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Atmos Energy 10-K 2009
e10vk
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
     
(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, 2009
    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
 
     
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).*  Yes o     No o
 
* The registrant has not been phased into the interactive data requirements.
 
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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
 
(Do not check if a smaller reporting company)
 
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, 2009, was $2,072,764,690.
 
As of November 8, 2009, the registrant had 92,599,896 shares of common stock outstanding.
 
 
Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 3, 2010 are incorporated by reference into Part III of this report.
 


 

 
 
                 
        Page
 
    3  
 
      Business     4  
      Risk Factors     22  
      Unresolved Staff Comments     27  
      Properties     27  
      Legal Proceedings     29  
      Submission of Matters to a Vote of Security Holders     29  
 
Part II
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     31  
      Selected Financial Data     34  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     35  
      Quantitative and Qualitative Disclosures About Market Risk     63  
      Financial Statements and Supplementary Data     65  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     128  
      Controls and Procedures     128  
      Other Information     130  
 
Part III
      Directors, Executive Officers and Corporate Governance     130  
      Executive Compensation     130  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     130  
      Certain Relationships and Related Transactions, and Director Independence     130  
      Principal Accountant Fees and Services     130  
 
Part IV
      Exhibits and Financial Statement Schedules     131  
 EX-10.4(B)
 EX-12
 EX-21
 EX-23.1
 EX-31
 EX-32


Table of Contents

 
 
     
AEC
 
Atmos Energy Corporation
AEH
 
Atmos Energy Holdings, Inc.
AEM
 
Atmos Energy Marketing, LLC
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
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
Fitch
 
Fitch Ratings, Ltd.
GRIP
 
Gas Reliability Infrastructure Program
GSRS
 
Gas System Reliability Surcharge
ISRS
 
Infrastructure System Replacement Surcharge
KPSC
 
Kentucky 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.
NYMEX
 
New York Mercantile Exchange, Inc.
NYSE
 
New York Stock Exchange
RRC
 
Railroad Commission of Texas
RRM
 
Rate Review Mechanism
RSC
 
Rate Stabilization Clause
S&P
 
Standard & Poor’s Corporation
SEC
 
United States Securities and Exchange Commission
Settled Cities
 
Represents 438 of the 439 incorporated cities, or approximately 80 percent of the Mid-Tex Division’s customers, with whom a settlement agreement was reached during the fiscal 2008 second quarter.
SRF
 
Stable Rate Filing
TXU Gas
 
TXU Gas Company, which was acquired on October 1, 2004
WNA
 
Weather Normalization Adjustment


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The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.
 
ITEM 1.   Business.
 
 
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. Since our incorporation in Texas in 1983, we have grown primarily through a series of acquisitions, the most recent of which was the acquisition in October 2004 of the natural gas distribution and pipeline operations of TXU Gas Company. We are also incorporated in the state of Virginia.
 
Today, we distribute natural gas through regulated sales and transportation arrangements to over 3 million residential, commercial, public authority and industrial customers in 12 states located primarily in the South, which makes us one of the country’s largest natural-gas-only distributors based on number of customers. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.
 
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation along with storage services to certain of our natural gas distribution divisions and third parties.
 
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.
 
We have experienced more than 25 consecutive years of increasing dividends and earnings growth after giving effect to our acquisitions. Historically, we achieved this record of growth through acquisitions while efficiently managing our operating and maintenance expenses and leveraging our technology to achieve more efficient operations. In recent years, we have also achieved growth by implementing rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved margins from customer usage patterns. In addition, we have developed various commercial opportunities within our regulated transmission and storage operations. Finally, we have strengthened our nonregulated businesses by increasing sales volumes and improving per-unit margins.
 
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.
 
 
We operate the Company through the following four segments:
 
  •  The natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations.
 
  •  The regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division.
 
  •  The natural gas marketing segment, which includes a variety of nonregulated natural gas management services.


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  •  The pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.
 
These operating segments are described in greater detail below.
 
Natural Gas Distribution Segment Overview
 
Our natural gas distribution segment consists of the following six regulated divisions, presented in order of total customers served, covering service areas in 12 states:
 
  •  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.
 
Revenues in this operating segment are established by regulatory authorities in the states in which we operate. These rates are intended to be sufficient to cover the costs of conducting business and to provide a reasonable return on invested capital. 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.
 
Rates established by regulatory authorities often include cost adjustment mechanisms for costs that (i) are subject to significant price fluctuations compared to our other costs, (ii) represent a large component of our cost of service and (iii) are generally outside our control.
 
Purchased gas cost mechanisms represent a common form of cost adjustment mechanism. Purchased gas cost adjustment mechanisms provide natural 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 instruments to lock in gas costs. Under the performance-based ratemaking adjustment, purchased gas costs savings are shared between the utility and its customers.
 
Finally, regulatory authorities have approved weather normalization adjustments (WNA) for over 90 percent of residential and commercial meters in our service areas as a part of our rates. WNA minimizes the effect of weather that is above or below normal by allowing 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, 2009 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
 
Financial results for this segment are affected by the cost of natural gas and economic conditions in the areas that we serve. As discussed above, we are generally able to pass the cost of gas through to our customers under purchased gas adjustment clauses; therefore, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs may cause customers to conserve or, in the case of industrial customers, to use alternative energy sources. Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense.
 
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 consist of both base load and swing supply (peaking) quantities and are contracted from our suppliers on a firm basis with various terms at market prices. 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 39 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 2009 were Anadarko Energy Services, Chesapeake Energy Marketing, Inc., ConocoPhillips Company, Devon Gas Services, L.P., Enbridge Marketing (US) L.P., Iberdrola Renewables, Inc., 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 2009 was on January 15, 2009, when sales to customers reached approximately 3.1 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 regulations or statutes. 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


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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 September 30, 2009, we held 1,111 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 incorporated and unincorporated communities in the north-central, eastern and western parts of Texas, including the Dallas/Fort Worth Metroplex. 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.
 
Prior to fiscal 2008, this division operated under one system-wide rate structure. However, in 2008, we reached a settlement with cities representing approximately 80 percent of this division’s customers (Settled Cities) that has allowed us, beginning in 2008, to update rates for customers in these cities through an annual rate review mechanism. Rates for the remaining 20 percent of this division’s customers, primarily the City of Dallas, continue to be updated through periodic formal rate proceedings and filings made under Texas’ Gas Reliability Infrastructure Program (GRIP). GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we 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, and other suburban areas of 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 rate stabilization clause 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, with the RRC having exclusive appellate jurisdiction over the municipalities and exclusive original jurisdiction over rates and services provided to customers not located within the limits of a municipality. Prior to fiscal 2008, rates were updated in this division through formal rate proceedings. However, the West Texas Division entered into agreements with its West Texas service areas during 2008 and its Amarillo and Lubbock service area during 2009 to update rates for customers in these service areas through an annual rate review mechanism.
 
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.


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Atmos Energy Colorado-Kansas Division.  Our Colorado-Kansas Division serves approximately 170 communities throughout Colorado and Kansas and parts of Missouri, including the cities of Olathe, Kansas, a suburb of Kansas City and Greeley, Colorado, located near Denver. We update our rates in this division through periodic formal rate filings made with each state’s public service commission.
 
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/GRIP Action     (thousands)(1)   Return(1)   Equity(1)
 
Atmos Pipeline — Texas
  Texas     5/24/04     $417,111   8.258%   10.00%
Atmos Pipeline —
Texas — GRIP
  Texas     4/28/09     755,038   8.258%   10.00%
Colorado-Kansas
  Colorado     10/1/07     81,208   8.45%   11.25%
    Kansas     5/12/08     (2)   (2)   (2)
Kentucky/Mid-States
  Georgia     9/22/08     66,893   7.75%   10.70%
    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     4/1/09     190,100   8.24%   10.30%
    Virginia     9/30/08     33,194   8.46% - 8.96%   9.50% - 10.50%
Louisiana
  Trans LA     4/1/09     96,570   (2)   10.00% - 10.80%
    LGS     7/1/09     236,600   (2)   10.40%
Mid-Tex — Settled Cities
  Texas     8/1/09     1,262,969(3)   7.78%   9.60%
Mid-Tex — Dallas & Environs
  Texas     6/24/08     1,127,924(3)   7.98%   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     8/1/09     124,401   (2)   9.60%
 


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            Bad
          Performance-
       
        Authorized Debt/
  Debt
          Based Rate
    Customer
 
Division   Jurisdiction   Equity Ratio   Rider(4)     WNA     Program(5)     Meters  
 
Atmos Pipeline — Texas
  Texas   50/50     No       N/A       N/A       N/A  
Colorado-Kansas
  Colorado   54/46     No (7)     No       No       111,382  
    Kansas   (2)     Yes       Yes       No       129,983  
Kentucky/Mid-States
  Georgia   55/45     No       Yes       Yes       65,080  
    Illinois   67/33     No       No       No       22,623  
    Iowa   57/43     No       No       No       4,344  
    Kentucky   (2)     No (7)     Yes       Yes       175,789  
    Missouri   (2)     No       No (6)     No       57,332  
    Tennessee   52/48     Yes       Yes       Yes       132,764  
    Virginia   55/45     Yes       Yes       No       23,182  
Louisiana
  Trans LA   52/48     No       Yes       No       78,345  
    LGS   52/48     No       Yes       No       277,648  
Mid-Tex — Settled Cities
  Texas   52/48     Yes       Yes       No       1,227,598  
Mid-Tex — Dallas & Environs
  Texas   52/48     Yes       Yes       No       306,899  
Mississippi
  Mississippi   47/53     No (7)     Yes       No       266,785  
West Texas
  Amarillo   50/50     Yes       Yes       No       69,836  
    Lubbock   50/50     Yes       Yes       No       73,642  
    West Texas   52/48     Yes       Yes       No       155,612  
 
 
(1) The rate base, authorized rate of return and authorized return on equity presented in this table are those from the last rate case or GRIP filing 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.
 
(3) The Mid-Tex Rate Base amounts for the Settled Cities and Dallas and Environs both represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base. The difference in rate base amounts is due to two separate test filing periods covered.
 
(4) The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.
 
(5) 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 costs savings.
 
(6) The Missouri jurisdiction has a straight-fixed variable rate design which decouples gross profit margin from customer usage patterns.
 
(7) The Company has pending requests in Colorado, Kentucky and Mississippi to move bad debt cost to the gas cost recovery mechanism. A hearing regarding the Mississippi request was held on September 1, 2009.

