10-K 1 d51644e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
     
(Mark One)    
 
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended September 30, 2007
    OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number 1-10042
 
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
     
Texas and Virginia
  75-1743247
(State or other jurisdiction of
incorporation or organization)
  (IRS employer
identification no.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
  75240
(Zip code)
(Address of principal executive offices)
   
 
Registrant’s telephone number, including area code:
(972) 934-9227
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
    Name of Each Exchange
Title of Each Class
 
on Which Registered
 
Common stock, No Par Value
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer  þ     Accelerated filer  o      Non-accelerated filer  o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the common voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2007, was $2,715,259,243.
 
As of November 20, 2007, the registrant had 89,749,755 shares of common stock outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 6, 2008 are incorporated by reference into Part III of this report.
 


 

 
TABLE OF CONTENTS
 
                 
        Page
 
    3  
 
PART I
      Business     4  
      Risk Factors     20  
      Unresolved Staff Comments     24  
      Properties     24  
      Legal Proceedings     25  
      Submission of Matters to a Vote of Security Holders     25  
 
PART II
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     27  
      Selected Financial Data     30  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     32  
      Quantitative and Qualitative Disclosures About Market Risk     60  
      Financial Statements and Supplementary Data     62  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     117  
      Controls and Procedures     117  
      Other Information     119  
 
PART III
      Directors, Executive Officers and Corporate Governance     119  
      Executive Compensation     119  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     119  
      Certain Relationships and Related Transactions, and Director Independence     119  
      Principal Accountant Fees and Services     120  
 
PART IV
      Exhibits and Financial Statement Schedules     120  
 Form of Award Agreement of Restricted Stock With Time-Lapse Vesting
 Form of Award Agreement of Performance-Based Restricted Stock Units
 Statement of Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries
 Consent of Independent Registered Public Accounting Firm
 Rule 13a-14(a)/15d-14(a) Certifications
 Section 1350 Certifications


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GLOSSARY OF KEY TERMS
 
     
AEC
 
Atmos Energy Corporation
AEH
 
Atmos Energy Holdings, Inc.
AEM
 
Atmos Energy Marketing, LLC
AES
 
Atmos Energy Services, LLC
APB
 
Accounting Principles Board
APS
 
Atmos Pipeline and Storage, LLC
ATO
 
Trading symbol for Atmos Energy Corporation common stock on the New York Stock Exchange
Bcf
 
Billion cubic feet
COSO
 
Committee of Sponsoring Organizations of the Treadway Commission
EITF
 
Emerging Issues Task Force
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FIN
 
FASB Interpretation
Fitch
 
Fitch Ratings, Ltd.
FSP
 
FASB Staff Position
GRIP
 
Gas Reliability Infrastructure Program
Heritage
 
Heritage Propane Partners, L.P.
iFERC
 
Inside FERC
KPSC
 
Kentucky Public Service Commission
LGS
 
Louisiana Gas Service Company and LGS Natural Gas Company, which were acquired July 1, 2001
LPSC
 
Louisiana Public Service Commission
LTIP
 
1998 Long-Term Incentive Plan
Mcf
 
Thousand cubic feet
MDWQ
 
Maximum daily withdrawal quantity
MMcf
 
Million cubic feet
Moody’s
 
Moody’s Investor Services, Inc.
MPSC
 
Mississippi Public Service Commission
MVG
 
Mississippi Valley Gas Company, which was acquired
December 3, 2002
NYMEX
 
New York Mercantile Exchange, Inc.
NYSE
 
New York Stock Exchange
RRC
 
Railroad Commission of Texas
RSC
 
Rate Stabilization Clause
S&P
 
Standard & Poor’s Corporation
SEC
 
United States Securities and Exchange Commission
SFAS
 
Statement of Financial Accounting Standards
TXU Gas
 
TXU Gas Company, which was acquired on October 1, 2004
USP
 
U.S. Propane, L.P.
VCC
 
Virginia Corporation Commission
WNA
 
Weather Normalization Adjustment


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PART I
 
The terms “we,” “our,” “us,” “Atmos” and “Atmos Energy” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.
 
ITEM 1.   Business
 
Overview
 
Atmos Energy Corporation, headquartered in Dallas, Texas, is engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as other nonregulated natural gas businesses. We are one of the country’s largest natural-gas-only distributors based on number of customers and one of the largest intrastate pipeline operators in Texas based upon miles of pipe. As of September 30, 2007, we distributed natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution 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 nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers in 22 states and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.
 
We were organized under the laws of Texas in 1983 as Energas Company for the purpose of owning and operating the natural gas distribution business of Pioneer Corporation in Texas. In September 1988, we changed our name to Atmos Energy Corporation. As a result of the merger with United Cities Gas Company in July 1997, we also became incorporated in Virginia.
 
Operating Segments
 
Through August 31, 2007, our operations were divided into four segments:
 
  •  the utility segment, which included our regulated natural gas distribution and related sales operations,
 
  •  the natural gas marketing segment, which included a variety of nonregulated natural gas management services,
 
  •  the pipeline and storage segment, which included our regulated and nonregulated natural gas transmission and storage services and
 
  •  the other nonutility segment, which included all of our other nonregulated nonutility operations.
 
During the fourth quarter of fiscal 2007, we completed a series of organizational changes and began reporting the results of our operations under the following new segments, effective September 1, 2007:
 
  •  The natural gas distribution segment, formerly referred to as the utility segment, includes our regulated natural gas distribution and related sales operations.
 
  •  The regulated transmission and storage segment includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division. These operations were previously included in the former pipeline and storage segment.
 
  •  The natural gas marketing segment remains unchanged and includes a variety of nonregulated natural gas management services.
 
  •  The pipeline, storage and other segment primarily is comprised of our nonregulated natural gas transmission and storage services, which were previously included in the former pipeline and storage segment.


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Strategy
 
Our overall strategy is to:
 
  •  deliver superior shareholder value,
 
  •  improve the quality and consistency of earnings growth, while operating our regulated and nonregulated businesses exceptionally well and
 
  •  enhance and strengthen a culture built on our core values.
 
Over the last five fiscal years, we have primarily grown through two significant acquisitions, our acquisition in December 2002 of Mississippi Valley Gas Company (MVG) and our acquisition in October 2004 of the natural gas distribution and pipeline operations of TXU Gas Company (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 efficiently managing our operating and maintenance expenses and leveraging our technology, such as our 24-hour call centers, to achieve more efficient operations. In addition, we have focused on regulatory rate proceedings to increase revenue to recover rising costs and mitigated weather-related risks through weather-normalized rates in most of our service areas. We have also strengthened our nonregulated businesses by increasing gross profit margins, expanding commercial opportunities in our regulated transmission and storage segment 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 continue to strengthen our culture through ongoing communications with our employees and enhanced employee training.
 
Natural Gas Distribution Segment Overview
 
Our natural gas distribution segment consisted of the following six regulated divisions during the year ended September 30, 2007:
 
  •  Atmos Energy Mid-Tex Division,
 
  •  Atmos Energy Kentucky/Mid-States Division,
 
  •  Atmos Energy Louisiana Division,
 
  •  Atmos Energy West Texas Division,
 
  •  Atmos Energy Mississippi Division and
 
  •  Atmos Energy Colorado-Kansas Division
 
Our natural gas distribution business is a seasonal business. 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.
 
In addition to seasonality, financial results for this segment 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. Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense.
 
The effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which are now approved by the regulatory authorities for over 90 percent of residential and commercial meters in our service areas. WNA allows us to increase customers’ bills to offset lower gas usage when weather is warmer than normal and decrease customers’ bills to offset higher gas usage when weather is colder than normal.


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As of September 30, 2007 we had WNA for our residential and commercial meters in the following service areas for the following periods:
 
     
Georgia
  October — May
Kansas
  October — May
Kentucky
  November — April
Louisiana
  December — March
Mississippi
  November — April
Tennessee
  November — April
Texas: Mid-Tex
  November — April
Texas: West Texas
  October — May
Virginia
  January — December
 
Our supply of natural gas is provided by a variety of suppliers, including independent producers, marketers and pipeline companies and withdrawals of gas from proprietary and contracted storage assets. Additionally, the natural gas supply for our Mid-Tex Division includes peaking and spot purchase agreements.
 
Supply arrangements are contracted from our suppliers on a firm basis with various terms at market prices. The firm supply consists of both base load and swing supply (peaking) 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.
 
Currently, all of our natural gas distribution divisions, except for our Mid-Tex Division, utilize 37 pipeline transportation companies, both interstate and intrastate, to transport our natural gas. 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. The natural gas supply for our Mid-Tex Division is delivered by our Atmos Pipeline — Texas Division.
 
Except for local production purchases, we select our natural gas 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 during fiscal 2007 were Anadarko Energy Services, BP Energy Company, Chesapeake Energy Marketing, Inc., ConocoPhillips Company, Devon Gas Services, L.P., Enbridge Marketing (US) L.P., National Fuel Marketing Company, LLC, ONEOK Energy Services Company L.P., Tenaska Marketing and Atmos Energy Marketing, LLC, our natural gas marketing subsidiary.
 
The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments. We estimate our peak-day availability of natural gas supply to be approximately 4.2 Bcf. The peak-day demand for our natural gas distribution operations in fiscal 2007 was on February 15, 2007, when sales to customers reached approximately 3.4 Bcf.
 
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 or applicable state statutes or regulations. Our customers’ demand on our system 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 the 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 anticipate no problems with obtaining additional gas supply as needed for our customers.
 
The following briefly describes our six natural gas distribution divisions. We operate in our service areas under terms of non-exclusive franchise agreements granted by the various cities and towns that we serve. At


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September 30, 2007, we held 1,106 franchises having terms generally ranging from five to 35 years. A significant number of our franchises expire each year, which require renewal prior to the end of their terms. We believe that we will be able to renew our franchises as they expire. Additional information concerning our natural gas distribution divisions is presented under the caption “Operating Statistics”.
 
Atmos Energy Mid-Tex Division.  Our Mid-Tex Division serves approximately 550 communities in the north-central, eastern and western parts of Texas, including the Dallas/Fort Worth Metroplex. This division currently operates under one system-wide rate structure. However, the governing body of each municipality we serve has original jurisdiction over all gas distribution rates, operations and services within its city limits, except with respect to sales of natural gas for vehicle fuel and agricultural use. The Railroad Commission of Texas (RRC) 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 participates in Texas’ Gas Reliability Infrastructure Program (GRIP), which allows us to include in rate base annually approved capital costs incurred in the prior calendar year. The program also requires us to file a complete rate case at least once every five years.
 
Atmos Energy Kentucky/Mid-States Division.  Our Kentucky/Mid-States Division operates in more than 420 communities across Georgia, Illinois, Iowa, Kentucky, Missouri, Tennessee and Virginia. The service areas in these states are primarily rural; however, this division serves Franklin, Tennessee, which is less than 20 miles from downtown Nashville. We update our rates in this division through periodic formal rate filings made with each state’s public service commission.
 
Atmos Energy Louisiana Division.  In Louisiana, we serve nearly 300 communities, including the suburban areas of New Orleans, the metropolitan area of Monroe and western Louisiana. 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. Our rates in this division are updated annually through a stable rate filing without filing a formal rate case.
 
Atmos Energy West Texas Division.  Our West Texas Division serves approximately 80 communities in West Texas, including the Amarillo, Lubbock and Midland areas. Like our Mid-Tex Division, each municipality we serve has original jurisdiction over all gas distribution rates, operations and services within its city limits. Similarly, the West Texas Division also participates in GRIP, which requires us to file a complete rate case at least once every five years.
 
Atmos Energy Mississippi Division.  In Mississippi, we serve about 110 communities throughout the northern half of the state, including the Jackson metropolitan area. Our rates in the Mississippi Division are updated annually through a stable rate filing without filing a formal rate case.
 
Atmos Energy Colorado-Kansas Division.  Our Colorado-Kansas Division serves approximately 170 communities throughout Colorado and Kansas and in the southwestern corner of Missouri, including Olathe, Kansas, and Greeley, Colorado. Olathe is a southern suburb of Kansas City, near the Missouri border. Greeley is located 20 miles outside of Denver. We update our rates in this division through periodic formal rate filings made with each state’s public service commission.


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The following table provides a jurisdictional rate summary for our regulated operations. This information is for regulatory purposes only and may not be representative of our actual financial position.
 
                         
        Effective
        Authorized
  Authorized
        Date of Last
    Rate Base
  Rate of
  Return on
Division   Jurisdiction   Rate Action     (thousands)(1)   Return(1)   Equity(1)
 
Atmos Pipeline — Texas
  Texas     5/24/04     $417,111   8.258%   10.00%
Colorado-Kansas
  Colorado     7/1/05     84,711   8.95%   11.25%
    Kansas     3/1/04     (2)   (2)   (2)
Kentucky/Mid-States
  Georgia     12/20/05     62,380   7.57%   10.13%
    Illinois     11/1/00     24,564   9.18%   11.56%
    Iowa     3/1/01     5,000   (2)   11.00%
    Kentucky     8/1/07     (2)   (2)   (2)
    Missouri     3/4/07     (2)   (2)   (2)
    Tennessee     11/4/07     186,506   8.03%   10.48%
    Virginia     8/1/04     30,672   8.46% - 8.96%   9.50% - 10.50%
Louisiana
  Trans LA     4/1/07     96,848   (2)   10.00% - 10.80%
    LGS     7/1/07     207,587   (2)   10.40%
Mid-Tex
  Texas     4/1/07     1,043,857   7.903%   10.00%
Mississippi
  Mississippi     1/1/05     196,801   8.23%   9.80%
West Texas
  Amarillo     9/1/03     36,844   9.88%   12.00%
    Lubbock     3/1/04     43,300   9.15%   11.25%
    West Texas     5/1/04     87,500   8.77%   10.50%
 
                                         
            Bad
          Performance-
       
        Authorized Debt/
  Debt
          Based Rate
    Customer
 
Division   Jurisdiction   Equity Ratio   Rider(3)     WNA     Program(4)     Meters  
 
Atmos Pipeline — Texas
  Texas   50/50     No       N/A       N/A       N/A  
Colorado-Kansas
  Colorado   52/48     No       No       No       109,860  
    Kansas   (2)     Yes       Yes       No       127,824  
Kentucky/Mid-States
  Georgia   55/45     No       Yes       Yes       70,606  
    Illinois   67/33     No       No       No       23,342  
    Iowa   57/43     No       No       No       4,455  
    Kentucky   (2)     No       Yes       Yes       177,988  
    Missouri   (2)     No       No(5 )     No       59,672  
    Tennessee   56/44     No       Yes       Yes       133,715  
    Virginia   52/48     Yes       Yes       No       23,721  
Louisiana
  Trans LA   52/48     No       Yes       No       79,985  
    LGS   52/48     No       Yes       No       277,497  
Mid-Tex
  Texas   52/48     No       Yes       No       1,518,119  
Mississippi
  Mississippi   47/53     No       Yes       No       270,980  
West Texas
  Amarillo   50/50     Yes       Yes       No       69,772  
    Lubbock   50/50     No       Yes       No       73,672  
    West Texas   50/50     No       Yes       No       165,919  
 
 
(1) The rate base, authorized rate of return and authorized return on equity presented in this table are those from the last base rate case for each jurisdiction. These rate bases, rates of return and returns on equity are not necessarily indicative of current or future rate bases, rates of return or returns on equity.
 
(2) A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.


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(3) The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.
 
(4) The performance-based rate program provides incentives to natural gas utility companies to minimize purchased gas costs by allowing the utility company and its customers to share the purchased gas cost savings.
 
