/ DWALA KUHN ------------------------------- Name: Dwala Kuhn Title: Corporate Secretary |
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated: October 22, 2004 SUNTRUST BANK, as Trustee
By: /s/ JACK ELLERIN ------------------------ Authorized Officer |
ASSIGNMENT FORM
To assign this Security, fill in the form below:
(I) or (we) assign and transfer this Security to
Date: Signature: ---------------- ----------------------------------------------- (sign exactly as name appears on the other side of this Security) |
Signature guaranteed by: ______________________________
EXHIBIT 10.2(f)
THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITORY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SECURITY IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITORY OR ITS NOMINEE EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE.
UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND SUCH CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY, ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL, SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
ATMOS ENERGY CORPORATION
4.95% Senior Notes due 2014
No. 1 CUSIP NO. 049560 AF 2
Atmos Energy Corporation, a Texas and Virginia corporation (herein called the "Company", which term includes any successor entity under the Indenture, hereinafter defined), for value received, hereby promises to pay to Cede & Co. or registered assigns the principal sum of FIVE HUNDRED MILLION DOLLARS ($500,000,000) on October 15, 2014 (the "Maturity Date"), at the office or agency of the Company referred to below, and to pay interest thereon from October 22, 2004, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semiannually on April 15 and October 15 in each year (each, an "Interest Payment Date"), commencing April 15, 2005 at 4.95% per annum until the principal hereof is paid or duly provided for.
Any payment of principal or interest required to be made on a day that is not a Business Day need not be made on such day, but may be made on the next succeeding Business Day with the same force and effect as if made on such day and no interest shall accrue as a result of such delayed payment. Interest payable on each Interest Payment Date will include interest accrued from and including October 22, 2004, or from and including the most recent Interest Payment Date to which interest has been paid or duly provided for, as the case may be, to but excluding such Interest Payment Date. Interest will be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person (the "Holder") in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the April 1 or October 1 (whether or not a Business Day) next preceding such Interest Payment Date (a "Regular Record Date"). Any such interest not so punctually paid or duly provided for ("Defaulted Interest") will forthwith cease to be payable to the Holder on such Regular Record Date and either may be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a special record date (the "Special Record Date") for the payment of such Defaulted Interest to be fixed by the Trustee (referred to herein), notice whereof shall be given to the Holder of this Security not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner, all as more fully provided in the Indenture.
For purposes of this Security, "Business Day" means any day that, in the city of the principal Corporate Trust Office of the Trustee and in the City of New York, is neither a Saturday, Sunday, or legal holiday nor a day on which banking institutions are authorized or required by law or regulation to close.
Payment of the principal of (and premium, if any) and interest on this Security will be made at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, or at such other office or agency of the Company as may be maintained for such purpose, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. So long as this Security remains in book-entry form, all payments of principal and interest will be made by the Company in immediately available funds.
Unless the certificate of authentication hereon has been duly executed by the Trustee by manual signature, this Security shall not be entitled to any benefit under the Indenture, or be valid or obligatory for any purpose.
This Security is one of a duly authorized series of securities of the Company, designated as the 4.95% Senior Notes due 2014 (the "Securities"), issued under an Indenture dated as of May 22, 2001, as it may be supplemented from time to time (referred to herein as the "Indenture"), between the Company and SunTrust Bank, as trustee (referred to herein as the "Trustee", which term includes any successor trustee under the Indenture with respect to the series of which this Security is a part). A reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties, obligations and immunities thereunder of the Company, the Trustee and the Holders of the Securities, and of the terms upon which the Securities are, and are to be, authenticated and delivered, except as otherwise provided herein.
The Securities are initially limited to $500,000,000 aggregate principal amount. The Company may, at any time, without the consent of the Holders of the Securities, create and issue additional securities having the same ranking, interest rate, maturity and other terms as the Securities. Any such additional securities shall be consolidated and form the same series of the Securities having the same terms as to status, redemption and otherwise as the Securities under the Indenture.
Events of Default. If an Event of Default shall occur and be continuing, the principal of all the Securities may be declared due and payable in the manner and with the effect provided in the Indenture.
Optional Redemption. The Securities will be redeemable, in whole or in part, at the Company's option, at any time at a Redemption Price equal to the greater of:
(a) 100% of the principal amount of the Securities to be redeemed, or
(b) as determined by the Quotation Agent, the sum of the present values of the Remaining Scheduled Payments of principal and interest on the Securities to be redeemed discounted to the Redemption Date on a semi-annual basis assuming a 360-day year consisting of twelve 30 day months at the Adjusted Treasury Rate plus 20 basis points;
plus, in either case, accrued and unpaid interest on the principal amount of Securities being redeemed to the Redemption Date.
