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Atmos Energy 10-Q 2009

Documents found in this filing:

  1. 10-Q
  2. Ex-12
  3. Ex-15
  4. Ex-31
  5. Ex-32
  6. Ex-32
e10vq
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
     
(Mark One)    
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended December 31, 2008
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
(Address of principal executive offices)
  75240
(Zip code)
(972) 934-9227
 
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 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 Exchange Act)  Yes o     No þ
 
Number of shares outstanding of each of the issuer’s classes of common stock, as of January 27, 2009.
 
     
Class
 
Shares Outstanding
 
No Par Value
  91,634,602
 


TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 6. Exhibits
SIGNATURE
EXHIBITS INDEX Item 6
EX-12
EX-15
EX-31
EX-32


Table of Contents

 
 
     
AEC
  Atmos Energy Corporation
AEH
  Atmos Energy Holdings, Inc.
AEM
  Atmos Energy Marketing, LLC
AOCI
  Accumulated other comprehensive income
APS
  Atmos Pipeline and Storage, LLC
Bcf
  Billion cubic feet
FASB
  Financial Accounting Standards Board
Fitch
  Fitch Ratings, Ltd.
GRIP
  Gas Reliability Infrastructure Program
Mcf
  Thousand cubic feet
MMcf
  Million cubic feet
Moody’s
  Moody’s Investors Services, Inc.
NYMEX
  New York Mercantile Exchange, Inc.
RRC
  Railroad Commission of Texas
RRM
  Rate Review Mechanism
S&P
  Standard & Poor’s Corporation
SEC
  United States Securities and Exchange Commission
SFAS
  Statement of Financial Accounting Standards
WNA
  Weather Normalization Adjustment


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Table of Contents

 
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,
    September 30,
 
    2008     2008  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 5,803,491     $ 5,730,156  
Less accumulated depreciation and amortization
    1,608,743       1,593,297  
                 
Net property, plant and equipment
    4,194,748       4,136,859  
Current assets
               
Cash and cash equivalents
    69,799       46,717  
Accounts receivable, net
    833,125       477,151  
Gas stored underground
    582,743       576,617  
Other current assets
    197,441       184,619  
                 
Total current assets
    1,683,108       1,285,104  
Goodwill and intangible assets
    738,929       739,086  
Deferred charges and other assets
    202,114       225,650  
                 
    $ 6,818,899     $ 6,386,699  
                 
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
               
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
December 31, 2008 — 91,599,495 shares;
September 30, 2008 — 90,814,683 shares
  $ 458     $ 454  
Additional paid-in capital
    1,757,834       1,744,384  
Retained earnings
    381,633       343,601  
Accumulated other comprehensive loss
    (61,849 )     (35,947 )
                 
Shareholders’ equity
    2,078,076       2,052,492  
Long-term debt
    1,719,920       2,119,792  
                 
Total capitalization
    3,797,996       4,172,284  
Current liabilities
               
Accounts payable and accrued liabilities
    815,095       395,388  
Other current liabilities
    441,481       460,372  
Short-term debt
    360,833       350,542  
Current maturities of long-term debt
    400,507       785  
                 
Total current liabilities
    2,017,916       1,207,087  
Deferred income taxes
    431,324       441,302  
Regulatory cost of removal obligation
    305,784       298,645  
Deferred credits and other liabilities
    265,879       267,381  
                 
    $ 6,818,899     $ 6,386,699  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (Unaudited)  
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 1,055,968     $ 928,177  
Regulated transmission and storage segment
    54,682       45,046  
Natural gas marketing segment
    787,495       840,717  
Pipeline, storage and other segment
    16,448       6,727  
Intersegment eliminations
    (198,261 )     (163,157 )
                 
      1,716,332       1,657,510  
Purchased gas cost
               
Natural gas distribution segment
    757,584       654,977  
Regulated transmission and storage segment
           
Natural gas marketing segment
    757,472       794,754  
Pipeline, storage and other segment
    3,903       729  
Intersegment eliminations
    (197,839 )     (162,588 )
                 
      1,321,120       1,287,872  
                 
Gross profit
    395,212       369,638  
Operating expenses
               
Operation and maintenance
    134,755       121,189  
Depreciation and amortization
    53,126       48,513  
Taxes, other than income
    44,137       41,427  
                 
Total operating expenses
    232,018       211,129  
                 
Operating income
    163,194       158,509  
Miscellaneous expense
    (301 )     (93 )
Interest charges
    38,991       36,817  
                 
Income before income taxes
    123,902       121,599  
Income tax expense
    47,939       47,796  
                 
Net income
  $ 75,963     $ 73,803  
                 
Basic net income per share
  $ 0.84     $ 0.83  
                 
Diluted net income per share
  $ 0.83     $ 0.82  
                 
Cash dividends per share
  $ 0.330     $ 0.325  
                 
Weighted average shares outstanding:
               
Basic
    90,471       89,006  
                 
Diluted
    91,066       89,608  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
 
                 
    Three Months Ended December 31  
    2008     2007  
    (Unaudited)  
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 75,963     $ 73,803  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    53,126       48,513  
Charged to other accounts
    8       23  
Deferred income taxes
    27,175       11,978  
Other
    7,683       4,406  
Net assets / liabilities from risk management activities
    (22,793 )     16,883  
Net change in operating assets and liabilities
    9,553       (94,169 )
                 