(5) The Missouri jurisdiction has a straight-fixed variable rate design which decouples gross profit margin from customer usage patterns.
 
Natural Gas Distribution Sales and Statistical Data
 
                                         
    Year Ended September 30  
    2007     2006     2005(1)     2004     2003(1)  
 
METERS IN SERVICE, end of year
                                       
Residential
    2,893,543       2,886,042       2,862,822       1,506,777       1,498,586  
Commercial
    272,081       275,577       274,536       151,381       151,008  
Industrial
    2,339       2,661       2,715       2,436       3,799  
Agricultural
    10,991       8,714       9,639       8,397       9,514  
Public authority and other
    8,173       8,205       8,128       10,145       9,891  
                                         
Total meters
    3,187,127       3,181,199       3,157,840       1,679,136       1,672,798  
                                         
INVENTORY STORAGE BALANCE — Bcf
    58.0       59.9       54.7       27.4       23.9  
                                         
HEATING DEGREE DAYS(2)
                                       
Actual (weighted average)
    2,879       2,527       2,587       3,271       3,473  
Percent of normal
    100 %     87 %     89 %     96 %     101 %
SALES VOLUMES — MMcf(3)
                                       
Gas Sales Volumes
                                       
Residential
    166,612       144,780       162,016       92,208       97,953  
Commercial
    95,514       87,006       92,401       44,226       45,611  
Industrial
    22,914       26,161       29,434       22,330       23,738  
Agricultural
    3,691       5,629       3,348       4,642       7,884  
Public authority and other
    8,596       8,457       9,084       9,813       9,326  
                                         
Total gas sales volumes
    297,327       272,033       296,283       173,219       184,512  
Transportation volumes
    135,109       126,960       122,098       87,746       70,159  
                                         
Total throughput
    432,436       398,993       418,381       260,965       254,671  
                                         
OPERATING REVENUES (000’s)(3)
                                       
Gas Sales Revenues
                                       
Residential
  $ 1,982,801     $ 2,068,736     $ 1,791,172     $ 923,773     $ 873,375  
Commercial
    970,949       1,061,783       869,722       400,704       367,961  
Industrial
    195,060       276,186       229,649       155,336       151,969  
Agricultural
    28,023       40,664       27,889       31,851       48,625  
Public authority and other
    86,275       103,936       86,853       77,178       65,921  
                                         
Total gas sales revenues
    3,263,108       3,551,305       3,005,285       1,588,842       1,507,851  
Transportation revenues
    59,813       62,215       59,996       31,714       30,461  
Other gas revenues
    35,844       37,071       37,859       17,172       15,770  
                                         
Total operating revenues
  $ 3,358,765     $ 3,650,591     $ 3,103,140     $ 1,637,728     $ 1,554,082  
                                         
Average transportation revenue per Mcf
  $ 0.44     $ 0.49     $ 0.49     $ 0.36     $ 0.43  
Average cost of gas per Mcf sold
  $ 8.09     $ 10.02     $ 7.41     $ 6.55     $ 5.76  
Employees
    4,472       4,402       4,327       2,742       2,817  
 
See footnotes following these tables.


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Natural Gas Distribution Sales and Statistical Data By Division
 
                                                                 
    Year Ended September 30, 2007  
          Kentucky/
          West
          Colorado-
             
    Mid-Tex     Mid-States     Louisiana     Texas     Mississippi     Kansas     Other(4)     Total  
 
METERS IN SERVICE
                                                               
Residential
    1,398,274       434,529       334,467       270,557       240,073       215,643             2,893,543  
Commercial
    119,660       54,964       23,015       25,460       27,461       21,521             272,081  
Industrial
    185       927             521       619       87             2,339  
Agricultural
                      10,685             306             10,991  
Public authority and other
          2,623             2,140       2,827       583             8,173  
                                                                 
Total
    1,518,119       493,043       357,482       309,363       270,980       238,140             3,187,127  
                                                                 
HEATING DEGREE DAYS(2)
                                                               
Actual
    2,332       3,831       1,638       3,537       2,759       5,732             2,879  
Percent of normal
    100 %     97 %     105 %     99 %     101 %     104 %           100 %
SALES VOLUMES — MMcf(3)
                                                               
Gas Sales Volumes
                                                               
Residential
    78,140       25,900       13,292       18,882       13,314       17,084             166,612  
Commercial
    50,752       16,137       7,138       7,671       6,859       6,957             95,514  
Industrial
    3,946       7,439             3,521       7,672       336             22,914  
Agricultural
                      3,079             612             3,691  
Public authority and other
          1,454             2,297       3,386       1,459             8,596  
                                                                 
Total
    132,838       50,930       20,430       35,450       31,231       26,448             297,327  
Transportation volumes
    49,337       46,852       6,841       21,709       2,072       8,298             135,109  
                                                                 
Total throughput
    182,175       97,782       27,271       57,159       33,303       34,746             432,436  
                                                                 
OPERATING MARGIN (000’s)(3)
  $ 433,279     $ 151,442     $ 108,908     $ 90,285     $ 94,866     $ 73,904     $     $ 952,684  
OPERATING EXPENSES (000’s)(3)
                                                               
Operation and maintenance
  $ 171,416     $ 61,029     $ 34,805     $ 34,187     $ 47,318     $ 30,026     $ 394     $ 379,175  
Depreciation and amortization
  $ 82,524     $ 34,439     $ 20,941     $ 14,026     $ 10,886     $ 14,372     $     $ 177,188  
Taxes, other than income
  $ 107,476     $ 13,813     $ 8,969     $ 21,036     $ 13,437     $ 7,114     $     $ 171,845  
Impairment of long-lived assets
  $ 3,289     $     $     $     $     $     $     $ 3,289  
OPERATING INCOME (000’s)(3)
  $ 68,574     $ 42,161     $ 44,193     $ 21,036     $ 23,225     $ 22,392     $ (394 )   $ 221,187  
CAPITAL EXPENDITURES (000’s)
  $ 140,037     $ 59,641     $ 40,752     $ 27,031     $ 20,643     $ 21,395     $ 17,943     $ 327,442  
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)
  $ 1,356,453     $ 656,920     $ 345,535     $ 258,622     $ 241,796     $ 264,629     $ 127,189     $ 3,251,144  
OTHER STATISTICS, at year end
                                                               
Miles of pipe
    28,324       12,081       8,216       14,603       6,496       6,642             76,362  
Employees
    1,415       633       422       340       409       269       984       4,472  
 
See footnotes following these tables.


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    Year Ended September 30, 2006  
          Kentucky/
          West
          Colorado-
             
    Mid-Tex     Mid-States     Louisiana     Texas     Mississippi     Kansas     Other(4)     Total  
 
METERS IN SERVICE
                                                               
Residential
    1,390,450       436,406       330,694       273,520       241,406       213,566             2,886,042  
Commercial
    122,263       54,914       23,108       25,984       27,868       21,440             275,577  
Industrial
    205       921             808       643       84             2,661  
Agricultural
                      8,402             312             8,714  
Public authority and other
          2,671             2,166       2,825       543             8,205  
                                                                 
Total
    1,512,918       494,912       353,802       310,880       272,742       235,945             3,181,199  
                                                                 
HEATING DEGREE DAYS(2)
                                                               
Actual
    1,697       3,932       1,319       3,561       2,757       5,466             2,527  
Percent of normal
    72 %     98 %     78 %     100 %     102 %     99 %           87 %
SALES VOLUMES — MMcf(3)
                                                               
Gas Sales Volumes
                                                               
Residential
    65,012       24,314       12,131       15,609       12,601       15,113             144,780  
Commercial
    45,558       15,854       6,944       6,309       6,440       5,901             87,006  
Industrial
    4,784       8,775             3,933       8,250       419             26,161  
Agricultural
                      5,010             619             5,629  
Public authority and other
          1,463             1,962       3,642       1,390             8,457  
                                                                 
Total
    115,354       50,406       19,075       32,823       30,933       23,442             272,033  
Transportation volumes
    47,608       46,525       6,310       15,135       1,702       9,680             126,960  
                                                                 
Total throughput
    162,962       96,931       25,385       47,958       32,635       33,122             398,993  
                                                                 
OPERATING MARGIN (000’s)(3)
  $ 412,334     $ 157,013     $ 98,502     $ 93,693     $ 92,515     $ 71,000     $     $ 925,057  
OPERATING EXPENSES (000’s)(3)
                                                               
Operation and maintenance
  $ 154,412     $ 58,022     $ 40,741     $ 33,332     $ 44,533     $ 28,235     $ (1,756 )   $ 357,519  
Depreciation and amortization
  $ 74,375     $ 33,808     $ 21,201     $ 13,690     $ 10,596     $ 13,578     $ (2,755 )   $ 164,493  
Taxes, other than income
  $ 111,844     $ 15,290     $ 8,788     $ 21,509     $ 14,110     $ 6,663     $     $ 178,204  
Impairment of long-lived assets
  $     $     $     $ 22,947     $     $     $     $ 22,947  
OPERATING INCOME (000’s)(3)
  $ 71,703     $ 49,893     $ 27,772     $ 2,215     $ 23,276     $ 22,524     $ 4,511     $ 201,894  
CAPITAL EXPENDITURES (000’s)
  $ 134,762     $ 54,952     $ 32,218     $ 27,374     $ 15,389     $ 19,466     $ 23,581     $ 307,742  
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)
  $ 1,262,516     $ 627,875     $ 328,310     $ 253,086     $ 226,690     $ 252,584     $ 132,240     $ 3,083,301  
OTHER STATISTICS, at year end
                                                               
Miles of pipe
    27,856       11,952       8,214       14,831       6,415       6,601             75,869  
Employees
    1,458       636       412       341       437       263       855       4,402  
 
 
Notes to preceding tables:
 
(1) The operational and statistical information includes the operations of the Mississippi Division since the December 3, 2002 acquisition date and the Mid-Tex Division since the October 1, 2004 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 National Weather Service data for selected locations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.
 
(3) Sales volumes, revenues, operating margins, operating expense and operating income reflect segment operations, including intercompany sales and transportation amounts.
 
(4) The Other column represents our shared services unit, which provides administrative and other support to the Company. Certain costs incurred by this unit are not allocated.


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Regulated Transmission and Storage Segment Overview
 
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking arrangements, lending and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands. These operations represent one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending 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 believed to contain a substantial portion of the nation’s remaining onshore natural gas reserves. This pipeline system provides access to all of these basins.
 
Regulated Transmission and Storage Sales and Statistical Data
 
                                         
    Year Ended September 30  
    2007     2006     2005     2004(1)     2003(1)  
 
CUSTOMERS, end of year
                                       
Industrial
    65       67       66              
Other
    196       178       191              
                                         
Total
    261       245       257              
                                         
PIPELINE TRANSPORTATION VOLUMES — MMcf(2)
    699,006       581,272       554,452              
OPERATING REVENUES (000’s)(2)
  $ 163,229     $ 141,133     $ 142,952              
Employees, at year end
    54       85       78              
 
 
(1) Atmos Pipeline — Texas was acquired on October 1, 2004, the first day of our fiscal 2005 year.
 
(2) Transportation volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
Natural Gas Marketing Segment Overview
 
Our natural gas marketing activities are conducted through Atmos Energy Marketing (AEM), which is wholly-owned by Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of AEC, which operates in 22 states. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana divisions. These services primarily consist of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative instruments. 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.
 
To optimize the storage and transportation capacity we own or control, we participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. 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 physical natural gas and then sell financial contracts at favorable prices to lock in a gross profit margin. Through the use of transportation and storage services and derivative contracts, we are able to capture gross profit margin through


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the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
 
AEM’s management of natural gas requirements involves the sale of natural gas and the management of storage and transportation supplies under contracts with customers generally having one to two year terms. AEM also sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years.
 
Natural Gas Marketing Sales and Statistical Data
 
                                         
    Year Ended September 30  
    2007     2006     2005     2004     2003  
 
CUSTOMERS, end of year
                                       
Industrial
    677       679       559       638       644  
Municipal
    68       73       69       80       94  
Other
    281       289       211       237       202  
                                         
Total
    1,026       1,041       839       955       940  
                                         
INVENTORY STORAGE BALANCE — Bcf
    19.3       15.3       8.2       5.2       17.6  
NATURAL GAS MARKETING SALES VOLUMES — MMcf(1)
    423,895       336,516       273,201       265,090       294,785  
OPERATING REVENUES (000’s)(1)
  $ 3,151,330     $ 3,156,524     $ 2,106,278     $ 1,618,602     $ 1,668,493  
 
 
(1) Sales volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
Pipeline, Storage and Other Segment Overview
 
Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are each wholly-owned by AEH.
 
APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, beginning in fiscal 2006, APS initiated activities in the natural gas gathering business. As of September 30, 2007, these activities were limited in nature.
 
AES, through December 31, 2006, provided natural gas management services to our natural gas distribution operations, other than the Mid-Tex Division. These services included aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our natural gas distribution service areas at competitive prices. Effective January 1, 2007, our shared services function began providing these services to our natural gas distribution operations. AES continues to provide limited services to our natural gas distribution divisions, and the revenues AES receives are equal to the costs incurred to provide those services.
 
Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.
 
Through January 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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Pipeline, Storage and Other Sales and Statistical Data
 
                                         
    Year Ended September 30  
    2007     2006     2005     2004     2003  
 
OPERATING REVENUES (000’s)(1)
  $ 33,400     $ 25,574     $ 15,639     $ 23,151     $ 23,151  
PIPELINE TRANSPORTATION VOLUMES — MMcf(1)
    7,710       9,712       7,593       9,395       11,648  
INVENTORY STORAGE BALANCE — Bcf
    2.0       2.6       1.8       2.3       2.3  
 
 
(1) Transportation volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
Ratemaking Activity
 
Overview
 
The method of determining regulated rates varies among the states in which our natural gas distribution divisions operate. The regulatory authorities 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 their investment. Generally, each regulatory authority reviews rate requests and establishes a rate structure intended to generate revenue sufficient to cover the costs of doing business and to provide a reasonable return on invested capital.
 
Rates established by regulatory authorities often include cost adjustment mechanisms that (i) are subject to significant price fluctuations compared to the utility’s other costs, (ii) represent a large component of the utility’s cost of service and (iii) are generally outside the control of the utility.
 
Purchased gas mechanisms represent a common form of cost adjustment mechanism. Purchased gas adjustment mechanisms provide gas utility companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case because they provide a dollar-for-dollar offset to increases or decreases in natural gas distribution gas costs. Therefore, although substantially all of our natural gas distribution operating revenues fluctuate with the cost of gas that we purchase, natural gas distribution gross profit (which is defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas.
 
Additionally, some 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 company and its customers.
 
Current Ratemaking Strategy
 
Our current rate strategy focuses on seeking rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved margins from customer usage patterns due to weather-related variability, declining use per customer and energy conservation, also known as decoupling. Additionally, we are seeking to stratify rates to benefit low income households and to recover the gas cost portion of our bad debt expense.
 
Improving rate design is a long-term process. In the interim, we are addressing regulatory lag issues by directing discretionary capital spending to jurisdictions that permit us to recover our investment timely and file rate cases on a more frequent basis to minimize the regulatory lag to keep our actual returns more closely aligned with our allowed returns.