"Adjusted Treasury Rate" means, for any Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for that Redemption Date.
"Comparable Treasury Issue" means the United States treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the Securities to be redeemed that would be used, at the time of a selection and in accordance with customary
financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Securities to be redeemed.
"Comparable Treasury Price" means, for any Redemption Date, the Reference Treasury Dealer Quotation for that Redemption Date.
"Quotation Agent" means the Reference Treasury Dealer appointed by the Company.
"Reference Treasury Dealer" means Merrill Lynch, Pierce, Fenner & Smith Incorporated and its successors; provided, however, if Merrill Lynch, Pierce, Fenner & Smith Incorporated ceases to be a primary U.S. government securities dealer in New York City, the Company will replace Merrill Lynch, Pierce, Fenner & Smith Incorporated as Reference Treasury Dealer with an entity that is a primary U.S. government securities dealer in New York City.
"Reference Treasury Dealer Quotation" means, with respect to any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed, in each case, as a percentage of its principal amount) quoted in writing to the Trustee by the Reference Treasury Dealer by 5:00 p.m. on the third business day preceding the Redemption Date.
"Remaining Scheduled Payments" means, with respect to each Security to be redeemed, the remaining scheduled payments of the principal and interest on such Security that would be due after the related Redemption Date but for such redemption; provided, however, that if such Redemption Date is not an Interest Payment Date, the amount of the next succeeding scheduled interest payment on such Security will be reduced by the amount of interest accrued on such Security to such Redemption Date.
In the event that less than all of the Securities are to be redeemed at any time, selection of such Securities for redemption will be made by The Depository Trust Company ("DTC") during any period the Securities are issued in the form of a global security registered in the name of DTC or a nominee thereof; provided that during any period the Securities are issued in certificated form, the selection of such Securities for redemption will be made by the Trustee by lot or by such other method as the Trustee in its sole discretion shall deem fair and appropriate. In no event shall Securities of a principal amount of $1,000 or less be redeemed in part. Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less than 30 nor more than 60 days before the Redemption Date, to each Holder of Securities to be redeemed, at its address as shown in the Security Register. If the Securities are to be redeemed in part only, the notice of redemption that relates to such Securities shall state the portion of the principal amount thereof to be redeemed. A new Security in a principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon surrender for cancellation of the original Security. On and after the Redemption Date, interest will cease to accrue on Securities or portions thereof called for redemption unless the Company defaults in the payment of the Redemption Price.
Sinking Fund. This Security does not have the benefit of any sinking fund obligations.
Modification and Waivers; Obligations of the Company Absolute. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities. Certain limited amendments may be effected under the Indenture at any time by the Company and the Trustee without the consent of any Holders of the Securities. Certain other amendments affecting the Securities may only be effected under the Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities at the time Outstanding. The Indenture also contains provisions permitting the Holders of not less than a majority in principal amount of the Securities at the time Outstanding, on behalf of the Holders of all Outstanding Securities, to waive compliance by the Company with certain provisions of the Indenture affecting the Securities. Furthermore, provisions in the Indenture permit the Holders of not less than a majority in principal amount of the Outstanding Securities to waive on behalf of all of the Holders of all Outstanding Securities certain past defaults under the Indenture in respect of the Securities and their consequences. Any such consent or waiver by or on behalf of the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof whether or not notation of such consent or waiver is made upon this Security.
No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of (and premium, if any) and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.
Defeasance and Covenant Defeasance. The Indenture contains provisions for defeasance at any time of (a) the entire indebtedness of the Company represented by this Security and (b) certain restrictive covenants and the related Defaults and Events of Default, upon compliance by the Company with certain conditions set forth therein, which provisions apply to this Security.
Authorized Denominations. The Securities are issuable only in registered form, without coupons in denominations of $1,000 and any integral multiple thereof.
Registration of Transfer or Exchange. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable on the Security Register of the Company, upon surrender of this Security for registration of transfer at the office or agency of the Company, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. At the date of the original issuance of this Security such office or agency of the Company is maintained by SunTrust Bank, Corporate Trust Division, 25 Park Place, 24th Floor, Atlanta, GA 30303-2900.