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Natural Gas Distribution Sales and Statistical Data
 
                                         
    Fiscal Year Ended September 30  
    2009     2008     2007     2006     2005  
 
METERS IN SERVICE, end of year
                                       
Residential
    2,901,577       2,911,475       2,893,543       2,886,042       2,862,822  
Commercial
    265,843       268,845       272,081       275,577       274,536  
Industrial
    2,193       2,241       2,339       2,661       2,715  
Public authority and other
    9,231       9,218       19,164       16,919       17,767  
                                         
Total meters
    3,178,844       3,191,779       3,187,127       3,181,199       3,157,840  
                                         
INVENTORY STORAGE BALANCE — Bcf
    57.0       58.3       58.0       59.9       54.7  
                                         
HEATING DEGREE DAYS(1)
                                       
Actual (weighted average)
    2,713       2,820       2,879       2,527       2,587  
Percent of normal
    100 %     100 %     100 %     87 %     89 %
SALES VOLUMES — MMcf(2)
                                       
Gas Sales Volumes
                                       
Residential
    159,762       163,229       166,612       144,780       162,016  
Commercial
    91,379       93,953       95,514       87,006       92,401  
Industrial
    18,563       21,734       22,914       26,161       29,434  
Public authority and other
    12,413       13,760       12,287       14,086       12,432  
                                         
Total gas sales volumes
    282,117       292,676       297,327       272,033       296,283  
Transportation volumes
    130,691       141,083       135,109       126,960       122,098  
                                         
Total throughput
    412,808       433,759       432,436       398,993       418,381  
                                         
OPERATING REVENUES (000’s)(2)
                                       
Gas Sales Revenues
                                       
Residential
  $ 1,830,140     $ 2,131,447     $ 1,982,801     $ 2,068,736     $ 1,791,172  
Commercial
    838,184       1,077,056       970,949       1,061,783       869,722  
Industrial
    135,633       212,531       195,060       276,186       229,649  
Public authority and other
    89,183       137,821       114,298       144,600       114,742  
                                         
Total gas sales revenues
    2,893,140       3,558,855       3,263,108       3,551,305       3,005,285  
Transportation revenues
    59,914       60,504       59,813       62,215       59,996  
Other gas revenues
    31,711       35,771       35,844       37,071       37,859  
                                         
Total operating revenues
  $ 2,984,765     $ 3,655,130     $ 3,358,765     $ 3,650,591     $ 3,103,140  
                                         
Average transportation revenue per Mcf
  $ 0.46     $ 0.43     $ 0.44     $ 0.49     $ 0.49  
Average cost of gas per Mcf sold
  $ 6.95     $ 9.05     $ 8.09     $ 10.02     $ 7.41  
Employees
    4,691       4,558       4,472       4,402       4,327  
 
See footnotes following these tables.


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Natural Gas Distribution Sales and Statistical Data By Division
 
                                                                 
    Fiscal Year Ended September 30, 2009  
          Kentucky/
          West
          Colorado-
             
    Mid-Tex     Mid-States     Louisiana     Texas     Mississippi     Kansas     Other(3)     Total  
 
METERS IN SERVICE
                                                               
Residential
    1,417,869       423,829       333,224       270,757       237,289       218,609             2,901,577  
Commercial
    116,480       53,386       22,769       24,986       26,142       22,080             265,843  
Industrial
    148       909             508       532       96             2,193  
Public authority and other
          2,555             2,839       2,822       1,015             9,231  
                                                                 
Total
    1,534,497       480,679       355,993       299,090       266,785       241,800             3,178,844  
                                                                 
HEATING DEGREE DAYS(1)
                                                               
Actual
    2,036       3,853       1,574       3,553       2,746       5,520             2,713  
Percent of normal
    100 %     98 %     101 %     99 %     103 %     100 %           100 %
SALES VOLUMES — MMcf(2)
                                                               
Gas Sales Volumes
                                                               
Residential
    73,678       26,589       12,371       16,341       13,503       17,280             159,762  
Commercial
    48,363       16,049       6,771       6,780       6,568       6,848             91,379  
Industrial
    2,918       6,217             3,528       5,704       196             18,563  
Public authority and other
          1,434             6,014       2,901       2,064             12,413  
                                                                 
Total
    124,959       50,289       19,142       32,663       28,676       26,388             282,117  
Transportation volumes
    44,991       41,693       5,151       23,417       4,968       10,471             130,691  
                                                                 
Total throughput
    169,950       91,982       24,293       56,080       33,644       36,859             412,808  
                                                                 
OPERATING MARGIN (000’s)(2)
  $ 483,155     $ 163,602     $ 118,021     $ 89,982     $ 91,680     $ 78,188     $     $ 1,024,628  
OPERATING EXPENSES (000’s)(2)
                                                               
Operation and maintenance
  $ 150,978     $ 68,823     $ 41,956     $ 35,126     $ 43,642     $ 32,935     $ (4,031 )   $ 369,429  
Depreciation and amortization
  $ 94,040     $ 32,755     $ 22,492     $ 15,242     $ 12,411     $ 15,334     $     $ 192,274  
Taxes, other than income
  $ 108,412     $ 13,261     $ 9,629     $ 15,863     $ 13,925     $ 8,222     $     $ 169,312  
Asset impairments
  $ 2,100     $ 785     $ 510     $ 413     $ 415     $ 376     $     $ 4,599  
OPERATING INCOME (000’s)(2)
  $ 127,625     $ 47,978     $ 43,434     $ 23,338     $ 21,287     $ 21,321     $ 4,031     $ 289,014  
CAPITAL EXPENDITURES (000’s)
  $ 173,201     $ 57,943     $ 42,626     $ 33,960     $ 22,173     $ 24,726     $ 24,871     $ 379,500  
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)
  $ 1,615,900     $ 722,530     $ 390,957     $ 299,242     $ 266,053     $ 284,398     $ 124,391     $ 3,703,471  
OTHER STATISTICS, at year end
                                                               
Miles of pipe
    28,996       12,158       8,321       7,702       6,540       7,162             70,879  
Employees
    1,585       605       446       352       389       290       1,024       4,691  
 
See footnotes following these tables.
 


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    Fiscal Year Ended September 30, 2008  
          Kentucky/
          West
          Colorado-
             
    Mid-Tex     Mid-States     Louisiana     Texas     Mississippi     Kansas     Other(3)     Total  
 
METERS IN SERVICE
                                                               
Residential
    1,414,543       431,880       336,211       270,990       240,113       217,738             2,911,475  
Commercial
    117,022       54,538       23,059       25,226       27,219       21,781             268,845  
Industrial
    163       930             497       562       89             2,241  
Public authority and other
          2,563             2,888       2,822       945             9,218  
                                                                 
Total
    1,531,728       489,911       359,270       299,601       270,716       240,553             3,191,779  
                                                                 
HEATING DEGREE DAYS(1)
                                                               
Actual
    2,213       3,799       1,531       3,546       2,741       5,861             2,820  
Percent of normal
    99 %     96 %     99 %     99 %     101 %     105 %           100 %
SALES VOLUMES — MMcf(2)
                                                               
Gas Sales Volumes
                                                               
Residential
    76,296       26,009       12,475       17,190       12,882       18,377             163,229  
Commercial
    50,348       15,731       6,858       7,162       6,590       7,264             93,953  
Industrial
    3,293       7,740             3,876       6,580       245             21,734  
Public authority and other
          1,419             6,933       3,013       2,395             13,760  
                                                                 
Total
    129,937       50,899       19,333       35,161       29,065       28,281             292,676  
Transportation volumes
    49,606       44,796       6,136       26,411       4,219       9,915             141,083  
                                                                 
Total throughput
    179,543       95,695       25,469       61,572       33,284       38,196             433,759  
                                                                 
OPERATING MARGIN (000’s)(2)
  $ 478,622     $ 159,265     $ 110,754     $ 87,344     $ 91,749     $ 78,332     $     $ 1,006,066  
OPERATING EXPENSES (000’s)(2)
                                                               
Operation and maintenance
  $ 167,497     $ 65,161     $ 42,367     $ 36,688     $ 46,024     $ 35,414     $ (3,907 )   $ 389,244  
Depreciation and amortization
  $ 84,202     $ 30,574     $ 21,193     $ 14,781     $ 11,752     $ 14,703     $     $ 177,205  
Taxes, other than income
  $ 111,914     $ 14,799     $ 8,104     $ 22,032     $ 14,003     $ 7,600     $     $ 178,452  
OPERATING INCOME (000’s)(2)
  $ 115,009     $ 48,731     $ 39,090     $ 13,843     $ 19,970     $ 20,615     $ 3,907     $ 261,165  
CAPITAL EXPENDITURES (000’s)
  $ 178,409     $ 59,274     $ 46,674     $ 34,354     $ 22,590     $ 20,331     $ 24,910     $ 386,542  
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)
  $ 1,491,188     $ 689,109     $ 370,751     $ 278,326     $ 254,452     $ 272,121     $ 127,609     $ 3,483,556  
OTHER STATISTICS, at year end
                                                               
Miles of pipe
    28,697       12,104       8,277       14,697       6,537       7,150             77,462  
Employees
    1,506       635       427       342       393       281       974       4,558  
 
 
Notes to preceding tables:
 
(1) A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The 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.
 
(2) Sales volumes, revenues, operating margins, operating expense and operating income reflect segment operations, including intercompany sales and transportation amounts.
 
(3) The Other column represents our shared services function, which provides administrative and other support to the Company. Certain costs incurred by this function are not allocated.
 
 
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division. This 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.

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Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands. Gross profit earned from our Mid-Tex Division and through certain other transportation and storage services is subject to traditional ratemaking governed by the RRC. However, Atmos Pipeline — Texas’ existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates with minimal regulation.
 
These operations include 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.
 
 
                                         
    Fiscal Year Ended September 30  
    2009     2008     2007     2006     2005  
 
CUSTOMERS, end of year
                                       
Industrial
    68       62       65       67       66  
Other
    168       189       196       178       191  
                                         
Total
    236       251       261       245       257  
                                         
PIPELINE TRANSPORTATION VOLUMES — MMcf(1)
    706,132       782,876       699,006       581,272       554,452  
OPERATING REVENUES (000’s)(1)
  $ 209,658     $ 195,917     $ 163,229     $ 141,133     $ 142,952  
Employees, at year end
    62       60       54       85       78  
 
 
(1) Transportation volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
 
Our natural gas marketing activities are conducted through Atmos Energy Marketing (AEM), which is wholly-owned by Atmos Energy Holdings, Inc. (AEH). AEH is a wholly-owned subsidiary of AEC and operates primarily in the Midwest and Southeast areas of the United States.
 