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Recent Ratemaking Activity
 
Approximately 97 percent of our natural gas distribution revenues in the fiscal years ended September 30, 2007, 2006 and 2005 were derived from sales at rates set by or subject to approval by local or state authorities. Of that amount, approximately 90 percent of our rate increases over the last three fiscal years have been obtained through rate making mechanisms that allow us to automatically refresh our rates without filing a formal rate case. Net annual revenue increases resulting from ratemaking activity totaling $40.1 million, $39.0 million and $6.3 million became effective in fiscal 2007, 2006 and 2005 as summarized below:
 
                         
    Increase (Decrease) to Revenue
 
    For the Year Ended September 30  
Rate Action   2007     2006     2005  
    (In thousands)  
 
GRIP filings
  $ 25,624     $ 34,320     $ 1,802  
Stable rate filings
    11,628       3,326       4,525  
Rate case filings
    4,221       (191 )      
Other rate activity
    (1,359 )     1,565        
                         
    $ 40,114     $ 39,020     $ 6,327  
                         
 
Additionally, the following ratemaking efforts were initiated during fiscal 2007 but had not been completed as of September 30, 2007:
 
                 
Division   Rate Action   Jurisdiction   Revenue Requested  
            (In thousands)  
 
Colorado-Kansas
  Rate Case   Kansas   $ 4,978  
Kentucky/Mid-States
  Rate Case(1)   Tennessee     11,055  
Mid-Tex
  Rate Case   Texas     51,945  
                 
            $ 67,978  
                 
 
 
(1) The Tennessee rate case was settled in October 2007, resulting in an increase in annual revenue of $4.0 million and a $4.1 million reduction in depreciation expense.


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Our recent ratemaking activity is discussed in greater detail below.
 
GRIP Filings
 
As discussed above in the “Natural Gas Distribution Segment Overview,” GRIP allows natural gas utility companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. The following table summarizes our GRIP filings with effective dates during the years ended September 30, 2007, 2006 and 2005:
 
                                 
          Incremental Net
    Additional
       
          Utility Plant
    Annual
    Effective
 
Division   Calendar Year     Investment     Revenue     Date  
          (In thousands)     (In thousands)        
 
2007 GRIP:
                               
Atmos Pipeline — Texas
    2006     $ 88,938     $ 13,202       9/14/07  
Mid-Tex
    2006       62,375       12,422       9/14/07  
                                 
Total 2007 GRIP
          $ 151,313     $ 25,624          
                                 
2006 GRIP:
                               
Mid-Tex(1)
    2005     $ 62,156     $ 11,891       9/1/06  
West Texas
    2005       3,802             9/1/06  
Atmos Pipeline — Texas
    2005       21,486       3,286       8/1/06  
West Texas
    2004       22,597       3,802       5/4/06  
Mid-Tex(1)
    2004       28,903       6,731       2/1/06  
Atmos Pipeline — Texas
    2004       10,640       1,919       1/1/06  
Mid-Tex(1)
    2003       32,518       6,691       10/1/05  
                                 
Total 2006 GRIP
          $ 182,102     $ 34,320          
                                 
2005 GRIP:
                               
Atmos Pipeline — Texas
    2003     $ 11,038     $ 1,802       4/1/05  
                                 
Total 2005 GRIP
          $ 11,038     $ 1,802          
                                 
GRIP pending approval:
                               
West Texas
    2006     $ 7,022     $ 1,234       (2 )
                                 
Total
          $ 7,022     $ 1,234          
                                 
 
 
(1) The order issued by the RRC in the Mid-Tex rate case required an immediate refund of amounts collected from the Mid-Tex Division’s 2003-2005 GRIP filings of approximately $2.9 million. This refund is not reflected in the amounts in the table above.
 
(2) The West Texas 2006 GRIP filing is pending authorization from the RRC and the cities.


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Stable Rate Filings
 
As an instrument to reduce regulatory lag, a stable rate filing is a regulatory mechanism designed to allow us to refresh our rates on a periodic basis without filing a formal rate case. As discussed above in the “Natural Gas Distribution Segment Overview,” we currently have stable rate filings in our Louisiana and Mississippi Divisions. The following table summarizes our recent stable rate filings:
 
                             
              Additional
       
              Annual
    Effective
 
Division   Jurisdiction   Test Year Ended     Revenue     Date  
              (In thousands)        
 
2007 Stable Rate Filings:
                           
Mississippi
  Mississippi     6/30/07     $       11/1/07  
Louisiana
  LGS     12/31/06       665       7/1/07  
Louisiana
  Transla     9/30/06       1,445       4/1/07  
Louisiana
  LGS     12/31/05       9,518       8/1/06  
                             
Total 2007 Stable Rate Filings
              $ 11,628          
                             
2006 Stable Rate Filings:
                           
Mississippi
  Mississippi     6/30/06     $       11/1/06  
Louisiana
  LGS     12/31/03       3,326       2/1/06  
                             
Total 2006 Stable Rate Filings
              $ 3,326          
                             
2005 Stable Rate Filings:
                           
Mississippi
  Mississippi     9/30/04     $ 4,300       2/2/05  
Louisiana
  LGS     12/31/02       225       10/1/04  
                             
Total 2005 Stable Rate Filings
              $ 4,525          
                             
 
Rate Case Filings
 
A rate case is a formal request from Atmos Energy to a state’s commission to increase rates that are charged to customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders as well as ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:
 
                     
        Increase
       
        (Decrease)
       
        in Annual
    Effective
 
Division   State   Revenue     Date  
        (In thousands)        
 
2007 Rate Case Filings:
                   
Kentucky/Mid-States
  Kentucky(1)   $ 5,500       8/1/07  
Mid-Tex
  Texas(2)     4,793       4/1/07  
Kentucky/Mid-States
  Missouri(3)           3/4/07  
Kentucky/Mid-States
  Tennessee     (6,072 )     12/15/06  
                     
Total 2007 Rate Case Filings
      $ 4,221          
                     
2006 Rate Case Filings:
                   
Kentucky/Mid-States
  Georgia   $ 409       11/22/05  
Mississippi
  Mississippi     (600 )     10/1/05  
                     
Total 2006 Rate Case Filings
      $ (191 )        
                     
See footnotes on the following page.


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(1) In February 2005, the Attorney General of the State of Kentucky filed a complaint with the Kentucky Public Service Commission (KPSC) alleging that our rates were producing revenues in excess of reasonable levels. In June 2007, the KPSC issued an order dismissing the case. In December 2006, the Company filed a rate application for an increase in base rates. Additionally, we proposed to implement a process to review our rates annually and to collect the bad debt portion of gas costs directly rather than through the base rate. In July 2007, the KPSC approved a settlement we had reached with the Attorney General for an increase in annual revenues of $5.5 million effective August 1, 2007.
 
(2) In March 2007, the RRC issued an order, which increased the Mid-Tex Division’s annual revenues by approximately $4.8 million beginning April 2007 and established a permanent WNA based on 10-year average weather effective for the months of November through April of each year. The RRC also approved a cost allocation method that eliminated a subsidy received from industrial and transportation customers and increased the revenue responsibility for residential and commercial customers. However, the order also required an immediate refund of amounts collected from our 2003 — 2005 GRIP filings of approximately $2.9 million and reduced our total return to 7.903 percent from 8.258 percent, based on a capital structure of 48.1 percent equity and 51.9 percent debt with a return on equity of 10 percent.
 
(3) The Missouri Commission issued an order in March 2007 approving a settlement with rate design changes, including revenue decoupling through the recovery of all non-gas cost revenues through fixed monthly charges and no rate increase.
 
Other Ratemaking Activity
 
The following table summarizes other ratemaking activity during the years ended September 30, 2007, 2006 and 2005:
 
                         
            Increase
       
            (Decrease)
    Effective
 
Division   Jurisdiction   Rate Activity   in Revenue     Date  
            (In thousands)        
 
2007 Other Rate Activity:
                       
Mid-Tex
  Texas   GRIP Refund   $ (2,887 )     4/1/07  
Colorado-Kansas
  Kansas   Ad Valorem Tax     1,528       1/1/07  
                         
2007 Other Rate Activity
          $ (1,359 )        
                         
2006 Other Rate Activity:
                       
Colorado-Kansas
  Kansas   Ad Valorem Tax   $ 1,565       1/1/06  
                         
2006 Other Rate Activity
          $ 1,565          
                         
 
In December 2006, the Louisiana Public Service Commission issued a staff report allowing the deferral of $4.3 million in operating and maintenance expenses in our Louisiana Division to allow recovery of all incremental operation and maintenance expense incurred in fiscal 2005 and 2006 in connection with our Hurricane Katrina recovery efforts.
 
In September 2006, our Mid-Tex Division filed its annual gas cost reconciliation with the RRC. The filing reflects approximately $24 million in refunds of amounts that were overcollected from customers between July 2005 and June 2006. The Mid-Tex Division received approval to refund these amounts over a six-month period, which began in November 2006. The ruling had no impact on the gross profit for the Mid-Tex Division.
 
In May 2007, our Mid-Tex Division filed a 36-month gas contract review filing. This filing is mandated by prior RRC orders and covers the prudence of gas purchases made from November 2003 through October 2006, which total approximately $2.7 billion. An agreed-upon procedural schedule has been filed with the RRC, which established a hearing schedule beginning in December 2007.


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In August 2007, our Colorado-Kansas Division agreed with the Colorado Office of Consumer Counsel and the staff of the Colorado Public Utility Commission to issue a one-time credit to our Colorado customers of $1.1 million on customer bills in January 2008.
 
Other Regulation
 
Each of our natural gas distribution 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. In addition, 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 nor 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 former manufactured gas plant sites in Tennessee, Iowa and Missouri.
 
The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act, gas transportation services through our Atmos Pipeline — Texas assets “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting these assets to the jurisdiction of the FERC.
 
Competition
 
Although our natural gas distribution operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas, 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, AEM competes with other natural gas brokers in obtaining natural gas supplies for our customers.
 
Employees
 
At September 30, 2007, we had 4,653 employees, consisting of 4,526 employees in our regulated operations and 127 employees in our nonregulated operations.
 
Available Information
 
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:
 
Shareholder Relations
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
972-855-3729


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Corporate Governance
 
In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer, Robert W. Best, has certified to the New York Stock Exchange that he was not aware of any violation by the Company of NYSE corporate governance listing standards. The Board of Directors has also periodically updated 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 our website. We will also provide copies of such information free of charge upon request to Shareholder Relations at the address listed above.
 
ITEM 1A.   Risk Factors
 
Our financial and operating results are subject to a number of factors, many of which are not within our control. Although we have tried to discuss key risk factors below, please be aware that other risks may prove to be important in the future. These factors include the following:
 
We are subject to regulation by each state in which we operate that affect our operations and financial results.
 
Our natural gas distribution and regulated transmission and storage businesses are subject to various regulated returns on our rate base in each jurisdiction in which we operate. We monitor the allowed rates of return and our effectiveness in earning such rates and initiate rate proceedings or operating changes as we believe are needed. In addition, in the normal course of the regulatory environment, assets may be placed in service and historical test periods established before rate cases can be filed that could result in an adjustment of our returns. 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 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, rate cases involve a risk of rate reduction, because once rates have been approved, they are still subject to challenge for their reasonableness by appropriate regulatory authorities. Our debt and equity financings are also subject to approval by regulatory bodies in several states, which could limit our ability to take advantage of favorable 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. Although we believe that our enhanced technology and distribution system infrastructures have positively positioned us, we cannot provide assurance that there would be no significant adverse effect on our business should unbundling or further deregulation of the natural gas distribution service business occur.
 
Our operations are exposed to market risks that are beyond our control which could adversely affect our financial results.
 
Our risk management operations are subject to market risks beyond our control including market liquidity, commodity price volatility and counterparty creditworthiness.
 
Although we maintain a risk management policy, we may not be able to completely offset the price risk associated with volatile gas prices or the risk in our natural gas marketing and pipeline and storage segments, which could lead to volatility in our earnings. Physical trading also introduces price risk on any net open positions at the end of each trading day, as well as volatility 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


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open positions, there are times when 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 the end of any particular trading 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 such day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner because the timing of the recognition of profits or losses on the hedges for financial accounting purposes usually do not match up with the timing of the economic profits or losses on the item being hedged. This volatility may occur with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated. Further, if the local physical markets in which we trade do not move consistently with the NYMEX futures market, we could experience increased volatility in the financial results of our natural gas marketing and pipeline and storage segments.
 
Our natural gas marketing and pipeline, storage and other segments manage margins and limit risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of a variety of financial derivatives. However, 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 could also realize financial losses on our efforts to limit risk as a result of volatility in the market prices of the underlying commodities or if a counterparty fails to perform under a contract. In addition, 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 are also subject to interest rate risk on our commercial paper borrowings. In recent years, we have been operating in a relatively low interest-rate environment with both short and long-term interest rates being relatively low compared to historical interest rates. However, in the last three years, the Federal Reserve has taken actions that have generally resulted in increases in short-term interest rates. Future increases in interest rates could adversely affect our future financial results.
 
The concentration of our distribution, pipeline and storage operations in the State of Texas has increased the exposure of our operations and financial results to economic conditions and regulatory decisions in Texas.
 
As a result of our acquisition of the distribution, pipeline and storage operations of TXU Gas in October 2004, over 50 percent of our natural gas distribution customers and most of our pipeline and storage assets and operations are located in the State of Texas. This concentration of our business in Texas means that our operations and financial results are subject to greater impact than before from changes in the Texas economy in general and regulatory decisions by state and local regulatory authorities.
 
Adverse weather conditions could affect our operations.
 
Beginning in the 2006-2007 winter heating season, we have had weather-normalized rates for over 90 percent of our residential and commercial meters, which has substantially mitigated the adverse effects of warmer-than-normal weather for meters in those service areas. However, our natural gas distribution and regulated transmission and storage operating results may continue to vary somewhat with the actual temperatures during the winter heating season. In addition, sustained cold weather could adversely affect our natural gas marketing operations as we may be required to purchase gas at spot rates in a rising market to obtain sufficient volumes to fulfill some customer contracts.
 
The execution of our business plan could be affected by an inability to access capital markets.
 
We rely upon access to both short-term and long-term capital markets to satisfy our liquidity requirements. Adverse changes in the economy or these markets, the overall health of the industries in which we


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operate and changes to our credit ratings could limit access to these markets, increase our cost of capital or restrict the execution of our business plan.
 
Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation (S&P), Moody’s Investors Services, Inc. (Moody’s) and Fitch Ratings, Ltd. (Fitch), 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 were unable to issue commercial paper at reasonable rates, we would likely borrow under our bank credit facilities to meet our working capital needs, which would likely increase the cost of our working capital financing.
 
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 some of our 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 natural gas distribution 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. However, the ability to control expenses is an important factor that could influence future results.
 
Rapid increases in the price of purchased gas, which has occurred in recent years, cause us to experience a significant increase in short-term debt. 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 natural gas distribution collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal accounts receivable. This could result in higher short-term debt levels, greater collection efforts and increased bad debt expense.
 
Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.
 
We must continually build additional capacity in our natural gas distribution system to maintain the growth in the number of our customers. The cost of adding this capacity may be affected by a number of factors, including the general state of the economy and weather. Our cash flows from operations generally are sufficient to supply funding for all our capital expenditures including the financing of the costs of new construction along with capital expenditures necessary to maintain our existing natural gas system. Due to the timing of these cash flows and capital expenditures, we often must fund at least a portion of these costs through borrowing funds from third party lenders, the cost of which is dependent on the interest rates at the time. This in turn may limit our ability to connect new customers to our system due to constraints on the amount of funds we can invest in our infrastructure.
 
Our operations are subject to increased competition.
 