As provided in the Indenture and subject to certain limitations therein set forth, the Securities are exchangeable for a like aggregate principal amount of Securities of a different authorized denomination, as requested by the Holder surrendering the same.
No service charge shall be made for any registration of transfer or exchange or redemption of Securities, but the Company may require payment of a sum sufficient to pay all documentary, stamp or similar issue or transfer taxes or other governmental charges payable in connection with any registration of transfer or exchange.
Prior to the time of due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any agent shall be affected by notice to the contrary.
Modifications to the Indenture pursuant to Section 301 of the Indenture. The following modifications to the Indenture shall be applicable with respect to the Securities:
(a) The defined term "Principal Property" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Principal Property" means any natural gas distribution property located in the United States, except any such property that in the opinion of the Board of Directors of the Company is not of material importance to the total business conducted by the Company and its consolidated Subsidiaries.
(b) The defined term "Restricted Subsidiary" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Restricted Subsidiary" means any Subsidiary the amount of Consolidated Net Tangible Assets of which constitutes more than 10% of the aggregate amount of Consolidated Net Tangible Assets of the Company and its Subsidiaries.
Defined Terms. Subject to the modifications to the Indenture set forth above, all capitalized terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
Governing Laws. This Security, the Indenture and the foregoing modifications to the Indenture shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles that would apply any other law.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
ATMOS ENERGY CORPORATION
By: /s/ LOUIS P. GREGORY ---------------------------------------- Name: Louis P. Gregory Title: Senior Vice President and General Counsel Attest: By: /s/ DWALA KUHN -------------------------------- Name: Dwala Kuhn Title: Corporate Secretary |
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated: October 22, 2004 SUNTRUST BANK, as Trustee
By: /s/ JACK ELLERIN ------------------------- Authorized Officer |
ASSIGNMENT FORM
To assign this Security, fill in the form below:
(I) or (we) assign and transfer this Security to
Date: Signature: ----------- ---------------------------------------------------- (sign exactly as name appears on the other side of this Security) |
EXHIBIT 10.2(g)
THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITORY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SECURITY IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITORY OR ITS NOMINEE EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE.
UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND SUCH CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO., OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY, ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL, SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.
ATMOS ENERGY CORPORATION
5.95% Senior Notes due 2034
No. 1 CUSIP NO. 049560 AG 0
Atmos Energy Corporation, a Texas and Virginia corporation (herein called the "Company", which term includes any successor entity under the Indenture, hereinafter defined), for value received, hereby promises to pay to Cede & Co. or registered assigns the principal sum of TWO HUNDRED MILLION DOLLARS ($200,000,000) on October 15, 2034 (the "Maturity Date"), at the office or agency of the Company referred to below, and to pay interest thereon from October 22,2004, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semiannually on April 15 and October 15 in each year (each, an "Interest Payment Date"), commencing April 15, 2005 at 5.95% per annum until the principal hereof is paid or duly provided for.
Any payment of principal or interest required to be made on a day that is not a Business Day need not be made on such day, but may be made on the next succeeding Business Day with the same force and effect as if made on such day and no interest shall accrue as a result of such delayed payment. Interest payable on each Interest Payment Date will include interest accrued from and including October 22, 2004, or from and including the most recent Interest Payment Date to which interest has been paid or duly provided for, as the case may be, to but excluding such Interest Payment Date. Interest will be computed on the basis of a 360-day year of twelve 30-day months.
The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in the Indenture, be paid to the person (the "Holder") in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the April 1 or October 1 (whether or not a Business Day) next preceding such Interest Payment Date (a "Regular Record Date"). Any such interest not so punctually paid or duly provided for ("Defaulted Interest") will forthwith cease to be payable to the Holder on such Regular Record Date and either may be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a special record date (the "Special Record Date") for the payment of such Defaulted Interest to be fixed by the Trustee (referred to herein), notice whereof shall be given to the Holder of this Security not less than ten days prior to such Special Record Date, or may be paid at any time in any other lawful manner, all as more fully provided in the Indenture.
For purposes of this Security, "Business Day" means any day that, in the city of the principal Corporate Trust Office of the Trustee and in the City of New York, is neither a Saturday, Sunday, or legal holiday nor a day on which banking institutions are authorized or required by law or regulation to close.
Payment of the principal of (and premium, if any) and interest on this Security will be made at the office or agency of the Company maintained for that purpose in the Borough of Manhattan, the City of New York, or at such other office or agency of the Company as may be maintained for such purpose, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. So long as this Security remains in book-entry form, all payments of principal and interest will be made by the Company in immediately available funds.