AEM’s primary business is to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. In addition, AEM utilizes proprietary and customer-owned transportation and storage assets to provide 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 financial instruments. AEM serves most of its customers under contracts generally having one to two year terms and sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms ranging from 30 days to two years. As a result, AEM’s margins arise from the types of commercial transactions we have structured with our customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.
 
AEM also seeks to maximize, through asset optimization activities, the economic value associated with the storage and transportation capacity we own or control in our natural gas distribution and natural gas marketing segments. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEM has access and selling financial instruments at advantageous prices to lock in a gross profit margin.


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    Fiscal Year Ended September 30  
    2009     2008     2007     2006     2005  
 
CUSTOMERS, end of year
                                       
Industrial
    631       624       677       679       559  
Municipal
    63       55       68       73       69  
Other
    321       312       281       289       211  
                                         
Total
    1,015       991       1,026       1,041       839  
                                         
INVENTORY STORAGE BALANCE — Bcf
    17.0       11.0       19.3       15.3       8.2  
NATURAL GAS MARKETING SALES VOLUMES — MMcf(1)
    441,081       457,952       423,895       336,516       273,201  
OPERATING REVENUES (000’s)(1)
  $ 2,336,847     $ 4,287,862     $ 3,151,330     $ 3,156,524     $ 2,106,278  
 
 
(1) Sales volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
 
Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. APS is engaged in nonregulated transmission, storage and natural gas gathering services. Its primary asset is a proprietary 21 mile pipeline located in New Orleans, Louisiana. It also owns or controls additional pipeline and storage capacity including interests in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for pipeline capacity to meet customer demand during peak periods.
 
APS’ primary business is to provide storage and transportation services to our Louisiana and Kentucky/MidStates regulated natural gas distribution divisions, to our natural gas marketing segment and, on a more limited basis, to third parties. APS earns transportation fees and storage demand charges to aggregate and provide gas supply, provide access to storage capacity and transport gas for these customers.
 
APS also engages in various asset optimization activities. APS’ primary asset optimization activity involves the administration of two asset management plans with regulated affiliates of the Company. These arrangements provide APS the opportunity to maximize the economic value associated with the transportation and storage capacity assigned to these plans. APS attempts to meet this objective through a variety of activities including engaging in natural gas storage transactions and utilizing excess asset capacity to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. These plans require APS to share a portion of the economic value created by these activities with the regulated customers served by these affiliates. These arrangements have been approved by applicable state regulatory commissions and are subject to annual regulatory review intended to ensure proper allocation of economic value between our regulated customers and APS.
 
APS also seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which APS has access and, in transactions involving storage capacity, selling financial instruments at advantageous prices to lock in a gross profit margin.


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    Fiscal Year Ended September 30
    2009   2008   2007   2006   2005
 
OPERATING REVENUES (000’s)(1)
  $ 41,924     $ 31,709     $ 33,400     $ 25,574     $ 15,639  
PIPELINE TRANSPORTATION VOLUMES — MMcf(1)
    6,395       5,492       7,710       9,712       7,593  
INVENTORY STORAGE BALANCE — Bcf
    2.9       1.4       2.0       2.6       1.8  
 
 
(1) Transportation volumes and operating revenues reflect segment operations, including intercompany sales and transportation amounts.
 
Ratemaking Activity
 
 
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 in 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 conducting business and to provide a reasonable return on invested capital.
 
Our current rate strategy is to focus on reducing or eliminating regulatory lag, obtaining adequate returns and providing stable, predictable margins. Atmos Energy has annual ratemaking mechanisms in place in three states that provide for an annual rate review and adjustment to rates for approximately 68 percent of our customers. Additionally, we have WNA mechanisms in eight states. These mechanisms work in tandem to provide insulation from volatile margins, both for the Company and our customers.
 
We will also continue to address various rate design changes, including the recovery of bad debt gas costs, inclusion of other taxes in gas costs and stratification of rates to benefit low income households in future rate filings. These design changes would address cost variations that are related to pass-through energy costs beyond our control.
 
Although substantial progress has been made in recent years by improving rate design across Atmos’ operating area, potential changes in federal energy policy and adverse economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.


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Substantially all of our natural gas distribution revenues in the fiscal years ended September 30, 2009, 2008 and 2007 were derived from sales at rates set by or subject to approval by local or state authorities. Annual net operating income increases resulting from ratemaking activity totaling $54.4 million, $40.6 million, and $45.2 million became effective in fiscal 2009, 2008 and 2007 as summarized below:
 
                         
    Annual Increase (Decrease) to Operating
 
    Income For the Fiscal Year Ended September 30  
Rate Action   2009     2008     2007  
    (In thousands)  
 
Rate case filings
  $ 2,959     $ 27,838     $ 7,793  
GRIP filings
    11,443       8,101       25,624  
Annual rate filing mechanisms
    38,764       3,275       12,963  
Other rate activity
    1,237       1,424       (1,132 )
                         
    $ 54,403     $ 40,638     $ 45,248  
                         
 
Additionally, the following ratemaking efforts were initiated during fiscal 2009 but had not been completed as of September 30, 2009:
 
                 
            Operating Income
 
Division   Rate Action   Jurisdiction   Requested  
            (In thousands)  
 
Mid-Tex
  Rate Case(1)   Dallas & Environs   $ 7,743  
Colorado/Kansas
  Rate Case   Colorado     3,834  
    GSRS(2)   Kansas     766  
Kentucky/Mid-States
  Rate Case(3)   Virginia     1,677  
    PRP Surcharge(4)   Georgia     909  
West Texas
  Rate Review Mechanism(5)   Lubbock     3,476  
    Rate Review Mechanism(5)   Amarillo     2,285  
Mississippi
  Stable Rate Filing   Mississippi     10,195  
                 
            $ 30,885  
                 
 
 
(1) Texas Railroad Commission Examiners issued a proposal for decision (PFD) on October 9, 2009. The PFD recommended a rate change of $3.5 million applicable to the Dallas and Environs area of the Mid-Tex system. The Company has filed exceptions to the Examiner’s proposal. A final Commission decision is expected before the end of the year.
 
(2) Gas System Reliability Surcharge (GSRS) relates to safety related investments made since the previous rate case.
 
(3) The Company filed a Rate Case with the state of Virginia requesting a $1.7 million increase. The staff has recommended an increase of $1.4 million.
 
(4) The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.
 
(5) The Company filed Rate Review Mechanisms with the City of Lubbock requesting an increase of $3.5 million and with the City of Amarillo requesting an increase of $2.3 million. Effective October 1, 2009, the respective cities have approved increases of $2.7 million and $1.3 million.
 
In October 2009, we filed rate cases in Georgia and Kentucky, requesting an increase in operating income of $3.8 million and $9.5 million.


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Our recent ratemaking activity is discussed in greater detail below.
 
 
A rate case is a formal request from Atmos Energy to a regulatory authority 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 and 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
    Effective
 
Division   State   Annual Operating Income     Date  
        (In thousands)        
 
2009 Rate Case Filings:
                   
Kentucky/Mid-States
  Tennessee   $ 2,513       4/1/09  
West Texas
  Texas     446       Various  
                     
Total 2009 Rate Case Filings
      $ 2,959          
                     
2008 Rate Case Filings:
                   
Kentucky/Mid-States
  Virginia   $ 869       9/30/08  
Kentucky/Mid-States
  Georgia     3,351       9/22/08  
Mid-Tex(1)
  Texas     5,430       6/24/08  
Colorado-Kansas
  Kansas     2,100       5/12/08  
Mid-Tex(2)
  Texas     8,000       4/1/08  
Kentucky/Mid-States
  Tennessee     8,088       11/4/07  
                     
Total 2008 Rate Case Filings
      $ 27,838          
                     
2007 Rate Case Filings:
                   
Kentucky/Mid-States
  Kentucky(3)   $ 6,200       8/1/07  
Mid-Tex
  Texas(4)     4,793       4/1/07  
Kentucky/Mid-States
  Missouri(5)     1,500       3/4/07  
Kentucky/Mid-States
  Tennessee     (4,700 )     12/15/06  
                     
Total 2007 Rate Case Filings
      $ 7,793          
                     
 
 
(1) Increase relates only to the City of Dallas and Environs areas of the Mid-Tex Division.
 
(2) Increase relates only to the Settled Cities area of the Mid-Tex Division.
 
(3) 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 operating income of $6.2 million effective August 1, 2007.
 
(4) In March 2007, the RRC issued an order, which increased the Mid-Tex Division’s annual operating income 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


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$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.
 
(5) 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 an estimated increase in operating income of $1.5 million.
 
GRIP Filings
 
As discussed above in “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 fiscal years ended September 30, 2009, 2008 and 2007:
 
                         
              Additional
     
        Incremental Net
    Annual
     
        Utility Plant
    Operating
    Effective
Division   Calendar Year   Investment     Income     Date
        (In thousands)     (In thousands)      
 
2009 GRIP:
                       
Mid-Tex(1)
  2007   $ 57,385     $ 1,837     1/26/09
West Texas(2)
  2007/08     27,425       532     Various
Atmos Pipeline — Texas
  2008     51,308       6,342     4/28/09
Mid-Tex(3)
  2008     105,777       2,732     9/9/09
                         
Total 2009 GRIP
      $ 241,895     $ 11,443      
                         
2008 GRIP:
                       
Atmos Pipeline — Texas
  2007   $ 46,648     $ 6,970     4/15/08
West Texas
  2006     7,022       1,131     12/17/07
                         
Total 2008 GRIP
      $ 53,670     $ 8,101      
                         
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      
                         
 
 
(1) Increase relates to the City of Dallas and Environs areas of the Mid-Tex Division.
 
(2) The West Texas Division files GRIP applications related only to the Lubbock Environs and the West Texas Cities Environs. GRIP implemented for this division include investments that related to both calendar years 2007 and 2008. The incremental investment is based on system-wide plant and additional annual operating income is applicable to Environs customers only.
 
(3) Increase relates only to the City of Dallas area of the Mid-Tex Division.
 