In the residential and commercial customer markets, our natural gas distribution operations compete with other energy products, such as electricity and propane. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This could adversely impact our business if as a result, our customer growth slows, reducing our ability to make capital expenditures, or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.


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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. Our regulated transmission and storage operations currently face limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, competition may increase if new intrastate pipelines are constructed near our existing facilities.
 
The cost of providing pension and postretirement health care benefits is subject to changes in pension fund values, changing demographics and actuarial assumptions and may have a material adverse effect on our financial results.
 
We provide a cash-balance pension plan and postretirement healthcare benefits to eligible full-time employees. Our costs of providing such benefits is subject to changes in the market value of our pension fund assets, changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years, and various actuarial calculations and assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates and interest rates and other factors. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.
 
We are subject to environmental regulations which could adversely affect our operations or financial results.
 
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could be significant to our financial results. In addition, existing environmental regulations may be revised or our operations may become subject to new regulations. Such revised or new regulations could result in increased compliance costs or additional operating restrictions which could adversely affect our business, financial condition and results of operations.
 
Distributing and storing natural gas involve risks that may result in accidents and additional operating costs.
 
Our natural gas distribution business involves a number of hazards and operating risks that cannot be completely avoided, such as leaks, accidents and operational problems, which could cause loss of human life, as well as substantial financial losses resulting from property damage, damage to the environment and to our operations. We do have liability and property insurance coverage in place for many of these hazards and risks. However, because our pipeline, storage and distribution facilities are near or are in populated areas, any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by insurance, our financial position and results of operations could be adversely affected.
 
Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.
 
Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance


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covering such risks may be more limited, which could increase the risk that an event could adversely affect future financial results.
 
ITEM 1B.   Unresolved Staff Comments
 
Not applicable.
 
ITEM 2.   Properties
 
Distribution, transmission and related assets
 
At September 30, 2007, our natural gas distribution segment owned an aggregate of 76,362 miles of underground distribution and transmission mains throughout our gas distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Our regulated transmission and storage segment owned 6,290 miles of gas transmission and gathering lines and our pipeline, storage and other segment owned 73 miles of gas transmission and gathering lines.
 
Storage Assets
 
We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities:
 
                                 
                      Maximum
 
                      Daily
 
          Cushion
    Total
    Delivery
 
    Usable Capacity
    Gas
    Capacity
    Capability
 
State   (Mcf)     (Mcf)(1)     (Mcf)     (Mcf)  
 
Natural Gas Distribution Segment
                               
Kentucky
    4,442,696       6,322,283       10,764,979       109,100  
Kansas
    3,239,000       2,300,000       5,539,000       45,000  
Mississippi
    2,211,894       2,442,917       4,654,811       48,000  
Georgia
    450,000       50,000       500,000       30,000  
                                 
Total
    10,343,590       11,115,200       21,458,790       232,100  
Regulated Transmission and Storage Segment — Texas
    39,128,475       13,128,025       52,256,500       1,235,000  
Pipeline, Storage and Other Segment
                               
Kentucky
    3,492,900       3,295,000       6,787,900       71,000  
Louisiana
    438,583       300,973       739,556       56,000  
                                 
Total
    3,931,483       3,595,973       7,527,456       127,000  
                                 
Total
    53,403,548       27,839,198       81,242,746       1,594,100  
                                 
 
 
(1) Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.


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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
 
Segment   Division/Company   (MMBtu)     (MMBtu)(1)  
 
Natural Gas Distribution Segment
                   
    Colorado-Kansas Division     4,237,243       108,232  
    Kentucky/Mid-States Division     15,302,867       287,831  
    Louisiana Division     2,689,695       163,692  
    Mississippi Division     4,033,649       168,039  
    West Texas Division     1,225,000       56,000  
                     
Total
    27,488,454       783,794  
Natural Gas Marketing Segment
  Atmos Energy Marketing, LLC     11,874,654       271,167  
Pipeline, Storage and Other Segment
  Trans Louisiana Gas Pipeline, Inc.     1,050,000       60,000  
                     
Total Contracted Storage Capacity
    40,413,108       1,114,961  
                 
 
 
(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.
 
Other facilities
 
Our natural gas distribution 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 and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our distribution system, the majority of which are located in leased facilities. Our nonregulated 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 2007.


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EXECUTIVE OFFICERS OF THE REGISTRANT
 
The following table sets forth certain information as of September 30, 2007, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.
 
                     
        Years of
   
Name
 
Age
 
Service
 
Office Currently Held
 
Robert W. Best
    60       10     Chairman, President and Chief Executive Officer
Kim R. Cocklin
    56       1     Senior Vice President, Utility Operations
Louis P. Gregory
    52       7     Senior Vice President and General Counsel
Mark H. Johnson
    48       6     Senior Vice President, Nonutility Operations and President, Atmos Energy Marketing, LLC
Wynn D. McGregor
    54       19     Senior Vice President, Human Resources
John P. Reddy
    54       9     Senior Vice President and Chief Financial Officer
 
Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997.
 
Kim R. Cocklin joined the Company in June 2006 as Senior Vice President, Utility Operations. Prior to joining the Company, Mr. Cocklin served as Senior Vice President, General Counsel and Chief Compliance Officer of Piedmont Natural Gas Company from February 2003 to May 2006. Prior to joining Piedmont, Mr. Cocklin was with Williams Gas Pipeline from 1995 to January 2003, where he served in various capacities, including serving as Vice President for rates, regulatory and business development for all of the Williams Gas pipelines from 2001 to January 2003.
 
Louis P. Gregory was named Senior Vice President and General Counsel in September 2000.
 
Mark H. Johnson was named Senior Vice President, Nonutility Operations in April 2006 and President of Atmos Energy Holdings, Inc., and Atmos Energy Marketing, LLC, in April 2005. Mr. Johnson previously served the Company as Vice President, Nonutility Operations from October 2005 to March 2006 and as Executive Vice President of Atmos Energy Marketing from October 2003 to March 2005. Mr. Johnson joined Atmos Energy Marketing’s predecessor, Woodward Marketing, L.L.C., in 1992 as Vice President of Marketing and Operations and was later promoted to Senior Vice President of Marketing for the Midwest and Gulf Coast through September 2003.
 
Wynn D. McGregor was named Senior Vice President, Human Resources in October 2005. He previously served the Company as Vice President, Human Resources from January 1994 to September 2005.
 
John P. Reddy was named Senior Vice President and Chief Financial Officer in September 2000.


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PART II
 
ITEM 5.   Market for Registrant’s 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 2007 and 2006 are listed below. The high and low prices listed are the closing NYSE quotes, as reported on the NYSE composite tape, for shares of our common stock:
 
                                                 
    2007     2006  
                Dividends
                Dividends
 
    High     Low     Paid     High     Low     Paid  
 
Quarter ended:
                                               
December 31
  $ 33.01     $ 28.45     $ .320     $ 28.36     $ 25.79     $ .315  
March 31
    33.00       30.63       .320       27.00       26.10       .315  
June 30
    33.11       29.38       .320       27.91       26.00       .315  
September 30
    30.66       26.47       .320       29.11       27.96       .315  
                                                 
                    $ 1.28                     $ 1.26  
                                                 
 
Dividends 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 agreement. See Note 6 to the consolidated financial statements. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. The number of record holders of our common stock on October 31, 2007 was 22,912. Future payments of dividends, and the amounts of these dividends, will depend on our financial condition, results of operations, capital requirements and other factors. We sold no securities during fiscal 2007 that were not registered under the Securities Act of 1933, as amended.


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Performance Graph
 
The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the Standard and Poor’s 500 Stock Index and the cumulative total return of a customized peer company group, the Comparison Company Index, which is comprised of utility companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2002 in our common stock, the S&P 500 Index and in the common stock of the companies in the Comparison Company Index, as well as a reinvestment of dividends paid on such investments throughout the period.
 
Comparison of Five-Year Cumulative Total Return
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Index
 
(PERFORMANCE GRAPH)
 
                                                 
    Cumulative Total Return  
    9/30/02     9/30/03     9/30/04     9/30/05     9/30/06     9/30/07  
 
Atmos Energy Corporation
    100.00       117.25       129.58       152.04       160.99       166.39  
S&P 500 Index
    100.00       124.40       141.65       159.01       176.17       205.13  
Comparison Company Index
    100.00       120.89       146.79       206.79       202.30       239.05  
 
The Comparison Company Index contains a hybrid group of utility companies, primarily natural gas distribution companies, recommended by a global management consulting firm and approved by the Board of Directors. The companies included in the index are AGL Resources Inc., CenterPoint Energy Resources Corporation, CMS Energy Corporation, Equitable Resources, Inc., Nicor Inc., NiSource Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., Questar Corporation, Vectren Corporation and WGL Holdings, Inc. KeySpan Corporation is no longer included in the index since it was acquired by National Grid plc in August 2007; Peoples Energy Corporation is no longer included in the index since it was acquired by WPS Resources, Inc. to form Integrys Energy Group, Inc. in February 2007.


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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2007.
 
                         
    Number of
          Number of Securities Remaining
 
    Securities to be Issued
    Weighted-Average
    Available for Future Issuance
 
    Upon Exercise of
    Exercise Price of
    Under Equity Compensation
 
    Outstanding Options,
    Outstanding Options,
    Plans (Excluding Securities
 
    Warrants and Rights     Warrants and Rights     Reflected in Column (a))  
    (a)     (b)     (c)  
 
Equity compensation plans approved by security holders:
                       
Long-Term Incentive Plan
    920,841     $ 22.54       2,730,192  
                         
Total equity compensation plans approved by security holders
    920,841       22.54       2,730,192  
Equity compensation plans not approved by security holders
                 
                         
Total
    920,841     $ 22.54       2,730,192  
                         


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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  
    2007(1)     2006(1)     2005(2)     2004(3)     2003(4)  
    (In thousands, except per share data and ratios)  
 
Results of Operations
                                       
Operating revenues
  $ 5,898,431     $ 6,152,363     $ 4,961,873     $ 2,920,037     $ 2,799,916  
Gross profit
    1,250,082       1,216,570       1,117,637       562,191       534,976  
Operating expenses(1)
    851,446       833,954       768,982       368,496       347,136  
Operating income
    398,636       382,616       348,655       193,695       187,840  
Miscellaneous income(3)
    9,184       881       2,021       9,507       2,191  
Interest charges
    145,236       146,607       132,658       65,437       63,660  
Income before income taxes and cumulative effect of accounting change
    262,584       236,890       218,018       137,765       126,371  
Cumulative effect of accounting change, net income tax benefit
                            (7,773 )
Income tax expense
    94,092       89,153       82,233       51,538       46,910  
Net income
  $ 168,492     $ 147,737     $ 135,785     $ 86,227     $ 71,688  
Weighted average diluted shares outstanding
    87,745       81,390       79,012       54,416       46,496  
Diluted net income per share
  $ 1.92     $ 1.82     $ 1.72     $ 1.58     $ 1.54  
Cash flows from operations
    547,095       311,449       386,944       270,734       49,541  
Cash dividends paid per share
  $ 1.28     $ 1.26     $ 1.24     $ 1.22     $ 1.20  
Total natural gas distribution throughput (MMcf)
    427,869       393,995       411,134       246,033       247,965  
Total regulated transmission and storage transportation volumes (MMcf)
    505,493       410,505       373,879              
Total natural gas marketing sales volumes (MMcf)
    370,668       283,962       238,097       222,572       225,961  
Financial Condition
                                       
Net property, plant and equipment(5)
  $ 3,836,836     $ 3,629,156     $ 3,374,367     $ 1,722,521     $ 1,624,394  
Working capital(5)
    149,217       (1,616 )     151,675       283,310       16,248  
Total assets(5)(6)
    5,896,917       5,719,547       5,653,527       2,912,627       2,625,495  
Short-term debt, inclusive of current maturities of long-term debt
    154,430       385,602       148,073       5,908       127,940  
Capitalization:
                                       
Shareholders’ equity
    1,965,754       1,648,098       1,602,422       1,133,459       857,517  
Long-term debt (excluding current maturities)
    2,126,315       2,180,362       2,183,104       861,311       862,500  
                                         
Total capitalization
    4,092,069       3,828,460       3,785,526       1,994,770       1,720,017  
Capital expenditures
    392,435       425,324       333,183       190,285       159,439  
Financial Ratios
                                       
Capitalization ratio(6)
    46.3 %     39.1 %     40.7 %     56.7 %     46.4 %
Return on average shareholders’ equity(7)
    8.8 %     8.9 %     9.0 %     9.1 %     9.9 %
 
See footnotes on the following page.


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(1) Financial results for 2007 and 2006 include a $6.3 million and a $22.9 million pre-tax loss for the impairment of certain assets.
 
(2) Financial results for 2005 include the results of the Mid-Tex Division and the Atmos Pipeline — Texas Division from October 1, 2004, the date of acquisition.
 
(3) 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.
 
(4) Financial results for fiscal 2003 include the results of MVG from December 3, 2002, the date of acquisition.
 
(5) Beginning in 2004, we reclassified our regulatory cost of removal obligation from accumulated depreciation to a liability. These reclassifications did not impact our financial position, results of operations or cash flows as of and for the year ended September 30, 2003.
 
(6) The capitalization ratio is calculated by dividing shareholders’ equity by the sum of total capitalization and short-term debt, inclusive of current maturities of long-term debt. Beginning in 2004 we 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.
 
(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, 2007.
 
                                                 
    Year Ended September 30, 2007  
          Regulated
          Pipeline,
             
    Natural Gas
    Transmission
    Natural Gas
    Storage
             
    Distribution     and Storage     Marketing     and Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 3,358,147     $ 84,344     $ 2,432,280     $ 23,660     $     $ 5,898,431  
Intersegment revenues
    618       78,885       719,050       9,740       (808,293 )      
                                                 
      3,358,765       163,229       3,151,330       33,400       (808,293 )     5,898,431  
Purchased gas cost
    2,406,081             3,047,019       792       (805,543 )     4,648,349  
                                                 
Gross profit
    952,684       163,229       104,311       32,608       (2,750 )     1,250,082  
Operating expenses
    731,497       83,399       29,271       10,373       (3,094 )     851,446  
                                                 
Operating income
    221,187       79,830       75,040       22,235       344       398,636  
Miscellaneous income
    8,945       2,105       6,434       8,173       (16,473 )     9,184  
Interest charges
    121,626       27,917       5,767       6,055       (16,129 )     145,236  
                                                 
Income before income taxes
    108,506       54,018       75,707       24,353             262,584  
Income tax expense
    35,223       19,428       29,938       9,503             94,092  
                                                 
Net income
  $ 73,283     $ 34,590     $ 45,769     $ 14,850     $     $ 168,492  
                                                 
Capital expenditures
  $ 327,442     $ 59,276     $ 1,069     $ 4,648     $     $ 392,435  
                                                 


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ITEM 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
INTRODUCTION
 
This section provides management’s discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.
 
Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors”. 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 such forward-looking statements.
 
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 27A of the Securities Act of 1933 and 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 us 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 our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “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 our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: 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, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in one state; adverse weather conditions; our 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; the capital-intensive nature of our distribution business, increased competition from energy suppliers and alternative forms of energy; increased costs of providing pension and postretirement health care benefits; the impact of environmental regulations on our business; the inherent hazards and risks involved in operating our distribution business, natural disasters, terrorist activities or other events, and other risks and uncertainties discussed herein, especially in Item 1A above, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe 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, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
 
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


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assets. Our critical accounting policies are reviewed by the Audit Committee quarterly. Actual results may differ from estimates.
 