Unless the certificate of authentication hereon has been duly executed by the Trustee by manual signature, this Security shall not be entitled to any benefit under the Indenture, or be valid or obligatory for any purpose.
This Security is one of a duly authorized series of securities of the Company, designated as the 5.95% Senior Notes due 2034 (the "Securities"), issued under an Indenture dated as of May 22, 2001, as it may be supplemented from time to time (referred to herein as the "Indenture"), between the Company and SunTrust Bank, as trustee (referred to herein as the "Trustee", which term includes any successor trustee under the Indenture with respect to the series of which this Security is a part). A reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties, obligations and immunities thereunder of the Company, the Trustee and the Holders of the Securities, and of the terms upon which the Securities are, and are to be, authenticated and delivered, except as otherwise provided herein.
The Securities are initially limited to $200,000,000 aggregate principal amount. The Company may, at any time, without the consent of the Holders of the Securities, create and issue additional securities having the same ranking, interest rate, maturity and other terms as the Securities. Any such additional securities shall be consolidated and form the same series of the Securities having the same terms as to status, redemption and otherwise as the Securities under the Indenture.
Events of Default. If an Event of Default shall occur and be continuing, the principal of all the Securities may be declared due and payable in the manner and with the effect provided in the Indenture.
Optional Redemption. The Securities will be redeemable, in whole or in part, at the Company's option, at any time at a Redemption Price equal to the greater of:
(a) 100% of the principal amount of the Securities to be redeemed, or
(b) as determined by the Quotation Agent, the sum of the present values of the Remaining Scheduled Payments of principal and interest on the Securities to be redeemed discounted to the Redemption Date on a semi-annual basis assuming a 360-day year consisting of twelve 30 day months at the Adjusted Treasury Rate plus 25 basis points;
plus, in either case, accrued and unpaid interest on the principal amount of Securities being redeemed to the Redemption Date.
"Adjusted Treasury Rate" means, for any Redemption Date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price of the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for that Redemption Date.
"Comparable Treasury Issue" means the United States treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the Securities to be redeemed that would be used, at the time of a selection and in accordance with customary
financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Securities to be redeemed.
"Comparable Treasury Price" means, for any Redemption Date, the Reference Treasury Dealer Quotation for that Redemption Date.
"Quotation Agent" means the Reference Treasury Dealer appointed by the Company.
"Reference Treasury Dealer" means Merrill Lynch, Pierce, Fenner & Smith Incorporated and its successors; provided, however, if Merrill Lynch, Pierce, Fenner & Smith Incorporated ceases to be a primary U.S. government securities dealer in New York City, the Company will replace Merrill Lynch, Pierce, Fenner & Smith Incorporated as Reference Treasury Dealer with an entity that is a primary U.S. government securities dealer in New York City.
"Reference Treasury Dealer Quotation" means, with respect to any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed, in each case, as a percentage of its principal amount) quoted in writing to the Trustee by the Reference Treasury Dealer by 5:00 p.m. on the third business day preceding the Redemption Date.
"Remaining Scheduled Payments" means, with respect to each Security to be redeemed, the remaining scheduled payments of the principal and interest on such Security that would be due after the related Redemption Date but for such redemption; provided, however, that if such Redemption Date is not an Interest Payment Date, the amount of the next succeeding scheduled interest payment on such Security will be reduced by the amount of interest accrued on such Security to such Redemption Date.
In the event that less than all of the Securities are to be redeemed at any time, selection of such Securities for redemption will be made by The Depository Trust Company ("DTC") during any period the Securities are issued in the form of a global security registered in the name of DTC or a nominee thereof; provided that during any period the Securities are issued in certificated form, the selection of such Securities for redemption will be made by the Trustee by lot or by such other method as the Trustee in its sole discretion shall deem fair and appropriate. In no event shall Securities of a principal amount of $1,000 or less be redeemed in part. Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less than 30 nor more than 60 days before the Redemption Date, to each Holder of Securities to be redeemed, at its address as shown in the Security Register. If the Securities are to be redeemed in part only, the notice of redemption that relates to such Securities shall state the portion of the principal amount thereof to be redeemed. A new Security in a principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon surrender for cancellation of the original Security. On and after the Redemption Date, interest will cease to accrue on Securities or portions thereof called for redemption unless the Company defaults in the payment of the Redemption Price.