Annual Rate Filing Mechanisms
 
As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. As discussed above in “Natural Gas Distribution Segment Overview,” we currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in significant portions of our Mid-Tex and West Texas divisions. These mechanisms are referred to as rate review mechanisms in our Mid-Tex and West Texas


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divisions, stable rate filings in the Mississippi Division and rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms:
 
                             
              Additional
       
              Annual
       
              Operating
    Effective
 
Division   Jurisdiction   Test Year Ended     Income     Date  
              (In thousands)        
 
2009 Filings:
                           
Louisiana
  LGS     12/31/08     $ 3,307       7/1/09  
Louisiana
  Transla     9/30/08       611       4/1/09  
Mississippi
  Mississippi     6/30/08             N/A  
Mid-Tex
  Settled Cities     12/31/07       21,800       11/8/08  
Mid-Tex
  Settled Cities     12/31/08       1,979       8/1/09  
West Texas
  WT Cities     12/31/07       4,468       11/20/08  
West Texas
  WT Cities     12/31/08       6,599       8/1/09  
                             
Total 2009 Filings
              $ 38,764          
                             
2008 Filings:
                           
Louisiana
  LGS     12/31/07     $ 1,709       7/1/08  
Louisiana
  Transla     9/30/07       1,566       4/1/08  
                             
Total 2008 Filings
              $ 3,275          
                             
2007 Filings:
                           
Mississippi
  Mississippi     6/30/07     $       11/1/07  
Louisiana
  LGS     12/31/06       2,000       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 Filings
              $ 12,963          
                             
 
The rate review mechanism in the Mid-Tex Division was entered into as a result of a settlement in the September 20, 2007 Statement of Intent case filed with all Mid-Tex Division cities. Of the 439 incorporated cities served by the Mid-Tex Division, 438 of these cities are part of the rate review mechanism process. The West Texas rate review mechanism was entered into in August 2008 as a result of a settlement with the West Texas Coalition of Cities. The Lubbock and Amarillo rate review mechanisms were entered into in the spring of 2009. All mechanisms have been implemented on a three year trial period, of which three began in fiscal 2009, based upon calendar 2007 financial information and two of which began in fiscal 2009 based on 2008 financial information. The third rate review mechanism in the Mid-Tex Division will be filed in March 2010 based upon calendar 2009 financial information. This filing will be the last filing under the three year trial period.


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The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2009, 2008 and 2007:
 
                     
            Increase
     
            (Decrease) in
     
            Operating
    Effective
Division   Jurisdiction   Rate Activity   Income     Date
            (In thousands)      
 
2009 Other Rate Activity:
                   
Kentucky/Mid-States
  Georgia   PRP Surcharge(1)   $ 198     10/1/08
    Missouri   ISRS(2)     408     11/4/08
Colorado-Kansas
  Kansas   Tax Surcharge(3)     631     2/1/09
                     
Total 2009 Other Rate Activity
          $ 1,237      
                     
2008 Other Rate Activity:
                   
West Texas
  Triangle   Special Contract   $ 748     6/1/08
Colorado-Kansas
  Kansas   Tax Surcharge(3)     1,434     1/1/08
    Colorado   Agreement(4)     (1,100 )   11/20/07
Kentucky/Mid-States
  Georgia   PRP Surcharge(1)     342     10/1/07
                     
Total 2008 Other Rate Activity
          $ 1,424      
                     
2007 Other Rate Activity:
                   
West Texas
  Triangle   Special Contract   $ 227     7/1/07
Mid-Tex
  Texas   GRIP Refund     (2,887 )   4/1/07
Colorado-Kansas
  Kansas   Tax Surcharge(3)     1,528     1/1/07
                     
Total 2007 Other Rate Activity
          $ (1,132 )    
                     
 
 
(1) The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.
 
(2) Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.
 
(3) In the State of Kansas, the tax surcharge represents a true-up of ad valorem taxes paid versus what is designed to be recovered through base rates.
 
(4) In November 2007, the Colorado Public Utilities Commission approved an earnings agreement entered into jointly between the Colorado-Kansas Division, the Commission Staff and the Office of Consumer Counsel. The agreement called for a one-time refund to customers of $1.1 million made in January 2008.
 
In May 2007, our Mid-Tex Division filed for a 36-month gas contract review filing. This filing was mandated by prior RRC orders and related to the prudency of gas purchases made from November 2003 through October 2006, which total approximately $2.7 billion. In February 2009, the RRC approved the Hearing Examiner’s recommendation to disallow no gas costs.
 
In March 2009, the RRC established a procedural schedule in GUD 9696 to examine the 36-month gas contract review process. In August 2009, the full Commission approved an order to eliminate the 36 month gas contract review at its August 2009 meeting.
 
 
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 or judicial proceedings arising under


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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. Additionally, the FERC has regulatory authority over the sale of natural gas in the wholesale gas market and the use and release of interstate pipeline and storage capacity, as well as authority to detect and prevent market manipulation and to enforce compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. We have taken what we believe are all necessary and appropriate steps to comply with these regulations.
 
In September 2008, the RRC issued a final rule requiring the replacement of known compression couplings at pre-bent gas meter risers by November 2009. This rule primarily affected the operations of the Mid-Tex Division. Compliance with this rule has required us to expend significant amounts of capital in the Mid-Tex Division, but these prudent and mandatory expenditures have been recoverable through our rates. As of September 30, 2009 we had substantially completed our pre-bent riser replacement program in the Mid-Tex Division.
 
 
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 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, periods of higher gas prices, coupled with the electric utilities’ marketing efforts, increase competition for residential and commercial customers. In addition, AEM competes with other natural gas marketers to provide natural gas management and other related services to customers.
 
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.
 
 
At September 30, 2009, we had 4,891 employees, consisting of 4,753 employees in our regulated operations and 138 employees in our nonregulated operations.
 
 
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, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, under “Publications and Filings” under the “Investors” tab, 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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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 also annually reviews and updates, if necessary, 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 all corporate governance documents 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 risk factors, many of which are not within our control. Although we have tried to discuss key risk factors below, please be aware that other or new risks may prove to be important in the future. Investors should carefully consider the following discussion of risk factors as well as other information appearing in this report. These factors include the following:
 
Further disruptions in the credit markets could limit our ability to access capital and increase our costs of capital.
 
We rely upon access to both short-term and long-term credit markets to satisfy our liquidity requirements. The global credit markets have experienced significant disruptions and volatility during the last two years to a greater degree than has been seen in decades. In some cases, the ability or willingness of traditional sources of capital to provide financing has been reduced.
 
Historically, we have accessed the commercial paper markets to finance our short-term working capital needs. The disruptions in the credit markets during the fall of 2008 temporarily limited our access to the commercial paper markets and increased our borrowing costs. Consequently, for a short period, we were forced to borrow directly under our primary credit facility that backstops our commercial paper program to provide much of our working capital. This credit facility provides up to $567 million in committed financing through its expiration in December 2011. Our borrowings under this facility, along with our commercial paper, have been used primarily to purchase natural gas supplies for the upcoming winter heating season. The amount of our working capital requirements in the near-term will depend primarily on the market price of natural gas. Higher natural gas prices may adversely impact our accounts receivable collections and may require us to increase borrowings under our credit facilities to fund our operations. The cost of both our borrowings under the primary credit facility and our commercial paper has increased significantly since September 2008. We have historically supplemented our commercial paper program with a short-term committed credit facility that must be renewed annually. No borrowings are currently outstanding under our current $200 million short-term facility, which matures in October 2010.
 
Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation, Moody’s Investors Services, Inc. and Fitch Ratings, Ltd. If adverse credit conditions were to cause a significant limitation on our access to the private and public credit markets, we could see a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook or even a reduction in our credit ratings by one or more of the three credit rating agencies. Such a downgrade could further limit our access to public and/or private credit markets and increase the costs of borrowing under each source of credit.
 
Further, if our credit ratings were downgraded, we could be required to provide additional liquidity to our natural gas marketing segment because the commodity financial instruments markets could become unavailable to us. Our natural gas marketing segment depends primarily upon a committed $450 million credit facility to finance its working capital needs, which it uses primarily to issue standby letters of credit to its natural gas


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suppliers. A significant reduction in the availability of this facility could require us to provide extra liquidity to support its operations or reduce some of the activities of our natural gas marketing segment. Our ability to provide extra liquidity is limited by the terms of our existing lending arrangements with AEH, which are subject to annual approval by one state regulatory commission.
 
While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near-term. The future effects on our business, liquidity and financial results of a further deterioration of current conditions in the credit markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.
 
 
The slowdown in the U.S. economy, together with increased mortgage defaults and significant decreases in the values of homes and investment assets, has adversely affected the financial resources of many domestic households. It is unclear whether the administrative and legislative responses to these conditions will be successful in ending the current recession, including the lowering of current high unemployment rates across the U.S. As a result, our customers may seek to use even less gas and it may become more difficult for them to pay their gas bills. This may slow collections and lead to higher than normal levels of accounts receivable. This in turn could increase our financing requirements and bad debt expense.
 
 
We provide a cash-balance pension plan and postretirement healthcare benefits to eligible full-time employees. Our costs of providing such benefits and related funding requirements are subject to changes in the market value of the assets funding our pension and postretirement healthcare plans. The fluctuations over the last two years in the values of investments that fund our pension and postretirement healthcare plans may significantly differ from or alter the values and actuarial assumptions we use to calculate our future pension plan expense and postretirement healthcare costs and funding requirements under the Pension Protection Act. Any significant declines in the value of these investments could increase the expenses of our pension and postretirement healthcare plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to 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, as well as various actuarial calculations and assumptions, which may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates and interest rates and other factors.
 
 
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, storage and other 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 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


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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, storage and other 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 instruments. 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. Further tightening of the credit markets could cause more of our counterparties to fail to perform than expected. 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. These circumstances could also increase our capital requirements.
 
We are also subject to interest rate risk on our 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, increases in interest rates could adversely affect our future financial results.
 
 
Our natural gas distribution and regulated transmission and storage segments 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 business in 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 allowed 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.” Rate cases also 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. In addition, regulators may review our purchases of natural gas and can adjust the amount of our gas costs that we pass through to our customers. Finally, our debt and equity financings are also subject to approval by regulatory commissions in several states, which could limit our ability to access or take advantage of changes in the capital markets.
 
 
FERC has regulatory authority that affects some of our operations, including sales of natural gas in the wholesale gas market and the use and release of interstate pipeline and storage capacity. Under legislation passed by Congress in 2005, FERC has adopted rules designed to prevent market power abuse and market manipulation and to promote compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. These rules carry increased penalties for violations. We are currently under investigation by FERC for possible violations of its posting and competitive bidding regulations for pre-arranged released firm capacity on interstate natural gas


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pipelines. Should FERC conclude that we have committed such violations of its regulations and levies substantial fines and/or penalties against us, our business, financial condition or financial results could be adversely affected. In addition, although we have taken steps to structure current and future transactions to comply with applicable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regulations issued by FERC in the future could also adversely affect our business, financial condition 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.
 