Regulation — Our natural gas distribution and regulated transmission and storage 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 operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in their financial statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because they can be recovered through rates. Discontinuing the application of SFAS 71 could significantly increase our operating expenses as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our natural gas distribution operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.
 
Revenue recognition — Sales of natural gas to our natural gas distribution 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 natural gas distribution 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. Revenue is recognized in our regulated transmission and storage segment as the services are provided.
 
On occasion, we are permitted to implement new rates that have not been formally approved by our regulatory authorities and are subject to refund. As permitted by SFAS No. 71, we recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.
 
Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas adjustment mechanisms. Purchased gas adjustment mechanisms provide gas utility companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of the utility company’s non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of expense, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility company’s other costs, (ii) represents a large component of the utility company’s cost of service and (iii) is generally outside the control of the gas utility company. There is no gross profit generated through purchased gas adjustments, but they provide a dollar-for-dollar offset to increases or decreases in utility gas costs. Although substantially all natural gas distribution sales to our customers fluctuate with the cost of gas that we purchase, our gross profit is generally not affected by fluctuations in the cost of gas as a result of 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 in which 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 are included as a component of natural gas marketing revenues.
 
Operating revenues for our pipeline, storage and other segment are recognized in the period in which actual volumes are transported and storage services are provided.


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Allowance for doubtful accounts — We record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of our customers’ inability or reluctance to pay. 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. Accounts are written off once they are deemed to be uncollectible.
 
Derivatives and hedging activities — Our natural gas distribution segment uses a combination of physical storage and financial derivatives to partially insulate our natural gas distribution customers against gas price volatility during the winter heating season. These financial derivatives have not been designated as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Accordingly, they are recorded at fair value. However, because the costs associated with and the gains and losses arising from these financial derivatives are included in our purchased gas adjustment mechanisms, changes in the fair value of these financial derivatives are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas costs when the related costs are recovered through our rates in accordance with SFAS 71. Accordingly, there is no earnings impact to our natural gas distribution segment as a result of the use of financial derivatives.
 
Our natural gas marketing and pipeline, storage and other segments are exposed to commodity price risk associated with our natural gas inventories, and, in our natural gas marketing segment, on our fixed-price contracts. We manage this risk through a combination of physical 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 daily.
 
We have designated the natural gas inventory held by Atmos Energy Marketing and Atmos Pipeline and Storage, LLC as the hedged item in a fair-value hedge. This inventory is marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in revenue in the period of change. The derivatives associated with this natural gas inventory have been designated as fair value hedges and are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in the period of change. The difference in the spot price used to value our physical inventory (Gas Daily) and the forward price used to value the related fair-value hedges (NYMEX) are reported as a component of revenue and can result in volatility in our reported net income. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges.
 
We recognize revenue and the associated carrying value of the inventory (inclusive of storage costs) as purchased gas costs in our consolidated statement of income when we sell the gas and deliver it out of the storage facility. Over time, we expect gains and losses on the sale of storage gas inventory to 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.
 
We have elected to treat our fixed-price forward contracts as normal purchases and sales and have designated the associated derivative contracts as cash flow hedges of anticipated transactions. Accordingly, unrealized gains and losses on these open derivative contracts are 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. Hedge ineffectiveness, to the extent incurred, is reported as a component of revenue.
 
Additionally, our natural gas marketing segment utilizes storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. Although the purpose of these instruments is to either reduce basis or other risks or lock in arbitrage opportunities, these derivative


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instruments have not been designated as hedges pursuant to SFAS 133. Accordingly, these derivative instruments are recorded at fair value with all changes in fair value included in revenue.
 
In addition to mitigating commodity price risk, we periodically manage our exposure to interest rate changes by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We have designated each of our previously executed Treasury lock agreements as a cash flow hedge of an anticipated transaction at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements are recorded as a component of accumulated other comprehensive income. The realized gain or loss recognized upon settlement of the Treasury lock agreement is initially recorded as a component of accumulated other comprehensive income and is recognized as a component of interest expense over the life of the related financing arrangement.
 
The fair value of all 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 then current 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. We have determined our reporting units to be each of our natural gas distribution divisions and wholly-owned subsidiaries. Goodwill is allocated to the reporting units responsible for the acquisition that gave rise to the goodwill. The discounted cash flow calculations used to assess goodwill impairment are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.
 
We annually assess whether the cost of our intangible assets subject to amortization or other long-lived assets is recoverable or that the remaining useful lives may warrant revision. We perform this assessment more frequently when specific events or circumstances have occurred that suggest the recoverability of the cost of the intangible and other long-lived assets is at risk.
 
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 from the operating division or subsidiary to which these assets relate. 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 costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. We review the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities annually based upon a June 30 measurement date. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate


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and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
 
The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on Moody’s Aa bond index, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with a high quality corporate bond spot rate curve.
 
The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan cost over a period of approximately ten to twelve years.
 
We estimate the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.
 
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 cost ultimately recognized. A 0.25 percent change in our discount rate would impact our pension and postretirement cost by approximately $0.9 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement cost by approximately $0.9 million.
 
RESULTS OF OPERATIONS
 
Overview
 
Atmos Energy Corporation is involved in the distribution, marketing and transportation of natural gas. Accordingly, our results of operations are impacted by the demand for natural gas, particularly during the winter heating season, and the volatility of the natural gas markets. 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. As a result of the seasonality of the natural gas industry, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 63 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. Additionally, the seasonality of this industry impacts the levels of accounts receivable, accounts payable, gas stored underground and short-term debt balances we report at various time of the fiscal year.


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Consolidated Results
 
The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2007, 2006 and 2005.
 
                         
    For the Year Ended September 30  
    2007     2006     2005  
    (In thousands, except per share data)  
 
Operating revenues
  $ 5,898,431     $ 6,152,363     $ 4,961,873  
Gross profit
    1,250,082       1,216,570       1,117,637  
Operating expenses
    851,446       833,954       768,982  
Operating income
    398,636       382,616       348,655  
Miscellaneous income
    9,184       881       2,021  
Interest charges
    145,236       146,607       132,658  
Income before income taxes
    262,584       236,890       218,018  
Income tax expense
    94,092       89,153       82,233  
Net income
  $ 168,492     $ 147,737     $ 135,785  
Earnings per diluted share
  $ 1.92     $ 1.82     $ 1.72  
 
Historically, our regulated operations arising from our natural gas distribution operations and, beginning in fiscal 2005, from our Atmos Pipeline — Texas division, contributed 65 to 85 percent of our consolidated net income. However, in recent years, this contribution has declined due to the growth of our nonregulated natural gas marketing and pipeline and storage businesses coupled with lower natural gas distribution income. Regulated operations contributed 64 percent, 54 percent and 80 percent to our consolidated net income for fiscal years 2007, 2006 and 2005. Our consolidated net income during the last three fiscal years was earned across our business segments as follows:
 
                         
    For the Year Ended September 30  
    2007     2006     2005  
          (In thousands)        
 
Natural gas distribution segment
  $ 73,283     $ 53,002     $ 81,117  
Regulated transmission and storage segment
    34,590       26,547       27,582  
Natural gas marketing segment
    45,769       58,566       23,404  
Pipeline, storage and other segment
    14,850       9,622       3,682  
                         
Net income
  $ 168,492     $ 147,737     $ 135,785  
                         
 
The following table segregates our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    For the Year Ended September 30  
    2007     2006     2005  
    (In thousands, except per share data)  
 
Regulated operations
  $ 107,873     $ 79,549     $ 108,699  
Nonregulated operations
    60,619       68,188       27,086  
                         
Consolidated net income
  $ 168,492     $ 147,737     $ 135,785  
                         
Diluted EPS from regulated operations
  $ 1.23     $ 0.98     $ 1.38  
Diluted EPS from nonregulated operations
    0.69       0.84       0.34  
                         
Consolidated diluted EPS
  $ 1.92     $ 1.82     $ 1.72  
                         
 
The 14 percent year-over-year increase in net income during fiscal 2007 reflects improvements across all business segments. Results from our regulated operations reflect the net favorable impact of various ratemaking rulings in our natural gas distribution segment, including the implementation of WNA in our Mid-


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Tex and Louisiana Divisions coupled with increased throughput and incremental gross profit margins from our North Side Loop and other pipeline compression projects completed in fiscal 2006. The decrease in net income from our nonregulated operations primarily reflects the impact of a less volatile natural gas market, which reduced delivered gas margins despite a 31 percent increase in sales volumes. However, our nonregulated operations benefited from higher asset optimization margins, primarily in the pipeline, storage and other segment.
 
The nine percent year-over-year increase in net income during fiscal 2006 primarily reflects strong results in our nonregulated operations, partially offset by a decrease in our regulated operations. The net income from our nonregulated operations reflect the favorable impact of a volatile natural gas market, which provided increased opportunities to maximize delivered gas margins. Our nonregulated results were also favorably impacted by recording unrealized gains during fiscal 2006 compared to recording unrealized losses in fiscal 2005. The decrease in net income from our regulated operations primarily reflects the adverse effects on our natural gas distribution segment of weather (adjusted for WNA) that was 13 percent warmer than normal, the adverse effect of Hurricane Katrina on our Louisiana Division and a non-recurring, noncash charge to impair our West Texas Division irrigation assets.
 
Other key financial and significant events for the year ended September 30, 2007 include the following:
 
  •  In December 2006, we filed a $900 million shelf registration statement with the SEC that replaced our previously existing shelf registration statement. Upon completion of the filing of this registration statement, we received net proceeds of approximately $192 million through the issuance of approximately 6.3 million shares of common stock. The net proceeds received were used to repay a portion of our then-existing short-term debt balance.
 
  •  In June 2007, we received net proceeds of approximately $247 million from the issuance of senior notes. The net proceeds received, together with $53 million of available cash, were used to repay our $300 million unsecured floating rate senior notes, which were redeemed on July 15, 2007.
 
  •  Our total-debt-to-capitalization ratio at September 30, 2007 was 53.7 percent compared with 60.9 percent at September 30, 2006, primarily reflecting the $50 million reduction in long-term debt and lower short-term debt balances as of September 30, 2007.
 
  •  For the year ended September 30, 2007, we generated $547.1 million in operating cash flow compared with $311.4 million for the year ended September 30, 2006, primarily reflecting the favorable impact of increased earnings, increased sales volumes attributable to colder weather during the period and lower natural gas prices.
 
  •  Capital expenditures decreased to $392.4 million during the year ended September 30, 2007 from $425.3 million in the prior year. The decrease primarily reflects the absence of capital spending for the North Side Loop and other compression projects completed in fiscal 2006.
 
  •  In March 2007, the Texas Railroad Commission issued an order in our Mid-Tex Division’s rate case, which prospectively increased annual revenues by approximately $4.8 million and established a permanent WNA based upon a 10-year average effective for the months of November through April. However, the ruling also reduced the Mid-Tex Division’s total return to 7.903 percent from 8.258 percent and required a $2.9 million refund, inclusive of interest, of amounts collected from our calendar 2003 — 2005 GRIP filings.


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See the following discussion regarding the results of operations for each of our business operating segments.
 
Year ended September 30, 2007 compared with year ended September 30, 2006
 
Natural Gas Distribution Segment
 
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
 
Our ability to earn our authorized rates is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy and recent ratemaking initiatives in more detail.
 
One example of our recent ratemaking initiatives involves the substantial separation of the recovery of our margins from seasonal weather patterns. Prior to fiscal 2007, seasonal weather patterns significantly impacted our natural gas distribution results. The rate design in our two most weather-sensitive jurisdictions, the Louisiana and Mid-Tex divisions, which represent approximately 60 percent of our natural gas distribution residential and commercial meters, provided for limited weather protection. During fiscal 2006, we received WNA in these jurisdictions, beginning with the 2006-2007 winter heating season. WNA substantially offsets the effects of weather that is above or below normal by allowing us to increase the base rate portion of customers’ bills when weather is warmer than normal and to decrease the base rate when weather is colder than normal. Accordingly, gross profit margin in our service areas covered by WNA should be based substantially on the amount of gross profit that would result from normal weather, despite actual weather conditions that may be either warmer or colder than normal. After receiving WNA in our Louisiana and Mid-Tex divisions, we have weather protection for over 90 percent of our residential and commercial meters, which should substantially reduce the volatility in this segment’s operating results.
 
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the tax expense as a component of taxes, other than income. Although changes in revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income. Timing differences exist between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. The effect of these timing differences can be significant in periods of volatile gas prices, particularly in our Mid-Tex Division. These timing differences may favorably or unfavorably affect net income; however, these amounts should offset over time with no permanent impact on net income.
 
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.


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Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the year ended September 30, 2007 and 2006 are presented below.
 
                 
    For the Year Ended September 30  
    2007     2006  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 952,684     $ 925,057  
Operating expenses
    731,497       723,163  
                 
Operating income
    221,187       201,894  
Miscellaneous income
    8,945       9,506  
Interest charges
    121,626       126,489  
                 
Income before income taxes
    108,506       84,911  
Income tax expense
    35,223       31,909  
                 
Net income
  $ 73,283     $ 53,002  
                 
Natural gas distribution sales volumes — MMcf
    297,327       272,033  
Natural gas distribution transportation volumes — MMcf
    130,542       121,962  
                 
Total natural gas distribution throughput — MMcf
    427,869       393,995  
                 
Heating degree days
               
Actual (weighted average)
    2,879       2,527  
Percent of normal
    100 %     87 %
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.45     $ 0.50  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 8.09     $ 10.02  
 
The following table shows our operating income by natural gas distribution division for the fiscal years ended September 30, 2007 and 2006. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                                 
    2007     2006  
          Heating
          Heating
 
    Operating
    Degree Days
          Degree Days
 
    Income
    Percent of
    Operating
    Percent of
 
    (Loss)     Normal(1)     Income     Normal(1)  
    (In thousands, except degree day information)  
 
Colorado-Kansas
  $ 22,392       104 %   $ 22,524       99 %
Kentucky/Mid-States
    42,161       97 %     49,893       98 %
Louisiana
    44,193       105 %     27,772       78 %
Mid-Tex
    68,574       100 %     71,703       72 %
Mississippi
    23,225       101 %     23,276       102 %
West Texas
    21,036       99 %     2,215       100 %
Other
    (394 )           4,511        
                                 
Total
  $ 221,187       100 %   $ 201,894       87 %
                                 
 
 
(1) Adjusted for service areas that have weather-normalized operations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.


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The $27.6 million increase in natural gas distribution gross profit primarily reflects a nine percent increase in throughput and the impact of having WNA coverage for more than 90 percent of our residential and commercial customers, which increased gross profit by $38.6 million. Included in this amount was a $10.8 million increase associated with the implementation of WNA in our Mid-Tex and Louisiana Divisions beginning with the 2006-2007 winter heating season.
 
As a result of the Mid-Tex rate case, our gas distribution gross profit increased by $5.4 million compared to the prior year. This increase was partially offset by a decrease in Mid-Tex transportation revenue as the rate case reduced the transportation rates for certain customer classes. The Mid-Tex rate case also required the refund of $2.9 million collected under GRIP, which reduced gross profit in the current year.
 
Favorable regulatory activity in the current year increased gross profit by $24.4 million, primarily due to an $11.8 million increase in GRIP-related recoveries and a $10.2 million increase from our Rate Stabilization Clause (RSC) filings in our Louisiana service areas. These increases were partially offset by an $11.6 million decrease in gross profit associated with regulatory rulings in our Tennessee, Louisiana and Virginia jurisdictions.
 