Sinking Fund. This Security does not have the benefit of any sinking fund obligations.
Modification and Waivers; Obligations of the Company Absolute. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities. Certain limited amendments may be effected under the Indenture at any time by the Company and the Trustee without the consent of any Holders of the Securities. Certain other amendments affecting the Securities may only be effected under the Indenture with the consent of the Holders of not less than a majority in aggregate principal amount of the Securities at the time Outstanding. The Indenture also contains provisions permitting the Holders of not less than a majority in principal amount of the Securities at the time Outstanding, on behalf of the Holders of all Outstanding Securities, to waive compliance by the Company with certain provisions of the Indenture affecting the Securities. Furthermore, provisions in the Indenture permit the Holders of not less than a majority in principal amount of the Outstanding Securities to waive on behalf of all of the Holders of all Outstanding Securities certain past defaults under the Indenture in respect of the Securities and their consequences. Any such consent or waiver by or on behalf of the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof whether or not notation of such consent or waiver is made upon this Security.
No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of (and premium, if any) and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.
Defeasance and Covenant Defeasance. The Indenture contains provisions for defeasance at any time of (a) the entire indebtedness of the Company represented by this Security and (b) certain restrictive covenants and the related Defaults and Events of Default, upon compliance by the Company with certain conditions set forth therein, which provisions apply to this Security.
Authorized Denominations. The Securities are issuable only in registered form, without coupons in denominations of $1,000 and any integral multiple thereof.
Registration of Transfer or Exchange. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable on the Security Register of the Company, upon surrender of this Security for registration of transfer at the office or agency of the Company, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. At the date of the original issuance of this Security such office or agency of the Company is maintained by SunTrust Bank, Corporate Trust Division, 25 Park Place, 24th Floor, Atlanta, GA 30303-2900.
As provided in the Indenture and subject to certain limitations therein set forth, the Securities are exchangeable for a like aggregate principal amount of Securities of a different authorized denomination, as requested by the Holder surrendering the same.
No service charge shall be made for any registration of transfer or exchange or redemption of Securities, but the Company may require payment of a sum sufficient to pay all documentary, stamp or similar issue or transfer taxes or other governmental charges payable in connection with any registration of transfer or exchange.
Prior to the time of due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any agent shall be affected by notice to the contrary.
Modifications to the Indenture pursuant to Section 301 of the Indenture. The following modifications to the Indenture shall be applicable with respect to the Securities:
(a) The defined term "Principal Property" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Principal Property" means any natural gas distribution property located in the United States, except any such property that in the opinion of the Board of Directors of the Company is not of material importance to the total business conducted by the Company and its consolidated Subsidiaries.
(b) The defined term "Restricted Subsidiary" in the Indenture is hereby deleted in its entirety and replaced by the following:
"Restricted Subsidiary" means any Subsidiary the amount of Consolidated Net Tangible Assets of which constitutes more than 10% of the aggregate amount of Consolidated Net Tangible Assets of the Company and its Subsidiaries.
Defined Terms. Subject to the modifications to the Indenture set forth above, all capitalized terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.
Governing Laws. This Security, the Indenture and the foregoing modifications to the Indenture shall be governed by and construed in accordance with the laws of the State of New York, without regard to conflicts of laws principles that would apply any other law.
IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.
ATMOS ENERGY CORPORATION
By: /s/ LOUIS P. GREGORY ----------------------------------------- Name: Louis P. Gregory Title: Senior Vice President and General Counsel Attest: By: /s/ DWALA KUHN ------------------------------ Name: Dwala Kuhn Title: Corporate Secretary |
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.
Dated: October 22, 2004 SUNTRUST BANK, as Trustee
By: /s/ JACK ELLERIN ----------------------- Authorized Officer |
ASSIGNMENT FORM
To assign this Security, fill in the form below:
(I) or (we) assign and transfer this Security to
Date: Signature: --------------- ------------------------------------------------- (sign exactly as name appears on the other side of this Security) |
EXHIBIT 10.7(k)
TENTH AMENDMENT TO CREDIT AGREEMENT
AND FIRST AMENDMENT TO SUPPORT AGREEMENT
TENTH AMENDMENT TO CREDIT AGREEMENT AND FIRST AMENDMENT TO SUPPORT AGREEMENT, dated as of September 17, 2004 (this "Amendment"), in respect of (i) 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 "Existing Credit Agreement"; as amended hereby and as further amended, restated, supplemented or otherwise modified and in effect from time to time, the "Credit Agreement") among ATMOS ENERGY MARKETING, LLC (formerly known as Woodward Marketing, L.L.C.), a Delaware limited liability company (the "the Borrower"), the financial institutions from time to time parties thereto (the "Banks"), FORTIS CAPITAL CORP., a Connecticut corporation ("Fortis"), as a Bank, an Issuing Bank, Collateral Agent and Administrative Agent for the Banks, and BNP PARIBAS, a bank organized under the laws of France ("BNP Paribas"), as a Bank, an Issuing Bank and Documentation Agent, and (ii) the Support Agreement, dated as of July 1, 2002, of Atmos Energy Corporation (the "Support Agreement").