Our business may be subject in the future to additional regulatory and financial risks associated with global warming and climate change.
 
There are a number of new federal and state legislative and regulatory initiatives being proposed and adopted in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. For example, in June 2009, the U.S. House of Representatives approved The American Clean Energy and Security Act of 2009, also known as the Waxman-Markey bill or “cap and trade” bill. The legislation, which strives to promote energy efficiency in the United States and reduce the amount of greenhouse gases produced, has implications for the natural gas industry. The bill, if adopted, would accelerate significantly the reduction in energy use per customer through a number of measures, including a dramatic tightening of building and appliance codes and other practices designed to put an increased focus on building and appliance efficiency. According to the bill, overall nationwide energy savings would total 75 percent by the year 2030 as a result of adopting its provisions. If adopted, the Waxman-Markey bill would establish a phased-in greenhouse gas emission cap-and-trade program that would reduce overall greenhouse gas emissions from capped sources by 17 percent by 2020 compared to emissions from such sources in 2005. These caps would be postponed on natural gas residential and commercial customers until 2016. Subsequent to the adoption by the House of this bill, a similar bill was introduced in the U.S. Senate, entitled the Clean Energy Jobs and American Power Act, also known as the Kerry-Boxer bill. At this time, the Kerry-Boxer bill is awaiting Senate action. The adoption of this legislation by Congress or similar legislation by states or the adoption of related regulations by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. Such new legislation or regulations could result in increased compliance costs for us or additional operating restrictions on our business, affect the demand for natural gas or impact the prices we charge to our customers. At this time, we cannot predict the potential impact of such laws or regulations on our future business, financial condition or financial results.
 
 
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 may be significantly affected by changes in the Texas economy in general and regulatory decisions by state and local regulatory authorities in Texas.


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Since 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, there is no assurance that we will continue to receive such regulatory protection from adverse weather in our rates in the future. The loss of such weather — normalized rates could have an adverse effect on our operations and financial results. In addition, 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. 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.
 
 
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 impact future financial results.
 
Rapid increases in the costs of purchased gas would 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.
 
 
We must continually build additional capacity in our natural gas distribution system to enable us to adequately serve any significant amount of additional 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 and availability of which is dependent on the liquidity of the credit markets, interest rates and other market conditions. 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.
 
 
In 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.
 
In the case of industrial customers, such as manufacturing plants, 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


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storage segment currently faces 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.
 
 
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 operations or financial results could be adversely affected.
 
 
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 covering such risks may be more limited, which could increase the risk that an event could adversely affect our operations or financial results.
 
ITEM 1B.   Unresolved Staff Comments.
 
Not applicable.
 
ITEM 2.   Properties.
 
 
At September 30, 2009, our natural gas distribution segment owned an aggregate of 70,879 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 5,950 miles of gas transmission and gathering lines and our pipeline, storage and other segment owned 113 miles of gas transmission and gathering lines.


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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
    490,000       10,000       500,000       30,000  
                                 
Total
    10,383,590       11,075,200       21,458,790       232,100  
Regulated Transmission and Storage Segment — Texas
    39,243,226       13,128,025       52,371,251       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
    53,558,299       27,799,198       81,357,497       1,594,100  
                                 
 
 
(1) Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.
 
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     3,237,243       97,832  
    Kentucky/Mid-States Division     18,497,006       348,290  
    Louisiana Division     2,574,479       158,731  
    Mississippi Division     3,875,429       165,402  
    West Texas Division     1,225,000       56,000  
                     
Total
    29,409,157       826,255  
Natural Gas Marketing Segment
  Atmos Energy Marketing, LLC     9,539,053       278,417  
Pipeline, Storage and Other Segment
  Trans Louisiana Gas Pipeline, Inc.     1,674,000       67,507  
                     
Total Contracted Storage Capacity
    40,622,210       1,172,179  
                 
 
 
(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.


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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.
 
 
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 12 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 2009.


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The following table sets forth certain information as of September 30, 2009, 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
    62       12     Chairman and Chief Executive Officer
Kim R. Cocklin
    58       3     President and Chief Operating Officer
Louis P. Gregory
    54       9     Senior Vice President and General Counsel
Michael E. Haefner
    49       1     Senior Vice President, Human Resources
Mark H. Johnson
    50       8     Senior Vice President, Nonregulated Operations and President, Atmos Energy Marketing, LLC
Fred E. Meisenheimer
    65       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. Since October 1, 2008, Mr. Best has continued to serve the Company as Chairman of the Board and Chief Executive Officer.
 
Kim R. Cocklin joined the Company in June 2006 as Senior Vice President, Regulated Operations. On October 1, 2008, Mr. Cocklin was named President and Chief Operating Officer. On November 10, 2009, Mr. Cocklin was elected to the Board of Directors. 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.
 
Louis P. Gregory was named Senior Vice President and General Counsel in September 2000.
 
Michael E. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources. Prior to joining the Company, Mr. Haefner was a self-employed consultant and founder and president of Perform for Life, LLC from May 2007 to May 2008. Mr. Haefner previously served for 10 years as the Senior Vice President, Human Resources, of Sabre Holding Corporation, the parent company of Sabre Airline Solutions, Sabre Travel Network and Travelocity.
 
Mark H. Johnson was named Senior Vice President, Nonregulated 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 left his position with the Company to pursue other interests, effective October 31, 2009.
 
Fred E. Meisenheimer was named Senior Vice President and Chief Financial Officer in February 2009. Mr. Meisenheimer previously served the Company as Vice President and Controller from July 2000 through May 2009 and also served as interim Chief Financial Officer beginning in January 2009.


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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 2009 and 2008 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:
 
                                                 
    2009     2008  
                Dividends
                Dividends
 
    High     Low     paid     High     Low     Paid  
 
Quarter ended:
                                               
December 31
  $ 27.88     $ 21.17     $ .330     $ 29.46     $ 26.11     $ .325  
March 31
    25.95       20.20       .330       28.96       25.09       .325  
June 30
    26.37       22.81       .330       28.54       25.81       .325  
September 30
    28.80       24.65       .330       28.25       25.49       .325  
                                                 
                    $ 1.32                     $ 1.30  
                                                 
 
Dividends are payable at the discretion of our Board of Directors out of legally available funds. 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, 2009 was 20,824. 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 2009 that were not registered under the Securities Act of 1933, as amended.


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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 two different customized peer company groups, the New Comparison Company Index and the Old Comparison Company Index. The New Comparison Company Index includes National Fuel Gas and excludes Questar Corporation because the Board of Directors determined that National Fuel Gas better fits the profile of the companies in the peer group, which is comprised of natural gas distribution 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, 2004 in our common stock, the S&P 500 Index and in the common stock of the companies in the New and Old Comparison Company Indexes, 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 Indices
 
(PERFORMANCE GRAPH)
 
                                                 
    Cumulative Total Return
    9/30/04   9/30/05   9/30/06   9/30/07   9/30/08   9/30/09
 
Atmos Energy Corporation
    100.00       117.33       124.23       128.40       126.62       141.40  
S&P 500 Index
    100.00       112.25       124.37       144.81       112.99       105.18  
New Comparison Company Index
    100.00       131.99       130.72       152.32       134.96       136.40  
Old Comparison Company Index
    100.00       140.50       136.86       160.95       139.13       137.43  
 
The New 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, EQT Corporation (formerly known as Equitable Resources, Inc.), Integrys Energy Group, Inc., National Fuel Gas, Nicor Inc., NiSource Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., Vectren Corporation and WGL Holdings, Inc. The Old Comparison Company Index includes the companies listed above in the New Comparison Company Index with the exception of National Fuel Gas, which replaced Questar Corporation in the Company’s peer group in the current year for the reasons discussed above.


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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2009.
 
                         
    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:
                       
1998 Long-Term Incentive Plan
    611,227     $ 21.88       1,473,531  
                         
Total equity compensation plans approved by security holders
    611,227       21.88       1,473,531  
Equity compensation plans not approved by security holders
                 
                         
Total
    611,227     $ 21.88       1,473,531  
                         


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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.
 
                                         
    Fiscal Year Ended September 30  
    2009(1)     2008     2007(1)     2006(1)     2005  
    (In thousands, except per share data and ratios)  
 
Results of Operations
                                       
Operating revenues
  $ 4,969,080     $ 7,221,305     $ 5,898,431     $ 6,152,363     $ 4,961,873  
Gross profit
    1,346,702       1,321,326       1,250,082       1,216,570       1,117,637  
Operating expenses(1)
    899,300       893,431       851,446       833,954       768,982  
Operating income
    447,402       427,895       398,636       382,616       348,655  
Miscellaneous income (expense)
    (3,303 )     2,731       9,184       881       2,021  
Interest charges
    152,830       137,922       145,236       146,607       132,658  
Income before income taxes
    291,269       292,704       262,584       236,890       218,018  
Income tax expense
    100,291       112,373       94,092       89,153       82,233  
Net income
  $ 190,978     $ 180,331     $ 168,492     $ 147,737     $ 135,785  
Weighted average diluted shares outstanding
    92,024       90,272       87,745       81,390       79,012  
Diluted net income per share
  $ 2.08     $ 2.00     $ 1.92     $ 1.82     $ 1.72  
Cash flows from operations
  $ 919,233     $ 370,933     $ 547,095     $ 311,449     $ 386,944  
Cash dividends paid per share
  $ 1.32     $ 1.30     $ 1.28     $ 1.26     $ 1.24  
Total natural gas distribution throughput (MMcf)(2)
    408,885       429,354       427,869       393,995       411,134  
Total regulated transmission and storage transportation volumes (MMcf)(2)
    528,689       595,542       505,493       410,505       373,879  
Total natural gas marketing sales volumes (MMcf)(2)
    370,569       389,392       370,668       283,962       238,097  
Financial Condition
                                       
Net property, plant and equipment
  $ 4,439,103     $ 4,136,859     $ 3,836,836     $ 3,629,156     $ 3,374,367  
Working capital
    91,519       78,017       149,217       (1,616 )     151,675  
Total assets
    6,343,766       6,386,699       5,895,197       5,719,547       5,610,547  
Short-term debt, inclusive of current maturities of long-term debt
    72,681       351,327       154,430       385,602       148,073  
Capitalization:
                                       
Shareholders’ equity
    2,176,761       2,052,492       1,965,754       1,648,098       1,602,422  
Long-term debt (excluding current maturities)
    2,169,400       2,119,792       2,126,315       2,180,362       2,183,104  
                                         
Total capitalization
    4,346,161       4,172,284       4,092,069       3,828,460       3,785,526  
Capital expenditures
    509,494       472,273       392,435       425,324       333,183  
Financial Ratios
                                       
Capitalization ratio(3)
    49.3 %     45.4 %     46.3 %     39.1 %     40.7 %
Return on average shareholders’ equity(4)
    8.9 %     8.8 %     8.8 %     8.9 %     9.0 %
 
 
(1) Financial results for 2009, 2007 and 2006 include a $5.4 million, $6.3 million and a $22.9 million pre-tax loss for the impairment of certain assets.
 