Offsetting these increases in gross profit was a reduction in revenue-related taxes. Due to a significant decline in the cost of gas in the current-year period compared with the prior-year period, franchise and state gross receipts taxes included in gross profit decreased approximately $1.7 million; however, franchise and state gross receipts tax expense recorded as a component of taxes, other than income decreased $5.4 million, which resulted in a $3.7 million increase in operating income when compared with the prior-year period.
 
Natural gas distribution gross profit also reflects a $7.5 million accrual for estimated unrecoverable gas costs. The remaining decrease in gross profit primarily is attributable to lower irrigation margins and a reduction in pass-through surcharges used to recover various costs as these costs were fully recovered by the end of fiscal 2006 and during fiscal 2007.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income, and impairment of long-lived assets, increased to $731.5 million for the year ended September 30, 2007 from $723.2 million for the year ended September 30, 2006.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $22.4 million, primarily due to increased employee and other administrative costs. These increases include the personnel and other operating costs associated with the transfer of our gas supply function from our pipeline, storage and other segment to our natural gas distribution segment effective January 1, 2007. Partially offsetting these increases was the deferral of $4.3 million of operation and maintenance expense in our Louisiana Division resulting from the Louisiana Public Service Commission’s ruling to allow recovery of all incremental operation and maintenance expense incurred in fiscal 2005 and 2006 in connection with our Hurricane Katrina recovery efforts.
 
The provision for doubtful accounts decreased $0.8 million to $19.8 million for the year ended September 30, 2007. The decrease primarily was attributable to reduced collection risk as a result of lower natural gas prices. In the natural gas distribution segment, the average cost of natural gas for the year ended September 30, 2007 was $8.09 per Mcf, compared with $10.02 per Mcf for the year ended September 30, 2006.
 
Depreciation and amortization expense increased $12.7 million for the year ended September 30, 2007 compared with the prior-year period. The increase was primarily attributable to increases in assets placed in service during fiscal 2007. Additionally, the increase was partially attributable to the absence in the current-year period of a $2.8 million reduction in depreciation expense recorded in the prior-year period arising from the Mississippi Public Service Commission’s decision to allow certain deferred costs in our rate base.
 
Operating expenses for the year ended September 30, 2007 included a $3.3 million noncash charge associated with the write-off of costs for software that will no longer be used. Fiscal 2006 results included a $22.9 million noncash charge to impair the West Texas Division irrigation properties.


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Interest charges
 
Interest charges allocated to the natural gas distribution segment for the year ended September 30, 2007 decreased to $121.6 million from $126.5 million for the year ended September 30, 2006. The decrease primarily was attributable to lower average outstanding short-term debt balances in the current-year period compared with the prior-year period.
 
Regulated Transmission and Storage Segment
 
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking arrangements, lending and sales of inventory on hand.
 
Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the years ended September 30, 2007 and 2006 are presented below.
 
                 
    For the Year Ended
 
    September 30  
    2007     2006  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 77,090     $ 69,925  
Third-party transportation
    65,158       56,813  
Storage and park and lend services
    9,374       8,047  
Other
    11,607       6,348  
                 
Gross profit
    163,229       141,133  
Operating expenses
    83,399       77,807  
                 
Operating income
    79,830       63,326  
Miscellaneous income (expense)
    2,105       (153 )
Interest charges
    27,917       22,787  
                 
Income before income taxes
    54,018       40,386  
Income tax expense
    19,428       13,839  
                 
Net income
  $ 34,590     $ 26,547  
                 
Pipeline transportation volumes — MMcf
    505,493       410,505  
                 
 
The $22.1 million increase in gross profit primarily is attributable to a 23 percent increase in throughput due to colder weather in the current year and incremental volumes from the North Side Loop and other compression projects. These activities increased gross profit by $16.2 million, of which, $10.8 million was associated with our North Side Loop and other compression projects completed in fiscal 2006. Increases in gross profit also include a $3.1 million increase from rate adjustments resulting from our 2005 GRIP filing, a


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$2.1 million increase from the sale of excess gas inventory and a $2.0 million increase from new or renegotiated blending and capacity enhancement contracts.
 
Operating expenses increased to $83.4 million for the year ended September 30, 2007 from $77.8 million for the year ended September 30, 2006 due to higher administrative and other operating costs primarily associated with the North Side Loop and other compression projects that were completed in fiscal 2006.
 
Interest charges
 
Interest charges allocated to the pipeline and storage segment for the year ended September 30, 2007 increased to $27.9 million from $22.8 million for the year ended September 30, 2006. The increase was attributable to the use of updated allocation factors for fiscal 2007. These factors are reviewed and updated on an annual basis.
 
Natural Gas Marketing Segment
 
Our natural gas marketing segment aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers 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, revenues and gross profit from this segment 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 perform.
 
To optimize the storage and transportation capacity we own or control, we participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. 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 physical natural gas and then sell financial contracts at favorable prices to lock in gross profit margins. Through the use of transportation and storage services and derivative contracts, we seek to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
 
AEM continually manages its net physical position to enhance the future economic profit it captured when an original transaction was executed. Therefore, AEM may change its scheduled injection and withdrawal plans from one time period to another based on market conditions or adjust the amount of storage capacity it holds on a discretionary basis in an effort to achieve this objective.
 
The natural gas inventory used in our natural gas marketing storage activities is marked to market at the end of each month based upon the Gas Daily index with changes in fair value recognized as unrealized gains and losses in the period of change. We use derivatives, designated as fair value hedges, to hedge this natural gas inventory. These derivatives 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 changes between the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in the unrealized margins reported as a part of our storage activities until the underlying physical gas is cycled and the related financial derivatives are settled.
 
AEM also uses derivative instruments to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original physical inventory hedge and to insulate and protect the economic value within its storage and marketing activities. Changes in fair value associated with these financial


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instruments are recognized as unrealized gains and losses within AEM’s storage and marketing activities until they are settled.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas marketing segment for the years ended September 30, 2007 and 2006 are presented below. Gross profit margin for our natural gas marketing segment consists primarily of margins earned from the delivery of gas and related services requested by our customers; and asset optimization activities, which are derived from the utilization of our managed proprietary and third party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.
 
Unrealized margins represent the unrealized gains or losses on the derivative contracts used by our natural gas marketing segment to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.
 
                 
    For the Year Ended
 
    September 30  
    2007     2006  
    (In thousands, unless otherwise noted)  
 
Delivered gas
  $ 57,054     $ 87,236  
Asset optimization
    28,827       26,225  
Unrealized margins
    18,430       17,166  
                 
Gross profit
    104,311       130,627  
Operating expenses
    29,271       28,392  
                 
Operating income
    75,040       102,235  
Miscellaneous income
    6,434       2,598  
Interest charges
    5,767       8,510  
                 
Income before income taxes
    75,707       96,323  
Income tax expense
    29,938       37,757  
                 
Net income
  $ 45,769     $ 58,566  
                 
Natural gas marketing sales volumes — MMcf
    370,668       283,962  
                 
Net physical position (Bcf)
    12.3       14.5  
                 
 
The $26.3 million decrease in our natural gas marketing segment’s gross profit primarily reflects lower delivered gas margins, partially offset by higher asset optimization margins.
 
Delivered gas margins decreased $30.2 million compared with the prior-year period. This decrease reflects the impact of a less volatile market, which reduced opportunities to take advantage of pricing differences between hubs, partially offset by a 31 percent increase in sales volumes attributable to successful execution of our marketing strategies and colder weather in the current fiscal year compared with the prior year.
 
Asset optimization margins increased $2.6 million compared with the prior-year period. The increase reflects greater cycled storage volumes during the current-year period, partially offset by an increase in storage fees and park and loan fees which reduced the arbitrage spreads available.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $29.3 million for the


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year ended September 30, 2007 from $28.4 million for the year ended September 30, 2006. The increase in operating expense primarily was attributable to an increase in employee and other administrative costs.
 
Miscellaneous income
 
Miscellaneous income increased to $6.4 million for the year ended September 30, 2007 from $2.6 million for the year ended September 30, 2006. The increase primarily was attributable to increased investment income earned on overnight investments during the current-year period combined with increased interest income earned on our margin account associated with increased margin requirements during the current year.
 
Interest charges
 
Interest charges for the year ended September 30, 2007 decreased to $5.8 million from $8.5 million for the year ended September 30, 2006. The decrease was attributable to lower borrowing requirements during the current-year period.
 
Economic Gross Profit
 
AEM monitors the impacts of its asset optimization efforts by estimating the gross profit that it captured through the purchase and sale of physical natural gas and the associated financial derivatives. The reconciliation below of the economic gross profit, combined with the effect of unrealized gains or losses recognized in accordance with generally accepted accounting principles in the financial statements in prior periods, is presented to provide a measure of the potential gross profit from asset optimization that could occur in future periods if AEM’s optimization efforts are executed as planned. We consider this measure of potential gross profit a non-GAAP financial measure as it is calculated using both forward-looking and historical financial information. The following table presents AEM’s economic gross profit and its potential gross profit for the last three fiscal years.
 
                                 
                Associated Net
       
    Net Physical
    Economic Gross
    Unrealized Gain
    Potential Gross
 
Period Ending
  Position     Profit     (Loss)     Profit  
    (Bcf)     (In millions)     (In millions)     (In millions)  
 
September 30, 2007
    12.3     $ 40.8     $ 10.8     $ 30.0  
September 30, 2006
    14.5     $ 60.0     $ (16.0 )   $ 76.0  
September 30, 2005
    6.9     $ 13.1     $ (14.8 )   $ 27.9  
 
As of September 30, 2007, based upon AEM’s derivatives position and inventory withdrawal schedule, the economic gross profit was $40.8 million. This amount is reduced by $10.8 million of net unrealized gains recorded in the financial statements as of September 30, 2007 that will reverse when the inventory is withdrawn and the accompanying financial derivatives are settled. Therefore, the potential gross profit was $30.0 million. This potential gross profit amount will not result in an equal increase in future net income as AEM will incur additional storage and other operational expenses and increased income taxes to realize this amount.
 
The economic gross profit is based upon planned injection and withdrawal schedules, and the realization of the economic gross profit is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to enhance the future profitability of its storage position, it may change its scheduled injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic gross profit or the potential gross profit calculated as of September 30, 2007 will be fully realized in the future or in what time period. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted.


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Pipeline, Storage and Other Segment
 
Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are each wholly-owned by AEH.
 
APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, beginning in fiscal 2006, APS initiated activities in the natural gas gathering business. As of September 30, 2007, these activities were limited in nature.
 
AES, through December 31, 2006, provided natural gas management services to our natural gas distribution operations, other than the Mid-Tex Division. These services included aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our natural gas distribution service areas at competitive prices. Effective January 1, 2007, these activities were moved to our shared services function included in our natural gas distribution segment. AES continues to provide limited services to our natural gas distribution divisions, and the revenues AES receives are equal to the costs incurred to provide those services.
 
Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.
 
Results for this segment are primarily impacted by seasonal weather patterns and volatility in the natural gas markets. Additionally, this segment’s results include an unrealized component as APS hedges its risk associated with its asset optimization activities.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our pipeline, storage and other segment for the years ended September 30, 2007 and 2006 are presented below.
 
                 
    For the Year Ended
 
    September 30  
    2007     2006  
    (In thousands, unless otherwise noted)  
 
Storage and transportation services
  $ 15,968     $ 11,841  
Asset optimization
    10,751       3,387  
Other
    3,792       5,916  
Unrealized margins
    2,097       3,350  
                 
Gross profit
    32,608       24,494  
Operating expenses
    10,373       9,570  
                 
Operating income
    22,235       14,924  
Miscellaneous income
    8,173       6,858  
Interest charges
    6,055       6,512  
                 
Income before income taxes
    24,353       15,270  
Income tax expense
    9,503       5,648  
                 
Net income
  $ 14,850     $ 9,622  
                 
Pipeline transportation volumes — MMcf
    4,150       5,439  
                 
 
Gross profit increased $8.1 million primarily due to APS’ ability to capture more favorable arbitrage spreads from its asset optimization activities, an increase in asset optimization contracts and increased transportation margins.


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Operating expenses increased to $10.4 million for the year ended September 30, 2007 from $9.6 million for the year ended September 30, 2006 primarily due to a $3.0 million noncash charge associated with the write-off of costs associated with a natural gas gathering project. This increase was partially offset by a decrease in employee and other administrative costs associated with the transfer of gas supply operations from the pipeline, storage and other segment to our natural gas distribution segment effective January 1, 2007.
 
Miscellaneous income
 
Miscellaneous income increased to $8.2 million for the year ended September 30, 2007 from $6.9 million for the year ended September 30, 2006. The increase was primarily attributable to $2.1 million received from leasing certain mineral interests coupled with an increase in interest income recorded in the pipeline, storage and other segment.
 
Interest charges
 
Interest charges allocated to the pipeline, storage and other segment for the year ended September 30, 2007 decreased to $6.1 million from $6.5 million for the year ended September 30, 2006. The decrease was attributable to the use of updated allocation factors for fiscal 2007. These factors are reviewed and updated on an annual basis.
 
Year ended September 30, 2006 compared with year ended September 30, 2005
 
Natural Gas Distribution Segment
 
Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2006 and 2005 are presented below.
 
                 
    For the Year Ended September 30  
    2006     2005  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 925,057     $ 907,366  
Operating expenses
    723,163       671,001  
                 
Operating income
    201,894       236,365  
Miscellaneous income
    9,506       6,776  
Interest charges
    126,489       112,382  
                 
Income before income taxes
    84,911       130,759  
Income tax expense
    31,909       49,642  
                 
Net income
  $ 53,002     $ 81,117  
                 
Natural gas distribution sales volumes — MMcf
    272,033       296,283  
Natural gas distribution transportation volumes — MMcf
    121,962       114,851  
                 
Total natural gas distribution throughput — MMcf
    393,995       411,134  
                 
Heating degree days
               
Actual (weighted average)
    2,527       2,587  
Percent of normal
    87 %     89 %
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.50     $ 0.51  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 10.02     $ 7.41  


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The following table shows our operating income by natural gas distribution division for the fiscal years ended September 30, 2006 and 2005. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                                 
    2006     2005  
          Heating Degree
          Heating Degree
 
    Operating
    Days Percent
    Operating
    Days Percent
 
    Income     of Normal(1)     Income     of Normal(1)  
    (In thousands, except degree day information)  
 
Colorado-Kansas
  $ 22,524       99 %   $ 25,157       99 %
Kentucky/Mid-States
    49,893       98 %     54,344       96 %
Louisiana
    27,772       78 %     24,819       78 %
Mid-Tex
    71,703       72 %     84,965       80 %
Mississippi
    23,276       102 %     19,045       96 %
West Texas
    2,215       100 %     27,520       99 %
Other
    4,511             515        
                                 
Total
  $ 201,894       87 %   $ 236,365       89 %
                                 
 
 
(1) Adjusted for service areas that have weather-normalized operations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.
 
Natural gas distribution gross profit increased to $925.1 million for the year ended September 30, 2006 from $907.4 million for the year ended September 30, 2005. Total throughput for our natural gas distribution business was 394.0 Bcf during the current year compared to 411.1 Bcf in the prior year.
 
The increase in natural gas distribution gross profit, despite lower throughput, primarily reflects higher franchise fees and state gross receipts taxes, which are paid by customers and have no permanent effect on net income. Additionally, margins increased approximately $14.0 million due to rate increases received from our fiscal 2005 and fiscal 2004 GRIP filings and the recognition of $3.3 million that had been previously deferred in Louisiana following the LPSC’s ratification of our agreement in May 2006. These increases were partially offset by approximately $22.9 million due to the impact of significantly warmer than normal weather, particularly in our Mid-Tex and Louisiana divisions. For the year ended September 30, 2006, weather was 13 percent warmer than normal, as adjusted for jurisdictions with weather-normalized operations and two percent warmer than the prior year. In the Mid-Tex and Louisiana Divisions, which did not have weather-normalized rates during the 2005-2006 winter heating season, weather was 28 percent and 22 percent warmer than normal.
 