WHEREAS, the parties hereto desire to amend the Existing Credit Agreement and the Support Agreement as more fully set forth herein;
NOW, THEREFORE, in consideration of premises, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto hereby agree as follows:
1. Defined Terms. Unless otherwise defined herein, terms defined in the Existing Credit Agreement are used herein as therein defined.
2. Amendments to Existing Credit Agreement. The Existing Credit Agreement is hereby amended as follows:
(a) Subsection (a) of the definition of "Eligible Accounts" set forth in Section 1.01, Certain Defined Terms, is hereby deleted in its entirety and the following new subsection (a) is inserted in lieu thereof:
"(a) Such Account (i) if for an amount in excess of $750,000.00, is acceptable to the Banks in their sole discretion and either (x) is the result of a sale to a Tier I or Tier II Account Party, or (y) is secured by letters of credit in form acceptable to the Banks in their sole discretion and issued by banks approved by the Banks in their sole discretion, or (ii) if for an amount of $750,000.00 or less, such Account will be included as a Tier II Account unless
such Account has been previously approved by the Banks as a Tier I Account;"
(b) Subsection (i) of the definition of "Eligible Accounts" set forth in Section 1.01, Certain Defined Terms, is hereby deleted in its entirety and the following new subsection (i) is inserted in lieu thereof:
"(i) No Account Debtor in respect of such Account is (i) incorporated in or primarily conducting business in any jurisdiction outside of the U.S., unless such Account Debtor and the Account is approved by the Banks and the Borrower is notified in writing by the Administrative Agent, or (ii) an Affiliate of the Borrower, other than Atmos Energy Corporation, provided, that as long as Atmos Energy Corporation maintains an S&P rating of BBB or a Moody's rating of Baa2 or better, and such Accounts would otherwise qualify as Eligible Accounts, Accounts of Atmos Energy Corporation (and its Subsidiaries and Affiliates that have been approved by Agents as Tier I Account Parties) may be included as Tier I Accounts to the extent that such Accounts do not exceed 50% of Borrower's total Accounts, provided, further, should Atmos Energy Corporation not maintain such ratings, and such Accounts would otherwise qualify as Eligible Accounts, Accounts of Atmos Energy Corporation may be included, subject to the approval of the Banks, as Eligible Accounts as a Tier I Account or a Tier II Account."
(c) The definition of "Swap Bank" in Section 1.01, Certain Defined Terms, is hereby amended by deleting such definition in its entirety and substituting in lieu thereof the following new definition:
"'Swap Bank' means BNP Paribas, Societe Generale, or Fortis, or any Affiliate of BNP Paribas, Societe Generale, or Fortis, or any other Bank approved by the Agents."
3. Amendment to Support Agreement. The sixth paragraph of the Support Agreement is hereby amended by deleting such paragraph in its entirety and substituting in lieu thereof the following new paragraph:
"Further, within 30 days of the event that our long-term unsecured debt is rated BBB- or lower by Standard and Poor's and Baa3 or lower by Moody's, we will cause you, for the benefit of the Banks (as defined in the Facility), to be named as an additional insured and loss payee under all applicable insurance policies by endorsement of such policies in a manner reasonably satisfactory to you."
4. Representations. To induce the Administrative Agent and the Banks to enter into this Amendment, the 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 that
(a) no material adverse change has occurred in the financial condition or business prospects of the Borrower since the date of the last financial statements delivered to the Administrative Agent and the Banks, (b) no Default or Event of Default has occurred and is continuing, and (c) the Borrower is fully authorized to enter into this Amendment. THE 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 on the first date (the "Effective Date") on which each of the following conditions precedent shall have been satisfied:
(a) Fees and Expenses. Each of the Agents and the Banks parties to this amendment shall have received payment of a $2,500 amendment fee, in addition to any other fees or expenses owed to them by the Borrower as of the Effective Date,
(b) Delivered Documents. On the Effective Date, the Administrative Agent shall have received executed originals of:
(i) this Amendment, executed by a duly authorized officer of each of the Borrower and the Required Banks; and
(ii) such other documents or certificates as the Administrative Agent or counsel to the Administrative Agent may reasonably request.