(2) Net of intersegment eliminations
 
(3) 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.
 
(4) 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.


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ITEM 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
 
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.
 
 
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: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of recent economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the possible impact of future additional regulatory and financial risks associated with global warming and climate change; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events, and other risks and uncertainties discussed herein, especially those discussed 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


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our estimates, including those related to risk management and trading activities, fair value measurements, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and valuation of goodwill, indefinite-lived intangible assets and other long-lived 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. We meet the criteria established within accounting principles generally accepted in the United States of a cost-based, rate-regulated entity, which requires us to reflect the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in our financial statements in accordance with applicable authoritative accounting standards. We apply the provisions of this standard to our regulated operations and record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable and regulatory liabilities 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 it is probable they can be recovered through rates. Discontinuing the application of this method of accounting for regulatory assets and liabilities 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 regulated 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 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.
 
On occasion, we are permitted to implement new rates that have not been formally approved by our regulatory authorities, which are subject to refund. 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 cost adjustment mechanisms. Purchased gas cost 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 cost, 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 cost 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 cost adjustment mechanism. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our balance sheet.
 
Operating revenues for our regulated transmission and storage and pipeline, storage and other segments are recognized in the period in which actual volumes are transported and storage services are provided.
 
Operating revenues for our natural gas marketing segment and the associated carrying value of natural gas inventory (inclusive of storage costs) are recognized when we sell the gas and physically deliver it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial


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instruments used in our natural gas marketing activities and unrealized gains and losses arising from changes in the fair value of natural gas inventory designated as a hedged item in a fair value hedge and the associated financial instruments.
 
Allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collections experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
 
Financial instruments and hedging activities — We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically use financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to meet the needs of our regulated and nonregulated businesses.
 
We record all of our financial instruments on the balance sheet at fair value as required by accounting principles generally accepted in the United States, with changes in fair value ultimately recorded in the income statement. The timing of when changes in fair value of our financial instruments are recorded in the income statement depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the income statement as they occur.
 
 
In our natural gas distribution segment, our customers are exposed to the effect of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season. The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk in this segment are included in our purchased gas adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact to our natural gas distribution segment as a result of the use of financial instruments.
 
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. We also perform asset optimization activities in both our natural gas marketing segment and pipeline, storage and other segment. As a result of these activities, our nonregulated operations are exposed to risks associated with changes in the market price of natural gas. We manage our exposure to the risk of natural gas price changes through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties.
 
In our natural gas marketing and pipeline, storage and other segments, we have designated the natural gas inventory held by these operating segments 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 financial instruments 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 revenue in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial instruments designated against our physical inventory (NYMEX) and the market (spot) prices used to value


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our physical storage (Gas Daily) result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. The difference in the spot price used to value our physical inventory and the forward price used to value the related financial instruments can result in volatility in our reported income as a component of unrealized margins. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized. 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 fixed-price forward contracts used in our natural gas marketing segment to deliver gas as normal purchases and normal sales. As such, these deliveries are recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts have been designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on open financial instruments 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.
 
We also use storage swaps and futures to capture additional storage arbitrage opportunities in our natural gas marketing segment that arise after 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. These financial instruments have not been designated as hedges.
 
 
We periodically manage interest rate risk, typically when we issue new or refinance existing long-term debt. As of September 30, 2009, we had no financial instruments in place to manage interest rate risk. However, in prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We designated these 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 were recorded as a component of accumulated other comprehensive income (loss). The realized gain or loss recognized upon settlement of each Treasury lock agreement was initially recorded as a component of accumulated other comprehensive income (loss) and is recognized as a component of interest expense over the life of the related financing arrangement.
 
Impairment assessments — We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. As of September 30, 2009, we had 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 and 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


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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. Prior to fiscal 2009, we reviewed the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities annually based upon a June 30 measurement date. Effective October 1, 2008, we changed our measurement date to September 30. 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 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 obligations and net pension and postretirement costs. When establishing our discount rate, we consider high quality corporate bond rates, 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 costs. 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 costs are not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs 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 costs ultimately recognized. A 0.25 percent change in our discount rate would impact our pension and postretirement costs by approximately $0.8 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $0.9 million.
 
Fair Value Measurements — We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.
 
Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices) as a practical expedient for determining fair value measurement, as permitted under current accounting standards. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed. We


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utilize models and other valuation methods to determine fair value when external sources are not available. 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. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.
 
Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. Recent adverse developments in the global financial and credit markets have made it more difficult and more expensive for companies to access the short-term capital markets, which may negatively impact the creditworthiness of our counterparties. A continued tightening of the credit markets could cause more of our counterparties to fail to perform. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.
 
Amounts reported at fair value are subject to potentially significant volatility based upon 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 financial instruments. We believe the market prices and models used to value these financial instruments 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.
 
RESULTS OF OPERATIONS
 
 
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 fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal 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 64 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 our business impacts our working capital differently at various times during the year. Typically, our accounts receivable, accounts payable and short-term debt balances peak by the end of January and then start to decline, as customers begin to pay their winter heating bills. Gas stored underground, particularly in our natural gas distribution segment, typically peaks in November and declines as we utilize storage gas to serve our customers.
 
During the current year, several external factors have impacted Atmos Energy, including, but not limited to, adverse developments in the global and financial credit markets and the unfavorable impact of the economic recession.
 
The tightening of the credit markets has made it more difficult and more expensive for us to access the capital markets. However, during the fiscal year, we took several steps to improve our financial position. In March 2009, we successfully completed an offering of $450 million 8.5% senior notes, and used most of the proceeds in April 2009 to redeem $400 million of senior notes that were scheduled to mature in October 2009. Additionally, we enhanced our liquidity sources in various ways. In October 2008, we replaced our former $300 million 364-day committed credit facility with a new 364-day $212.5 million committed credit facility. Then, in October 2009, we replaced the $212.5 million 364-day committed credit facility with a new 364-day $200 million committed credit facility. We also converted AEM’s former $580 million uncommitted credit


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facility to a 364-day $375 million committed credit facility in December 2008. This facility was subsequently increased to $450 million in April 2009. Finally, in April 2009 we replaced an expiring $18 million unsecured committed credit facility with a $25 million unsecured committed credit facility. After entering into these new facilities, we currently have a total of approximately $902.0 million available to us under four committed credit facilities. As a result of these developments and our continued successful financial performance, Standard & Poor’s Corporation (S&P) upgraded our credit rating from BBB to BBB+ in December 2008 and Moody’s Investors Service (Moody’s) upgraded the credit rating on our senior long-term debt from Baa3 to Baa2 and our commercial paper from P-3 to P-2 in May 2009. These ratings upgrades have improved our ability to access the short-term capital markets to satisfy our liquidity requirements on more economical terms.
 
However, the turmoil in the financial markets did also have a direct financial impact on our results of operations. We determined that the decline in fair value for certain available-for-sale securities in our Supplemental Executive Benefit Plans experienced during the year ended September 30, 2009 was other than temporary and, accordingly, recorded a $5.4 million noncash charge to impair the assets. As a result of these impairments, we do not maintain any investments that are in an unrealized loss position.
 
Finally, challenging economic times resulted in a general decline in throughput across most of our business segments. The impact of the economic downturn is most apparent in a general decline in throughput. Our natural gas distribution segment has experienced a year-over-year 5 percent decrease in consolidated throughput, primarily associated with lower residential, commercial and industrial consumption. Declines in the demand for natural gas as a result of idle production and plant closures have contributed to an 11 percent year-over-year decrease in consolidated throughput in our regulated transmission and storage segment and a 5 percent year-over-year decrease in consolidated sales volumes in our natural gas marketing segment. However, recent improvements in rate design in our natural gas distribution segment and the ability to earn higher per-unit margins in our regulated transmission and storage and natural gas marketing segments has more than offset the decline in throughput and sales volumes. Additionally, reduced demand for natural gas has resulted in lower natural gas prices, which has contributed significantly to the increase in our operating cash flow.
 
Consolidated Results
 
The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2009, 2008 and 2007.
 
                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007  
    (In thousands, except per share data)  
 
Operating revenues
  $ 4,969,080     $ 7,221,305     $ 5,898,431  
Gross profit
    1,346,702       1,321,326       1,250,082  
Operating expenses
    899,300       893,431       851,446  
Operating income
    447,402       427,895       398,636  
Miscellaneous income (expense)
    (3,303 )     2,731       9,184  
Interest charges
    152,830       137,922       145,236  
Income before income taxes
    291,269       292,704       262,584  
Income tax expense
    100,291       112,373       94,092  
Net income
  $ 190,978     $ 180,331     $ 168,492  
Earnings per diluted share
  $ 2.08     $ 2.00     $ 1.92  
 
Historically, our regulated operations arising from our natural gas distribution and regulated transmission and storage operations contributed 65 to 85 percent of our consolidated net income. Regulated operations contributed 83 percent, 74 percent and 64 percent to our consolidated net income for fiscal years 2009, 2008,


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and 2007. Our consolidated net income during the last three fiscal years was earned across our business segments as follows:
 
                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007  
    (In thousands)  
 
Natural gas distribution segment
  $ 116,807     $ 92,648     $ 73,283  
Regulated transmission and storage segment
    41,056       41,425       34,590  
Natural gas marketing segment
    20,194       29,989       45,769  
Pipeline, storage and other segment
    12,921       16,269       14,850  
                         
Net income
  $ 190,978     $ 180,331     $ 168,492  
                         
 
The following table segregates our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007  
    (In thousands, except per share data)  
 
Regulated operations
  $ 157,863     $ 134,073     $ 107,873  
Nonregulated operations
    33,115       46,258       60,619  
                         
Consolidated net income
  $ 190,978     $ 180,331     $ 168,492  
                         
Diluted EPS from regulated operations
  $ 1.72     $ 1.49     $ 1.23  
Diluted EPS from nonregulated operations
    0.36       0.51       0.69  
                         