Additionally, natural gas distribution gross profit decreased approximately $2.9 million compared with the prior year in the Louisiana Division due to the impact of Hurricane Katrina. Service has been restored in some areas affected by the storm; however, it is likely that service will not be restored to all of the affected service areas. As more fully described under Ratemaking Activity, we implemented new rates in September 2006 that reflect the impact of Hurricane Katrina.
 
Operating expenses increased to $723.2 million for the year ended September 30, 2006 from $671.0 million for the year ended September 30, 2005. The increase reflects a $13.3 million increase in taxes, other than income, primarily related to franchise fees and state gross receipts taxes, both of which are calculated as a percentage of revenue, and are paid by our customers as a component of their monthly bills. Although these amounts are included as a component of revenue in accordance with our tariffs, timing differences between when these amounts are billed to our customers and when we recognize the associated expense may affect net income favorably or unfavorably on a temporary basis. However, there is no permanent effect on net income.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $7.8 million primarily due to higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party, higher medical and dental claims and increased pension and


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postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Increased line locate, telecommunication and facilities costs also contributed to the overall increase. These increases were partially offset by a reduction in third-party costs for outsourced administrative and meter reading functions that were in-sourced during fiscal 2006. Operation and maintenance expense for the year ended September 30, 2006 was also favorably impacted by the absence of $2.1 million of merger and integration cost amortization associated with the merger of United Cities Gas Company in July 1997, as these costs were fully amortized by December 2004.
 
The provision for doubtful accounts increased $3.1 million to $20.6 million for the year ended September 30, 2006, compared with $17.5 million in the prior year. The increase was primarily attributable to increased collection risk associated with higher natural gas prices. In the natural gas distribution segment, the average cost of natural gas for the year ended September 30, 2006 was $10.02 per Mcf, compared with $7.41 per Mcf for the year ended September 30, 2005.
 
Additionally, during the first quarter of fiscal 2006, the MPSC, in connection with the modification of our rate design, decided to allow the recovery of $2.8 million in deferred costs, which it had originally disallowed in its September 2004 decision. This charge was originally recorded in fiscal 2004. This ruling decreased our depreciation expense during the year ended September 30, 2006. This decrease was offset by increased depreciation expense associated with the placement of various capital projects into service during the fiscal year.
 
Operating expenses were also impacted by a $22.9 million noncash charge to impair our West Texas Division’s irrigation assets. During the fiscal 2006 fourth quarter, we determined that, as a result of declining irrigation sales primarily associated with our agricultural customers’ shift from gas-powered pumps to electric pumps, the West Texas Division’s irrigation assets would not be able to generate sufficient future cash flows from operations to recover the net investment in these assets. Therefore, the entire net book value was written off. We will continue to operate these assets until we determine a plan for these assets as we are obligated to provide natural gas services to certain customers served by these assets. We are currently evaluating an opportunity to sell these assets in the first quarter of fiscal 2008. We do not expect the outcome of this potential transaction to materially affect our results of operations.
 
As a result of the aforementioned factors, our natural gas distribution segment operating income for the year ended September 30, 2006 decreased to $201.9 million from $236.4 million for the year ended September 30, 2005.
 
Miscellaneous income
 
Miscellaneous income for the year ended September 30, 2006 was $9.5 million compared to miscellaneous income of $6.8 million for the year ended September 30, 2005. This increase was primarily attributable to increased interest income on intercompany borrowings to our natural gas marketing segment to fund its working capital needs. This increase was partially offset by a $3.3 million charge recorded during the fiscal 2006 second quarter associated with an adverse ruling in Tennessee related to the calculation of a performance-based rate mechanism associated with gas purchases.
 
Interest charges
 
Interest charges allocated to the natural gas distribution segment for the year ended September 30, 2006 increased to $126.5 million from $112.4 million for the year ended September 30, 2005. The increase was attributable to higher average outstanding short-term debt balances to fund natural gas purchases at significantly higher prices coupled with an approximate 200 basis point increase in the interest rate on our $300 million unsecured floating rate Senior Notes due 2007 due to an increase in the three-month LIBOR rate. These increases were partially offset by $4.8 million of interest savings arising from the early payoff of $72.5 million of our First Mortgage Bonds in June 2005.


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Regulated Transmission and Storage Segment
 
Financial and operational highlights for our regulated transmission and storage segment for the years ended September 30, 2006 and 2005 are presented below.
 
                 
    For the Year Ended
 
    September 30  
    2006     2005  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 69,925     $ 70,089  
Third-party transportation
    56,813       44,348  
Storage and park and lend services
    8,047       4,235  
Other
    6,348       19,362  
                 
Gross profit
    141,133       138,034  
Operating expenses
    77,807       72,194  
                 
Operating income
    63,326       65,840  
Miscellaneous income (expense)
    (153 )     150  
Interest charges
    22,787       23,344  
                 
Income before income taxes
    40,386       42,646  
Income tax expense
    13,839       15,064  
                 
Net income
  $ 26,547     $ 27,582  
                 
Pipeline transportation volumes — MMcf
    410,505       373,879  
                 
 
Gross profit increased to $141.1 million for the year ended September 30, 2006 from $138.0 million for the year ended September 30, 2005. Total pipeline transportation volumes were 581.3 Bcf during the year ended September 30, 2006, compared with 554.5 Bcf for the prior year. Excluding intersegment transportation volumes, total pipeline transportation volumes were 410.5 Bcf during the current year compared with 373.9 Bcf in the prior year.
 
The increase in gross profit was primarily attributable to increased third-party throughput and ancillary service margins. The increase in third-party transportation margins was primarily attributable to increases in the electric-generation market due to the warmer than normal temperatures during the summer of 2006, increased demand for through-system transportation services due to a widening of pricing differentials between the pipeline’s hubs and the impact of Atmos Pipeline — Texas’ North Side Loop and other compression projects that were placed into service in June 2006. Storage and parking and lending services on Atmos Pipeline — Texas also increased during fiscal 2006 as a result of the widening of pricing differentials between the pipeline’s hubs, which increased the attractiveness of storing gas on the pipeline and our ability to obtain improved margins for these services. The increases on Atmos Pipeline — Texas’ system were partially offset by a decrease in margins earned from intercompany transportation services to our Mid-Tex Division due to the significantly warmer than normal weather experienced during fiscal 2006. Additionally, these increases were partially offset by the absence of inventory sales of $3.0 million realized in the prior year.
 
Operating expenses increased to $77.8 million for the year ended September 30, 2006 from $72.2 million for the year ended September 30, 2005 due to higher employee benefit costs associated with an increase in headcount, increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs, higher facilities costs and higher pipeline integrity costs.
 
As a result of the aforementioned factors, our regulated transmission and storage segment operating income for the year ended September 30, 2006 decreased to $63.3 million from $65.8 million for the year ended September 30, 2005.


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Natural Gas Marketing Segment
 
Financial and operational highlights for our natural gas marketing segment for the years ended September 30, 2006 and 2005 are presented below.
 
                 
    For the Year Ended
 
    September 30  
    2006     2005  
    (In thousands, unless otherwise noted)  
 
Delivered gas
  $ 87,236     $ 59,971  
Asset optimization
    26,225       28,008  
Unrealized margins
    17,166       (26,006 )
                 
Gross profit
    130,627       61,973  
Operating expenses
    28,392       20,988  
                 
Operating income
    102,235       40,985  
Miscellaneous income
    2,598       771  
Interest charges
    8,510       3,405  
                 
Income before income taxes
    96,323       38,351  
Income tax expense
    37,757       14,947  
                 
Net income
  $ 58,566     $ 23,404  
                 
Natural gas marketing sales volumes — MMcf
    283,962       238,097  
                 
Net physical position (Bcf)
    14.5       6.9  
                 
 
The $68.7 million increase in our natural gas marketing segment’s gross profit reflects increased delivered gas margins and increased unrealized margins partially offset by a decrease in asset optimization margins.
 
Delivered gas margins increased $27.3 million during fiscal 2006 as a result of increased sales volumes resulting from focusing our marketing efforts on higher margin opportunities partially offset by warmer-than-normal weather across our market areas. The increase in gas delivery margins also reflected our ability to successfully capture increased per unit margins in certain market areas that experienced higher market volatility.
 
Asset optimization margins decreased $1.8 million primarily due to the realization of less favorable arbitrage spreads during the current year period compared with the prior year, coupled with increased storage fees.
 
The favorable unrealized margin variance primarily was due to a favorable movement during the year ended September 30, 2006 in the forward natural gas prices associated with financial derivatives used in our gas delivery activities, a narrowing of the physical/forward spreads during fiscal 2006 and positive basis ineffectiveness on our financial derivatives. These results were magnified by a 7.6 Bcf increase in our net physical position at September 30, 2006 compared to the prior 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 $28.4 million for the year ended September 30, 2006 from $21.0 million for the year ended September 30, 2005. The increase in operating expense primarily was attributable to an increase in personnel costs due to increased headcount and an increase in regulatory compliance costs.
 
The improved gross profit margin partially offset by higher operating expenses resulted in an increase in our natural gas marketing segment operating income to $102.2 million for the year ended September 30, 2006 compared with operating income of $41.0 million for the year ended September 30, 2005.


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Interest charges
 
Interest charges allocated to the natural gas marketing segment for the year ended September 30, 2006 increased to $8.5 million from $3.4 million for the year ended September 30, 2005. The increase was attributable to higher average outstanding debt balances to fund natural gas purchases at significantly higher prices.
 
Pipeline, Storage and Other Segment
 
Financial and operational highlights for our pipeline, storage and other segment for the years ended September 30, 2006 and 2005 are presented below.
 
                 
    For the Year Ended
 
    September 30  
    2006     2005  
    (In thousands, unless otherwise noted)  
 
Storage and transportation services
  $ 11,841     $ 11,539  
Asset optimization
    3,387       1,613  
Other
    5,916       5,324  
Unrealized margins
    3,350       (4,730 )
                 
Gross profit
    24,494       13,746  
Operating expenses
    9,570       8,482  
                 
Operating income
    14,924       5,264  
Miscellaneous income
    6,858       4,455  
Interest charges
    6,512       3,457  
                 
Income before income taxes
    15,270       6,262  
Income tax expense
    5,648       2,580  
                 
Net income
  $ 9,622     $ 3,682  
                 
Pipeline transportation volumes — MMcf
    5,439       5,580  
                 
 
Gross profit increased to $24.5 million for the year ended September 30, 2006 from $13.7 million for the year ended September 30, 2005. The increase in gross profit was primarily attributable to increased unrealized gains recorded during fiscal 2006 as favorable movements in the forward natural gas prices used to value the financial hedges designated against the physical inventory underlying these contracts resulted in an unrealized gain compared with an unrealized loss in the prior year. Additionally, APS recorded increased margins from its asset optimization activities due to its ability to capture more favorable arbitrage spreads.
 
Operating expenses increased to $9.6 million for the year ended September 30, 2006 from $8.5 million for the year ended September 30, 2005 due to higher employee and other administrative costs.
 
As a result of the aforementioned factors, our pipeline, storage and other segment operating income for the year ended September 30, 2006 increased to $14.9 million from $5.3 million for the year ended September 30, 2005.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Our internally generated funds and borrowings under our credit facilities and commercial paper program generally provide the liquidity needed to fund our working capital, capital expenditures and other cash needs. Additionally, from time to time, we raise funds from the public debt and equity capital markets through our existing shelf registration statement to fund our liquidity needs.


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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 services, the demand for our services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
 
Cash flows from operating activities
 
Year-over-year changes in our operating cash flows are primarily attributable to working capital changes within our natural gas distribution segment resulting from the impact of the price of natural gas and the timing of customer collections, payments for natural gas purchases, deferred gas cost recoveries and weather.
 
For the year ended September 30, 2007, we generated operating cash flow of $547.1 million compared with $311.4 million in fiscal 2006 and $386.9 million in fiscal 2005. The significant factors impacting our operating cash flow for the last three fiscal years are summarized below.
 
Year ended September 30, 2007
 
Fiscal 2007 operating cash flows reflect the favorable timing of payments for accounts payable and accrued liabilities, which increased operating cash flow by $107.6 million. Additionally, improved management of our deferred gas cost balances increased operating cash flow by $125.2 million. Finally, increased net income and other favorable working capital changes contributed to the increase in operating cash flow. Partially offsetting these increases in operating cash flow was a decrease in customer collections of $84.8 million due to the decrease in the price of natural gas during the current year.
 
Year ended September 30, 2006
 
Fiscal 2006 operating cash flows reflect the adverse impact of significantly higher natural gas prices. Year-over-year, unfavorable timing of payments for accounts payable and other accrued liabilities reduced operating cash flow by $523.0 million. Partially offsetting these outflows were higher customer collections ($245.1 million) and reduced payments for natural gas inventories ($102.1 million). Additionally, favorable movements in the market indices used to value our natural gas marketing segment risk management assets and liabilities reduced the amount that we were required to deposit in a margin account and therefore favorably affected operating cash flow by $126.3 million.
 
Year ended September 30, 2005
 
Fiscal 2005 operating cash flows reflect the effects of a $49.6 million increase in net income and effective working capital management partially offset by higher natural gas prices. Working capital management efforts, which affected the timing of payments for accounts payable and other accrued liabilities, favorably affected operating cash flow by $354.1 million. However, these efforts were partially offset by reduced cash flow generated from accounts receivable changes by $168.9 million, primarily attributable to higher natural gas prices, and an increase in our natural gas inventories attributable to a 13 percent year-over-year increase in natural gas prices coupled with increased natural gas inventory levels, which reduced operating cash flow by $81.8 million. Operating cash flow was also adversely impacted by unfavorable movements in the indices used to value our natural gas marketing segment risk management assets and liabilities, which resulted in a net liability for the segment. Accordingly, under the terms of the associated derivative contracts, we were required to deposit $81.0 million into a margin account.
 
Cash flows from investing activities
 
In recent years, a substantial portion of our cash resources has been used to fund acquisitions and growth projects, our ongoing construction program and improvements to information systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary


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capital spending to jurisdictions that permit us to earn a return on our investment timely. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
 
For the year ended September 30, 2007, we incurred $392.4 million for capital expenditures compared with $425.3 million for the year ended September 30, 2006 and $333.2 million for the year ended September 30, 2005. The decrease in capital expenditures in fiscal 2007 primarily reflects the absence of capital expenditures associated with our North Side Loop and other pipeline compression projects, which were completed during the fiscal 2006 third quarter. Our cash used for investing activities for the year ended September 30, 2005 reflects the $1.9 billion cash paid for the TXU Gas acquisition, including related transaction costs and expenses.
 
Cash flows from financing activities
 
For the year ended September 30, 2007, our financing activities used $159.3 million in cash compared with $155.3 million and $1.7 billion provided for the years ended September 30, 2006 and 2005. Our significant financing activities for the years ended September 30, 2007, 2006 and 2005 are summarized as follows:
 
  •  In December 2006, we raised net proceeds of approximately $192 million from the sale of approximately 6.3 million shares of common stock, including the underwriters’ exercise of their overallotment option of 0.8 million shares, under a shelf registration statement filed with the SEC in December 2006. The net proceeds from this issuance were used to reduce our then-existing short-term debt balance.
 