(c) No Default. On the Effective Date, the Borrower shall be in compliance in all material respects with all of the terms and provisions set forth in the Credit Agreement and the other Loan Documents on its part to be observed and no Event of Default shall have occurred and be continuing.
6. Miscellaneous.
(a) Limited Effect. 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; provided, however, that upon the Effective Date, all references herein and therein to the "Loan Documents" shall be deemed to include, in any event, the Existing Credit Agreement, the First Amendment, dated as of December 23, 2002, the Second Amendment, dated as of February 7, 2003, the Third Amendment, dated as of February 28, 2003, the Fourth Amendment, dated as of March 31, 2003, the
Fifth Amendment and Waiver, dated as of April 28, 2003, the sixth Amendment to Credit Agreement, Global Amendment to Loan Documents and Waiver, dated as of October 1, 2003, the Amendment to Guaranty, dated as of October 1, 2003, the Seventh Amendment and Joinder Agreement, dated as of December 19, 2003, the Eighth Amendment and Joinder Agreement to Credit Agreement and First Amendment to Subordination Agreement, dated as of February 18, 2004, the Ninth Amendment to Credit Agreement, dated as of March 31, 2004, this Amendment, the Notes, the Guaranty, the Security Agreement, the L/C-Related Documents, the Swap Contracts, the Three Party Agreement, the Atmos Support Agreement, and all other documents delivered to the Administrative Agent or any Bank in connection therewith. Each reference to the Credit Agreement in any of the Loan Documents shall be deemed to be a reference to the Credit Agreement as amended hereby.
(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 facsimile or telecopier shall be effective as delivery of an originally executed counterpart of this Amendment.
(d) Governing Law. This Amendment shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York without giving effect to the conflict of law principles thereof; 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 the 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 THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.
[SIGNATURES FOLLOW]
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.
BORROWER
ATMOS ENERGY MARKETING, LLC
(formerly known as Woodward Marketing,
L.L.C.), a Delaware limited liability
company
By: /s/ LOUIS P. GREGORY ------------------------------------------- Name: Louis P. Gregory Title: V.P. and General Counsel |
the Borrower's Address:
11251 Northwest Freeway, Suite 400
Houston, Texas 77092
Attention: Ronald W. Bahr
Telephone: (713) 688-7771
Facsimile: (713) 688-5124
GUARANTOR
ATMOS ENERGY HOLDINGS, INC.
By: /s/ LOUIS P. GREGORY ------------------------------------------- Name: Louis P. Gregory Title: V.P. and General Counsel |
1800 Three Lincoln Centre 5430 LBJ Freeway Dallas, TX 75240
ACCEPTED, ACKNOWLEDGED AND AGREED:
ATMOS ENERGY CORPORATION
By: /s/ LOUIS P. GREGORY ------------------------------------------- Name: Louis P. Gregory Title: V.P. and General Counsel |
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/ LEONARD RUSSO ------------------------------------------- Name: Leonard Russo Title: Director |
15455 N. Dallas Parkway Suite 1400 Addison, TX 75001 Telephone: (214) 953-9313 Facsimile: (214) 969-9332
BNP PARIBAS,
a bank organized under the laws of France, as a
Bank, Issuing Bank, and Documentation Agent
By: /s/ EDWARD CHIN ------------------------------------------- Name: Edward Chin Title: Managing Director By: /s/ SALLY HASWELL ------------------------------------------- Name: Sally Haswell Title: Director |
787 Seventh Avenue New York, New York 10019 Attention: Ed Chin Telephone: (212) 841-2020 Facsimile: (212) 841-2536
SOCIETE GENERALE, as a Bank
By: /s/ BARBARA PAULSEN ------------------------------------------- Name: Barbara Paulsen Title: Director |
1221 Avenue of the Americas New York, New York 10020 Attention: Barbara Paulsen Telephone: (212) 278-6496 Facsimile: (212) 278-7417
NATEXIS BANQUES POPULAIRES, NEW YORK BRANCH,
as a Bank
By: /s/ DAVID PERSHAD ------------------------------------------- Name: David Pershad Title: Vice President By: /s/ GUILLAUME DE PARASCAU ------------------------------------------- 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/ HERMINE KIROLOS ------------------------------------------- Name: Hermine Kirolos Title: Group Vice President By: /s/ GRISELDA ALVIZO ------------------------------------------- Name: Griselda Alvizo Title: Vice President |
1133 Avenue of the Americas New York, New York 10036 Attention: Hermine Kirolos Telephone: (212) 845-4114 Facsimile: (212) 944-6389
UFJ BANK LIMITED, NEW YORK BRANCH, as a Bank
By: /s/L.J. PERENYI ------------------------------------------- Name: L.J. Perenyi Title: Vice President |
Attention: Seiji Tate Telephone: 212-339-6235 Facsimile: 213-754-2360
BROWN BROTHERS HARRIMAN & CO., as a Bank
By: /s/ JOHN C. SANTOS, JR. ----------------------------------------- Name: John C. Santos, Jr. Title: Managing Director |
40 Broadway New York, New York 10005 Attention: Paul Feldman Telephone: (212) 493-7732 Facsimile: (212) 493-8998
.