Consolidated diluted EPS
  $ 2.08     $ 2.00     $ 1.92  
                         
 
Net income during fiscal 2009 increased six percent over fiscal 2008. Net income from our regulated operations increased 18 percent during fiscal 2009. The increase primarily reflects a $32.3 million increase in gross profit resulting from the net favorable impact of various ratemaking activities in our natural gas distribution segment, partially offset by higher depreciation expense, pipeline maintenance costs and interest expense. Net income in our nonregulated operations decreased $13.1 million, primarily due to the impact of unrealized margins. Unrealized margins totaled $35.9 million which reduced earnings per share by $0.23 per diluted share. The overall increase in consolidated net income was also favorably affected by non-recurring items totaling $17.1 million, or $0.19 per diluted share, related to the following pre-tax amounts:
 
  •  $11.3 million related to a favorable one-time tax benefit
 
  •  $7.6 million related to the favorable impact of an update to the estimate for unbilled accounts
 
  •  $7.0 million favorable impact of the reversal of estimated uncollectible gas costs
 
  •  $5.4 million unfavorable impact of a non-cash impairment charge of $5.4 million related to available-for-sale securities in our Supplemental Executive Retirement Plan
 
Net income during fiscal 2008 increased seven percent over fiscal 2007. Net income from our regulated operations increased 24 percent during fiscal 2008. The increase primarily reflects a $53.8 million increase in gross profit resulting from our ratemaking efforts, coupled with higher per-unit transportation margins and an 18 percent increase in consolidated throughput in our Atmos Pipeline — Texas Division. These increases were partially offset by a four percent increase in operating expenses. Net income in our nonregulated operations experienced a 24 percent decline as less volatile natural gas market conditions significantly reduced our asset optimization margins. However, higher delivered gas margins in our natural gas marketing segment and unrealized margins partially offset this decrease.
 
See the following discussion regarding the results of operations for each of our business operating segments.


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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.
 
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. Prior to January 1, 2009, timing differences existed between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. These timing differences had a significant temporary effect on operating income in periods with volatile gas prices, particularly in our Mid-Tex Division. Beginning January 1, 2009, changes in our franchise fee agreements in our Mid-Tex Division became effective which should significantly reduce the impact of this timing difference on a prospective basis. Although this timing difference will still be present for gross receipts taxes, the timing differences described above should be less significant.
 
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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Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2009, 2008 and 2007 are presented below.
 
                                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007     2009 vs. 2008     2008 vs. 2007  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 1,024,628     $ 1,006,066     $ 952,684     $ 18,562     $ 53,382  
Operating expenses
    735,614       744,901       731,497       (9,287 )     13,404  
                                         
Operating income
    289,014       261,165       221,187       27,849       39,978  
Miscellaneous income
    5,766       9,689       8,945       (3,923 )     744  
Interest charges
    124,055       117,933       121,626       6,122       (3,693 )
                                         
Income before income taxes
    170,725       152,921       108,506       17,804       44,415  
Income tax expense
    53,918       60,273       35,223       (6,355 )     25,050  
                                         
Net income
  $ 116,807     $ 92,648     $ 73,283     $ 24,159     $ 19,365  
                                         
Consolidated natural gas distribution sales volumes — MMcf
    282,117       292,676       297,327       (10,559 )     (4,651 )
Consolidated natural gas distribution transportation volumes — MMcf
    126,768       136,678       130,542       (9,910 )     6,136  
                                         
Total consolidated natural gas distribution throughput — MMcf
    408,885       429,354       427,869       (20,469 )     1,485  
                                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.47     $ 0.44     $ 0.45     $ 0.03     $ (0.01 )
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 6.95     $ 9.05     $ 8.09     $ (2.10 )   $ 0.96  
 
The following table shows our operating income by natural gas distribution division for the fiscal years ended September 30, 2009, 2008 and 2007. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007     2009 vs. 2008     2008 vs. 2007  
    (In thousands)  
 
Mid-Tex
  $ 127,625     $ 115,009     $ 68,574     $ 12,616     $ 46,435  
Kentucky/Mid-States
    47,978       48,731       42,161       (753 )     6,570  
Louisiana
    43,434       39,090       44,193       4,344       (5,103 )
West Texas
    23,338       13,843       21,036       9,495       (7,193 )
Mississippi
    21,287       19,970       23,225       1,317       (3,255 )
Colorado-Kansas
    21,321       20,615       22,392       706       (1,777 )
Other
    4,031       3,907       (394 )     124       4,301  
                                         
Total
  $ 289,014     $ 261,165     $ 221,187     $ 27,849     $ 39,978  
                                         


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Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008
 
The $18.6 million increase in natural gas distribution gross profit primarily reflects an increase in rates. The major components of the increase are as follows:
 
  •  $13.6 million net increase in rates in the Mid-Tex Division as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all incorporated cities in the division other than the City of Dallas and Environs (the Settled Cities) and adjustments for customers in the City of Dallas.
 
  •  $16.0 million increase in other rate adjustments primarily in Georgia, Kansas, Louisiana and West Texas.
 
  •  $7.6 million increase attributable to a non-recurring update to our estimate for gas delivered to customers but not yet billed to reflect changes in base rates in several of our jurisdictions recorded in the fiscal first quarter.
 
  •  $7.0 million uncollectible gas cost accrual recorded in a prior year that was reversed in the current year period.
 
These increases were partially offset by:
 
  •  $17.9 million decrease as a result of a five percent decrease in consolidated distribution throughput primarily associated with lower residential, commercial and industrial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.
 
  •  $10.8 million decrease due to lower revenue related taxes, partially offset by the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income discussed below.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income and asset impairments decreased $9.3 million, primarily due to the following:
 
  •  $10.6 million decrease due to lower legal, fuel and other administrative costs.
 
  •  $9.2 million decrease in allowance for doubtful accounts due to the impact of recent rate design changes in certain jurisdictions that allow us to recover the gas cost portion of uncollectible accounts as well as a 23 percent year-over-year decline in the average cost of gas.
 
  •  $9.2 million decrease in taxes other than income primarily associated with lower franchise fees and state gross receipt taxes.
 
These decreases were partially offset by:
 
  •  $15.1 million increase in depreciation and amortization, due primarily to additional assets placed in service during the current year.
 
  •  $4.6 million increase due to a noncash charge to impair certain available-for-sale investments as we believed the fair value of these investments would not recover within a reasonable period of time.
 
Results for the current year include a $10.5 million tax benefit associated with updating the rates used to determine our deferred taxes. In addition, results for the prior year included a $1.2 million gain on the sale of irrigation assets in our West Texas Division.
 
Interest charges increased $6.1 million primarily due to the effect of the Company’s March 2009 issuance of $450 million 8.50% senior notes to repay $400 million 4.00% senior notes in April 2009. In addition, we experienced higher average short-term debt balances, interest rates and commitment fees during the current year compared to the prior year.


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Fiscal year ended September 30, 2008 compared with fiscal year ended September 30, 2007
 
The $53.4 million increase in natural gas distribution gross profit is primarily the result of increased rates and higher revenue-related taxes. The major components of the increase are as follows:
 
  •  $29.2 million increase in rates in the Mid-Tex Division due to its 2006 GRIP filing, the fiscal 2008 and 2007 rate cases and the absence of a one time GRIP refund that occurred in fiscal 2007.
 
  •  $14.4 million increase in rates in the Kansas, Kentucky, Louisiana, Tennessee and West Texas divisions.
 
  •  $8.6 million increase due to higher revenue related taxes, partially offset by the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income discussed below.
 
  •  $7.5 million increase due to an accrual for estimated unrecoverable gas costs in fiscal 2007 that did not recur in fiscal 2008.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased by a net $13.4 million, primarily due to the following:
 
  •  $9.0 million increase primarily due to higher employee and administrative costs and increased natural gas odorization and fuel costs.
 
  •  $7.2 increase in franchise and state gross receipts taxes due to higher revenues.
 
  •  $4.3 million increase due to the absence in the current year of the deferral of hurricane-related operation and maintenance expenses in fiscal 2007.
 
  •  $3.3 million noncash charge associated with the write-off of software costs in fiscal 2007 that did not recur in fiscal 2008.
 
These increases were offset by a $3.2 million decrease in the provision for doubtful accounts, which reflects our continued effective collection efforts.
 
The increase in miscellaneous income primarily reflects the recognition of a $1.2 million gain on the sale of irrigation assets in our West Texas Division during the fiscal 2008 second quarter.
 
Interest charges allocated to the natural gas distribution segment decreased $3.7 million due to lower average outstanding short-term debt balances in fiscal 2008 compared with fiscal 2007.
 
 
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. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Additionally, pricing differences that occur between the natural gas hubs served by our pipeline could significantly impact our results as we can profit through the arbitrage of these spreads. Spread differences are influenced by supply and demand constraints not only in the markets we directly serve but in other markets as well. 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.


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Financial and operational highlights for our regulated transmission and storage segment for the fiscal years ended September 30, 2009, 2008 and 2007 are presented below.
 
                                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007     2009 vs. 2008     2008 vs. 2007  
          (In thousands, unless otherwise noted)  
 
Mid-Tex Division transportation
  $ 89,348     $ 86,665     $ 77,090     $ 2,683     $ 9,575  
Third-party transportation
    95,314       85,256       65,158       10,058       20,098  
Storage and park and lend services
    11,858       9,746       9,374       2,112       372  
Other
    13,138       14,250       11,607       (1,112 )     2,643  
                                         
Gross profit
    209,658       195,917       163,229       13,741       32,688  
Operating expenses
    116,495       106,172       83,399       10,323       22,773  
                                         
Operating income
    93,163       89,745       79,830       3,418       9,915  
Miscellaneous income
    1,433       1,354       2,105       79       (751 )
Interest charges
    30,982       27,049       27,917       3,933       (868 )
                                         
Income before income taxes
    63,614       64,050       54,018       (436 )     10,032  
Income tax expense
    22,558       22,625       19,428       (67 )     3,197  
                                         
Net income
  $ 41,056     $ 41,425     $ 34,590     $ (369 )   $ 6,835  
                                         
Gross pipeline transportation volumes — MMcf
    706,132       782,876       699,006       (76,744 )     83,870  
                                         
Consolidated pipeline transportation volumes — MMcf
    528,689       595,542       505,493       (66,853 )     90,049  
                                         
 
Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008
 
The $13.7 million increase in regulated transmission and storage gross profit was attributable primarily to the following factors:
 
  •  $13.0 million increase from higher demand-based fees.
 