  •  In June 2007, we issued $250 million of 6.35% Senior Notes due 2017. The effective interest rate of this offering, inclusive of all debt issue costs, was 6.45 percent. After giving effect to the settlement of our $100 million Treasury lock agreement in June 2007, the effective rate on these senior notes was reduced to 6.26 percent. We used the net proceeds of $247 million, together with $53 million of available cash, to repay our $300 million unsecured floating rate senior notes, which were redeemed on July 15, 2007.
 
  •  During the years ended September 30, 2006 and 2005, we increased our borrowings under our short-term facilities by $237.6 million and $144.8 million whereas during the year ended September 30, 2007, we repaid a net $213.2 million under our short-term facilities. Net borrowings under our short-term facilities during fiscal 2006 and 2005 reflect the impact of seasonal natural gas purchases and the effect of higher natural gas prices.
 
  •  We repaid $303.2 million of long-term debt during the year ended September 30, 2007, compared with $3.3 million during the year ended September 30, 2006 and $103.4 million during the year ended September 30, 2005. Fiscal 2005 payments reflected the repayment of $72.5 million of our First Mortgage Bonds. In connection with this repayment we paid a $25.0 million make-whole premium in accordance with the terms of the agreements and accrued interest of approximately $1.0 million.
 
  •  During the year ended September 30, 2007, we paid $111.7 million in cash dividends compared with dividend payments of $102.3 million and $99.0 million for the years ended September 30, 2006 and 2005. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $1.26 per share during fiscal 2006 to $1.28 per share during fiscal 2007, combined with a 7.6 million increase in shares outstanding due to share issuances in connection with our December 2006 equity offering and new share issuances under our various plans.
 
  •  In October 2004, we sold a total of 16.1 million shares of common stock, including the underwriters’ exercise of their overallotment option, generating net proceeds of approximately $382 million. Additionally, we issued $1.39 billion of senior unsecured debt. The net proceeds from these issuances, combined with the net proceeds of $235.7 million from a July 2004 common stock offering were used to finance the acquisition of our Mid-Tex and Atmos Pipeline — Texas divisions and settle Treasury lock agreements, into which we entered to fix the Treasury yield component of the interest cost of financing associated with $875 million of the $1.39 billion long-term debt we issued.


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In addition to the December 2006 equity offering described above, during the year ended September 30, 2007 we issued 0.9 million shares of common stock which generated net proceeds of $24.9 million. In addition, we granted 0.4 million shares of common stock under our 1998 Long-Term Incentive Plan to directors, officers and other participants in the plan. The following table shows the number of shares issued for the years ended September 30, 2007, 2006 and 2005:
 
                         
    For the Year Ended September 30  
    2007     2006     2005  
 
Shares issued:
                       
Direct stock purchase plan
    325,338       387,833       450,212  
Retirement savings plan
    422,646       442,635       441,350  
1998 Long-term incentive plan
    511,584       366,905       745,788  
Long-term stock plan for Mid-States Division
          300        
Outside directors stock-for-fee plan
    2,453       2,442       2,341  
December 2006 Offering
    6,325,000              
October 2004 Offering
                16,100,000  
                         
Total shares issued
    7,587,021       1,200,115       17,739,691  
                         
 
Credit Facilities
 
As of September 30, 2007, we had a total of approximately $1.5 billion of credit facilities, comprised of three short-term committed credit facilities totaling $918 million, one uncommitted credit facility totaling $25 million and, through AEM, a second uncommitted credit facility that can provide up to $580 million. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the banks. 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, 2007, the amount available to us under our credit facilities, net of outstanding letters of credit, was $908.8 million. We believe these credit facilities, combined with our operating cash flows will be sufficient to fund our working capital needs. These facilities are described in further detail in Note 6 to the consolidated financial statements.
 
Shelf Registration
 
On December 4, 2006, we filed a registration statement with the SEC to issue, from time to time, up to $900 million in common stock and/or debt securities available for issuance, including approximately $401.5 million of capacity carried over from our prior shelf registration statement filed with the SEC in August 2004.
 
In December 2006, we sold approximately 6.3 million shares of common stock in an equity offering under the registration statement and used the net proceeds to reduce short-term debt. In June 2007, we issued $250 million of 6.35% Senior Notes due 2017 in a debt offering under the registration statement. The net proceeds of approximately $247 million, together with $53 million of available cash, were used to repay our $300 million unsecured floating rate senior notes in July 2007.
 
After these issuances, we have approximately $450 million of availability remaining under the registration statement. However, due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $100 million of equity securities, $50 million of senior debt securities and $300 million of subordinated debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard &


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Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until an investment grade rating from all three credit rating agencies was achieved.
 
Credit Ratings
 
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 risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
 
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Services, Inc. (Moody’s) and Fitch Ratings, Ltd. (Fitch). Our current debt ratings are all considered investment grade and are as follows:
 
             
    S&P   Moody’s   Fitch
 
Unsecured senior long-term debt
  BBB   Baa3   BBB+
Commercial paper
  A-2   P-3   F-2
 
Currently, with respect to our unsecured senior long-term debt, Moody’s and Fitch maintain their stable outlook and S&P maintains its positive outlook. None of our ratings is currently under review.
 
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s 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
 
We were in compliance with all of our debt covenants as of September 30, 2007. Our debt covenants are described in Note 6 to the consolidated financial statements.
 
Capitalization
 
The following table presents our capitalization as of September 30, 2007 and 2006:
 
                                 
    September 30  
    2007     2006  
    (In thousands, except percentages)  
 
Short-term debt
  $ 150,599       3.5 %   $ 382,416       9.1 %
Long-term debt
    2,130,146       50.2 %     2,183,548       51.8 %
Shareholders’ equity
    1,965,754       46.3 %     1,648,098       39.1 %
                                 
Total capitalization, including short-term debt
  $ 4,246,499       100.0 %   $ 4,214,062       100.0 %
                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 53.7 percent and 60.9 percent at September 30, 2007 and 2006. The decrease in the debt to capitalization ratio primarily reflects the favorable impact of our December 2006 equity offering and the reduction in short-term and long-term debt as of September 30, 2007. Our ratio of total debt to capitalization is typically greater during the winter heating season as we make additional short-term borrowings to fund natural gas purchases and meet our working capital requirements. We intend to maintain our capitalization ratio in a target range of 50 to 55 percent


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through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.
 
Contractual Obligations and Commercial Commitments
 
The following table provides information about contractual obligations and commercial commitments at September 30, 2007.
 
                                         
    Payments Due by Period  
          Less Than
                More Than
 
    Total     1 Year     1-3 Years     3-5 Years     5 Years  
    (In thousands)  
 
Contractual Obligations
                                       
Long-term debt(1)
  $ 2,133,693     $ 3,831     $ 403,416     $ 365,065     $ 1,361,381  
Short-term debt(1)
    150,599       150,599                    
Interest charges(2)
    1,060,034       119,628       223,250       169,198       547,958  
Gas purchase commitments(3)
    729,380       430,416       266,951       19,092       12,921  
Capital lease obligations(4)
    2,344       362       602       372       1,008  
Operating leases(4)
    171,405       16,923       30,957       28,247       95,278  
Demand fees for contracted storage(5)
    20,811       13,823       6,642       346        
Demand fees for contracted transportation(6)
    27,705       4,265       7,009       6,968       9,463  
Derivative obligations(7)
    21,629       21,339       290              
Postretirement benefit plan contributions(8)
    145,562       12,006       20,195       25,531       87,830  
                                         
Total contractual obligations
  $ 4,463,162     $ 773,192     $ 959,312     $ 614,819     $ 2,115,839  
                                         
 
 
(1) See Note 6 to the consolidated financial statements.
 
(2) Interest charges were calculated using the stated rate for each debt issuance.
 
(3) Gas purchase commitments were determined based upon contractually determined volumes at prices estimated based upon the index specified in the contract, adjusted for estimated basis differentials and contractual discounts as of September 30, 2007.
 
(4) See Note 14 to the consolidated financial statements.
 
(5) Represents third party contractual demand fees for contracted storage in our natural gas marketing and pipeline, storage and other segments. Contractual demand fees for contracted storage for our natural gas distribution segment are excluded as these costs are fully recoverable through our purchase gas adjustment mechanisms.
 
(6) Represents third party contractual demand fees for transportation in our natural gas marketing segment.
 
(7) Represents liabilities for natural gas commodity derivative contracts that were valued as of September 30, 2007. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the derivative contracts are settled.
 
(8) Represents expected contributions to our postretirement benefit plans.
 
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, 2007, AEM was committed to purchase 80.4 Bcf within one year, 38.1 Bcf within one to three years and 1.4 Bcf after three years under indexed contracts. AEM was committed to purchase 2.4 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $5.69 to $9.85 per Mcf.
 
With the exception of our Mid-Tex Division, our natural gas distribution 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


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terms of the individual contract. Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market prices. The estimated commitments under these contract terms as of September 30, 2007 are reflected in the table above.
 
Risk Management Activities
 
We conduct risk management activities through our natural gas distribution, natural gas marketing and pipeline, storage and other segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. In our natural gas marketing and pipeline, storage and other segments, 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. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the derivatives being treated as mark to market instruments through earnings.
 
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 natural gas distribution and natural gas marketing derivative contract activities for the year ended September 30, 2007 (in thousands):
 
                 
    Natural Gas
    Natural Gas
 
    Distribution     Marketing  
 
Fair value of contracts at September 30, 2006
  $ (27,209 )   $ 15,003  
Contracts realized/settled
    (27,824 )     (9,215 )
Fair value of new contracts
    (8,883 )      
Other changes in value
    42,863       21,020  
                 
Fair value of contracts at September 30, 2007
  $ (21,053 )   $ 26,808  
                 
 
The fair value of our natural gas distribution and natural gas marketing derivative contracts at September 30, 2007, is segregated below by time period and fair value source.
 
                                         
    Fair Value of Contracts at September 30, 2007  
    Maturity in Years        
    Less
                Greater
    Total Fair
 
Source of Fair Value
  Than 1     1-3     4-5     Than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ 1,304     $ 6,072     $     $     $ 7,376  
Prices based on models and other valuation methods
    (794 )     (827 )                 (1,621 )
                                         
Total Fair Value
  $ 510     $ 5,245     $     $     $ 5,755  
                                         
 
Pension and Postretirement Benefits Obligations
 
Net Periodic Pension and Postretirement Benefit Costs
 
For the fiscal year ended September 30, 2007, our total net periodic pension and other benefits costs was $48.6 million, compared with $50.0 million and $36.4 million for the years ended September 30, 2006 and 2005. These costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.


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The decrease in total net periodic pension and other benefits cost during fiscal 2007 compared with fiscal 2006 primarily reflects changes in assumptions we made during our annual pension plan valuation completed June 30, 2006. The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. In the period leading up to our June 30, 2006 measurement date, these interest rates were increasing, which resulted in a 130 basis point increase in our discount rate used to determine our fiscal 2007 net periodic and post-retirement cost to 6.30 percent. This increase had the effect of decreasing the present value of our plan liabilities and associated expenses. This favorable impact was partially offset by the unfavorable impact of reducing the expected return on our pension plan assets by 25 basis points to 8.25 percent, which has the effect of increasing our pension and postretirement benefit cost.
 
The increase in total net periodic pension and other benefits cost during fiscal 2006 compared with the prior year primarily reflects changes in assumptions we made during our annual pension plan valuation completed June 30, 2005. The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. In the period leading up to our June 30, 2005 measurement date, these interest rates were declining, which resulted in a 125 basis point reduction in our discount rate to 5.0 percent. This reduction increased the present value of our plan liabilities and associated expenses. Additionally, we reduced the expected return on our pension plan assets by 25 basis points to 8.5 percent, which also increased our pension and postretirement benefit cost.
 
Pension and Postretirement Plan Funding
 
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.
 
During fiscal 2007, we did not contribute to our pension plans. During fiscal 2006, we voluntarily contributed $2.9 million to the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. That contribution achieved a desired level of funding by satisfying the minimum funding requirements while maximizing the tax deductible contribution for this plan for plan year 2005. During fiscal 2005, we voluntarily contributed $3.0 million to the Master Trust to maintain the level of funding we desire relative to our accumulated benefit obligation. We made the contribution because declining high yield corporate bond yields in the period leading up to our June 30, 2005 measurement date resulted in an increase in the present value of our plan liabilities.
 
We contributed $11.8 million, $10.9 million and $10.0 million to our postretirement benefits plans for the years ended September 30, 2007, 2006 and 2005. The contributions represent the portion of the postretirement costs we are responsible for under the terms of our plan and minimum funding required by state regulatory commissions.
 
Outlook for Fiscal 2008
 
Market conditions as of the June 30, 2007 valuation date were similar to market conditions as of our June 30, 2006 measurement date, Therefore, we maintained the discount rate for determining our fiscal 2008 pension and benefit costs at 6.3 percent and the expected return on our pension plan assets at 8.25 percent. Accordingly, we expect our fiscal 2008 pension and postretirement medical costs to be materially the same as fiscal 2007.
 
We are not required to make a minimum funding contribution to our pension plans during fiscal 2008; nor, at this time, do we intend to make voluntary contributions during 2008. However, we anticipate contributing approximately $12 million to our postretirement medical plans during fiscal 2008.
 
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


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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.
 
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.
 
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 activities.
 
We conduct risk management activities through both our natural gas distribution and natural gas marketing segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to protect us and our customers against unusually large winter period gas price increases. 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 and our other short-term borrowings.
 
Commodity Price Risk
 
Natural gas distribution segment
 
We purchase natural gas for our natural gas distribution operations. Substantially all of the costs of gas purchased for natural gas distribution operations are recovered from our customers through purchased gas adjustment mechanisms. However, our natural gas distribution operations have commodity price risk exposure to fluctuations in spot natural gas prices related to purchases for sales to our nonregulated energy services customers at fixed prices.
 
For our natural gas distribution 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 costs related to fixed-price nonregulated sales. Based on these projected nonregulated gas sales, a hypothetical 10 percent increase in fixed prices based upon the September 30, 2007 three month market strip, would increase our purchased gas cost by approximately $0.5 million in fiscal 2008.
 
Natural gas marketing and pipeline, storage and other segments
 
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 and related financial contracts) at the end of each period. Based on AEH’s net open position (including existing storage and related financial contracts) at September 30, 2007 of 0.2 Bcf, a $0.50 change in the forward NYMEX price would have had a $0.1 million impact on our consolidated net income.
 
Changes in the difference between the indices used to mark to market our physical inventory (Gas Daily) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income; but, over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges. Based upon our net physical position at September 30, 2007 and assuming our hedges would still


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qualify as highly effective, a $0.50 change in the difference between the Gas Daily and NYMEX indices would impact our reported net income by approximately $4.3 million.
 
Additionally, these changes could cause us to recognize a risk management liability, which would require us to place cash into an escrow account to collateralize this liability position. This, in turn, would reduce the amount of cash we would have on hand to fund our working capital needs.
 
Interest Rate Risk
 
Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. 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 one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings increased by an average of one percent, our interest expense would have increased by approximately $2.7 million during 2007.
 
We also assess market risk for our fixed rate long-term obligations. We estimate market risk for our 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 long-term obligations would have increased by approximately $156.3 million.
 
As of September 30, 2007, we were not engaged in other activities that would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates or market commodity prices.


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ITEM 8.   Financial Statements and Supplementary Data
 
Index to financial statements and financial statement schedule:
 
         
    Page
 
    63  
Financial statements and supplementary data:
       
    64  
    65