.
.
Exhibit 12
Atmos Energy Corporation
Computation of Earnings to Fixed Charges
Year Ended September 30 ------------------------------------------------------------------- 2004 2003 2002 2001 2000 ------------- ------------- ------------ ------------ ------------- (Dollars in thousands) Income from continuing operations before provision for income taxes and cumulative effect of accounting change $137,765 $126,371 $ 94,836 $ 89,458 $56,237 per statement of income Add: Portion of rents representative of the interest factor 3,571 3,626 3,614 2,917 3,007 Interest on debt & amortization of debt expense 65,437 63,660 59,174 47,011 43,823 ------------- ------------- ------------ ------------ ------------- Income as adjusted $206,773 $193,657 $157,624 $139,386 $103,067 ============= ============= ============ ============ ============= Fixed charges: Interest on debt & amortization of debt expense (1) $ 65,437 $ 63,660 $ 59,174 $ 47,011 $43,823 Capitalized interest (2) 1,184 623 1,272 1,494 - Capitalized expenses related to indebtedness (3) - - - 4,718 - Rents 10,712 10,878 10,842 8,752 9,020 Portion of rents representative of the interest factor (4) 3,571 3,626 3,614 2,917 3,007 ------------- ------------- ------------ ------------ ------------- Fixed charges (1)+(2)+(3)+(4) $ 70,192 $ 67,909 $ 64,060 $ 56,140 $46,830 ============= ============= ============ ============ ============= Ratio of earnings to fixed charges 2.95 2.85 2.46 2.48 2.20 |
.
.
.
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% BLUE FLAME INSURANCE SERVICES, LTD Bermuda 100% PDH I HOLDING COMPANY, INC. (1) Texas 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 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) |
(1) PDH I Holding Company, Inc., a Texas corporation, became a wholly-owned subsidiary of Atmos Energy Corporation, as a result of its acquisition on October 1, 2004 from TXU Gas Company.
Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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-3D, No. 333-113603; Form S-3, No. 333-118706; 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; Form S-8, No. 333-88832; and Form S-8, No. 333-116367) of Atmos Energy Corporation and in the related Prospectuses of our report dated November 9, 2004, 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, 2004.
ERNST & YOUNG LLP
Dallas, Texas
November 18, 2004
EXHIBIT 31
RULE 13a-14(a)/15d-14(a) 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 19, 2004 /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 19, 2004 /s/ JOHN P. REDDY --------------------------- John P. Reddy Senior Vice President and Chief Financial Officer |
EXHIBIT 32
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)
In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2004 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 19, 2004 |
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)
In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the period ending September 30, 2004 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 19, 2004 |
EXHIBIT 99
ANNUAL CEO CERTIFICATION
(SECTION 303A.12(a))
As the Chief Executive Officer of Atmos Energy Corporation, and as required by
Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, I
hereby certify that as of the date hereof I am not aware of any violation by the
Company of NYSE's Corporate Governance listing standards, other than has been
notified to the Exchange pursuant to Section 303A.12(b) and disclosed as an
attachment hereto.
By: /s/ ROBERT W. BEST -------------------------------------------------- Name: Robert W. Best Title: Chairman, President and Chief Executive Officer Date: November 19, 2004 |