  •  $5.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions.
 
  •  $5.4 million increase due to our GRIP filings.
 
These increases were partially offset by an $8.4 million decrease associated with a decrease in transportation volumes to our Mid-Tex Division due to warmer weather and a decrease in electrical generation, Barnett Shale and HUB deliveries.
 
Operating expenses increased $10.3 million primarily due to higher levels of pipeline maintenance activities.
 
Results for the current-year period also include a $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.
 
Fiscal year ended September 30, 2008 compared with fiscal year ended September 30, 2007
 
The $32.7 million increase in regulated transmission and storage gross profit is primarily the result of rate adjustments and increased volumes. The major components of the increase are as follows:
 
  •  $13.1 million increase from rate adjustments resulting from our 2006 and 2007 GRIP filings.
 
  •  $8.3 million increase from transportation volumes as consolidated throughput increased 18 percent primarily due to increased transportation in the Barnett Shale region of Texas.


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  •  $8.0 million increase related to increased service fees and per-unit transportation margins due to favorable market conditions.
 
  •  $1.5 million increase due to new compression contracts and transportation capacity enhancements.
 
  •  $1.3 million increase in sales of excess gas compared to 2007.
 
Operating expenses increased $22.8 million primarily due to increased pipeline integrity and maintenance costs.
 
 
AEM’s primary business is to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. In addition, AEM utilizes proprietary and customer-owned transportation and storage assets to provide 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 financial instruments. As a result, AEM’s margins arise from the types of commercial transactions we have structured with our customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.
 
AEM seeks to enhance its gross profit margin by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity we own or control in our natural gas distribution and natural gas marketing segments. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEM has access and selling financial instruments at advantageous prices to lock in a gross profit margin.
 
AEM continually manages its net physical position to attempt to increase the future economic profit that was created when the original transaction was executed. Therefore, AEM may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market conditions and recognize any associated gains or losses at that time. If AEM elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to hedge the original financial instruments. If AEM elects to defer the withdrawal of gas, it will reset its financial instruments by settling the original financial instruments and executing new financial instruments to correspond to the revised withdrawal schedule.
 
We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments 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 hedged natural gas 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 and losses in the period of change. Changes in 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 unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.
 
AEM also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.
 
Due to the nature of these operations, natural gas prices have a significant impact on our natural gas marketing operations. Within our delivered gas activities, higher natural gas prices may adversely impact our


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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. Higher gas prices, as well as competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.
 
Volatility in natural gas prices also has a significant impact on our natural gas marketing segment. Increased price volatility often has a significant impact on the spreads between the market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. However, increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.
 
 
Financial and operational highlights for our natural gas marketing segment for the fiscal years ended September 30, 2009, 2008 and 2007 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed 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 our net physical position and the related financial instruments used 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 dependent upon the levels of our net physical position at the end of the reporting period.
 
                                         
    For the Fiscal Year Ended September 30  
    2009     2008     2007     2009 vs. 2008     2008 vs. 2007  
    (In thousands, unless otherwise noted)  
 
Realized margins
                                       
Delivered gas
  $ 75,341     $ 73,627     $ 57,054     $ 1,714     $ 16,573  
Asset optimization
    37,670       (6,135 )     28,827       43,805       (34,962 )
                                         
      113,011       67,492       85,881       45,519       (18,389 )
Unrealized margins
    (28,399 )     25,529       18,430       (53,928 )     7,099  
                                         
Gross profit
    84,612       93,021       104,311       (8,409 )     (11,290 )
Operating expenses
    38,208       36,629       29,271       1,579       7,358  
                                         
Operating income
    46,404       56,392       75,040       (9,988 )     (18,648 )
Miscellaneous income
    537       2,022       6,434       (1,485 )     (4,412 )
Interest charges
    12,911       9,036       5,767       3,875       3,269  
                                         
Income before income taxes
    34,030       49,378       75,707       (15,348 )     (26,329 )
Income tax expense
    13,836       19,389       29,938       (5,553 )     (10,549 )
                                         
Net income
  $ 20,194     $ 29,989     $ 45,769     $ (9,795 )   $ (15,780 )
                                         
Gross natural gas marketing sales volumes — MMcf
    441,081       457,952       423,895       (16,871 )     34,057  
                                         
Consolidated natural gas marketing sales volumes — MMcf
    370,569       389,392       370,668       (18,823 )     18,724  
                                         
Net physical position (Bcf)
    13.8       8.0       12.3       5.8       (4.3 )
                                         


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Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008
 
AEM’s delivered gas business contributed 67 percent to total realized margins during fiscal 2009 with asset optimization activities contributing the remaining 33 percent. In the prior year, delivered gas activities represented substantially all of AEM’s realized gross profit margin. The $45.5 million increase in realized gross profit reflected:
 
  •  A $43.8 million increase in asset optimization margins. AEM realized substantially all of its realized asset optimization margin in the fiscal 2009 first quarter when it realized substantially all of the economic value that it had captured as of September 30, 2008 from withdrawing gas and settling the associated financial instruments. Since that time, as a result of falling current cash prices, AEM has been deferring storage withdrawals and has been a net injector of gas into storage to increase the economic value it could realize in future periods from its asset optimization activities. In the prior year, AEM deferred storage withdrawals primarily into fiscal 2009 and recognized losses on the settlement of the associated financial instruments.
 
  •  A $1.7 million increase in realized delivered gas margins. AEM experienced a six percent increase in per-unit margins as a result of improved basis spreads in certain market areas where we were able to better optimize transportation assets and successful contract renewals. These margin improvements more than offset a four percent decrease in gross sales volumes primarily attributable to lower industrial demand as a result of the current economic climate.
 
The increase in realized gross profit was more than offset by a $53.9 million decrease in unrealized margins attributable to the following:
 
  •  The realization of unrealized gains recorded during fiscal 2008.
 
  •  A modest widening of the physical/financial spreads, partially offset by favorable unrealized basis gains in certain markets.
 
  •  A 5.8 Bcf increase in AEM’s net physical position.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income taxes, and asset impairments, increased $1.6 million primarily due the following factors:
 
  •  $4.0 million increase in legal and other administrative costs.
 
  •  $2.4 million decrease related to tax matters incurred in the prior year that did not recur in the current year.
 
Asset Optimization Activities
 
AEM monitors the impact of its asset optimization efforts by estimating the gross profit, before related fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic value, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement and related fees is referred to as the potential gross profit.
 
We define potential gross profit as the change in AEM’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include other operating expenses and associated income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic value or the potential gross profit will be fully realized in the future.
 
We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.


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The following table presents AEM’s economic value and its potential gross profit (loss) at September 30, 2009 and 2008.
 
                 
    September 30  
    2009     2008  
    (In millions, unless otherwise noted)  
 
Economic value
  $ 28.6     $ 48.5  
Associated unrealized (gains) losses
    11.0       (36.4 )
                 
Subtotal
    39.6       12.1  
Related fees(1)
    (14.7 )     (19.6 )
                 
Potential gross profit (loss)
  $ 24.9     $ (7.5 )
                 
Net physical position (Bcf)
    13.8       8.0  
                 
 
 
(1) Related fees represent AEM’s contractual costs to acquire the storage capacity utilized in its asset optimization operations. The fees primarily consist of demand fees and contractual obligations to sell gas below market index prices in exchange for the right to manage and optimize third party storage assets for the positions AEM has entered into as of September 30, 2009 and 2008.
 
During the year ended September 30, 2009, AEM’s economic value decreased from $48.5 million, or $6.08/Mcf at September 30, 2008, to $28.6 million, or $2.07/Mcf. As discussed above, in the fiscal 2009 first quarter, AEM withdrew gas and realized substantially all of the economic value that it captured as of September 30, 2008. During the remainder of the year, as a result of falling current cash prices, AEM deferred certain storage withdrawals and has been a net injector of gas into storage to increase economic value that it can realize in future periods.
 
The economic value is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic value or the potential gross profit calculated as of September 30, 2009 will be fully realized in the future nor can we ensure in what time periods such realization may occur. 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. Assuming AEM fully executes its plan in place on September 30, 2009, without encountering operational or other issues, we anticipate the majority of the potential gross profit as of September 30, 2009 will be recognized during the first and second quarters of fiscal 2010.
 
Fiscal year ended September 30, 2008 compared with fiscal year ended September 30, 2007
 
AEM’s delivered gas business represented substantially all of AEM’s realized gross profit margin in fiscal 2008. In fiscal 2007, AEM’s delivered gas business contributed 66 percent to total realized margins during the year with asset optimization activities contributing the remaining 34 percent. The $18.4 million decrease in realized gross profit reflected:
 
  •  A $35.0 million decrease in realized asset optimization margins. As a result of less volatile natural gas market conditions experienced during fiscal 2008, AEM regularly deferred storage withdrawals and reset the associated financial instruments to increase the future economic value it could realize in future periods from its asset optimization activities. AEM recognized losses on the settlement of the associated financial instruments without corresponding storage withdrawal gains. In fiscal 2007, AEM changed its withdrawal schedule within the fiscal year and recognized substantially smaller losses from resetting its position. Increased storage fees during fiscal 2008 also contributed to the decrease.
 
  •  A $16.6 million increase in realized delivered gas margins. Gross sales volumes increased eight percent due to the successful execution of our marketing strategies. Basis gains and contract renewals increased


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  per-unit margins 19 percent. Excluding the impact of basis gains, per-unit margins increased seven percent in fiscal 2008.
 
The decrease in realized gross profit was partially offset by a $7.1 million increase in unrealized margins attributable to:
 
  •  A narrowing of the spreads between current cash prices and forward natural gas prices. This impact was partially mitigated by a 4.3 Bcf decrease in the net physical position.
 
  •  The realization of unrealized gains recorded during fiscal 2007.
 
Operating expenses increased $7.4 million primarily due to the following:
 
  •  $5.0 million increase in other administrative costs.
 
  •  $2.4 million increase associated with property taxes.
 
 
Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS is engaged in nonregulated transmission, storage and natural gas-gathering services. Its primary asset is a proprietary 21 mile pipeline located in New Orleans, Louisiana that is primarily used to aggregate gas supply for our regulated natural gas distribution division in Louisiana and for our natural gas marketing segment, and, on a more limited basis, to third parties. APS also owns or has an interest in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for additional pipeline capacity to meet customer demand during peak periods.
 
APS also engages in asset optimization activities whereby it seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. Certain of these arrangements are with regulated affiliates of the Compa