Net cash provided by operating activities
    150,715       61,437  
Cash Flows From Investing Activities
               
Capital expenditures
    (107,367 )     (94,155 )
Other, net
    (1,210 )     (1,874 )
                 
Net cash used in investing activities
    (108,577 )     (96,029 )
Cash Flows From Financing Activities
               
Net increase in short-term debt
    5,312       50,690  
Repayment of long-term debt
    (278 )     (1,741 )
Cash dividends paid
    (30,165 )     (29,178 )
Issuance of common stock
    6,075       5,970  
                 
Net cash provided by (used in) financing activities
    (19,056 )     25,741  
                 
Net increase (decrease) in cash and cash equivalents
    23,082       (8,851 )
Cash and cash equivalents at beginning of period
    46,717       60,725  
                 
Cash and cash equivalents at end of period
  $ 69,799     $ 51,874  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2008
 
1.   Nature of Business
 
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions in the service areas described below:
 
     
Division   Service Area
 
Atmos Energy Colorado-Kansas Division
  Colorado, Kansas, Missouri(1)
Atmos Energy Kentucky/Mid-States Division
  Georgia(1), Illinois(1), Iowa(1), Kentucky, Missouri(1), Tennessee, Virginia(1)
Atmos Energy Louisiana Division
  Louisiana
Atmos Energy Mid-Tex Division
  Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division
  Mississippi
Atmos Energy West Texas Division
  West Texas
 
 
(1) Denotes states where we have more limited service areas.
 
In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.
 
Our regulated transmission and storage business consists of the regulated operations of our Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands.
 
Our nonregulated businesses operate primarily in the Midwest and Southeast and include our natural gas marketing operations and pipeline, storage and other operations. These businesses are operated through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH), which is wholly owned by the Company and based in Houston, Texas.
 
Our natural gas marketing operations are conducted through Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas customers, primarily in the Southeast and Midwest and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments.


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS) and Atmos Power Systems, Inc., which are wholly owned by AEH. APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, APS manages our natural gas gathering operations. These operations did not significantly impact our financial results for the period ended December 31, 2008. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles in the United States.
 
2.   Unaudited Interim Financial Information
 
In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2008 are not indicative of our results of operations for the full 2009 fiscal year, which ends September 30, 2009.
 
 
Our accounting policies are described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, and there were no changes to those policies. However, during the three months ended December 31, 2008, we recognized a non-recurring $8.1 million increase in gross profit associated with a one-time update to our estimate for gas delivered to customers but not yet billed, resulting from base rate changes in several jurisdictions.
 
Effective October 1, 2008, the Company adopted Statement of Financial Accounting Standards (SFAS) 157, Fair Value Measurements, the measurement date requirements of SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R ), SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115 and SFAS 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. Except for the adoption of these accounting pronouncements, which are further discussed below, there were no significant changes to our accounting policies during the three months ended December 31, 2008.
 
SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosure on fair value measurements required under other accounting pronouncements but does not change existing guidance as to whether or not an instrument is carried at fair value. The adoption of this standard did not materially impact our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 4.
 
Effective October 1, 2008, the Company adopted the measurement date requirements of SFAS 158 using the remeasurement approach. Under this approach, the Company remeasured its projected benefit obligation, fair value of plan assets and its fiscal 2009 net periodic cost. In accordance with the transition rules of SFAS 158, the impact of changing the measurement date from June 30, 2008 to September 30, 2008 decreased retained earnings by $7.8 million, net of tax, decreased the unrecognized actuarial loss by $9.0 million and increased our postretirement liabilities by $3.5 million.
 
SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of the standard is to improve financial reporting by allowing entities to mitigate volatility in reported


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis. The fair value option is irrevocable, unless a new election date occurs. The adoption of this standard did not impact our financial position, results of operations or cash flows.
 
SFAS 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement requires specific disclosures regarding how and why an entity uses derivative instruments; the accounting for derivative instruments and related hedged items; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Since SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard did not have an impact on our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 3.
 
 
We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
 
Significant regulatory assets and liabilities as of December 31, 2008 and September 30, 2008 included the following:
 
                 
    December 31,
    September 30,
 
    2008     2008  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 90,394     $ 100,563  
Merger and integration costs, net
    7,480       7,586  
Deferred gas costs
    122,524       55,103  
Environmental costs
    888       980  
Rate case costs
    11,243       12,885  
Deferred franchise fees
    627       651  
Deferred income taxes, net
    343       343  
Other
    7,294       8,120  
                 
    $ 240,793     $ 186,231  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 68,226     $ 76,979  
Regulatory cost of removal obligation
    323,517       317,273  
Other
    5,569       5,639  
                 
    $ 397,312     $ 399,891  
                 
 
Currently, our authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from various state regulatory commissions.


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
The following table presents the components of comprehensive income (loss), net of related tax, for the three-month periods ended December 31, 2008 and 2007:
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (In thousands)  
 
Net income
  $ 75,963     $ 73,803  
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(3,330) and $714
    (5,433 )     1,165  
Other than temporary impairment of investments, net of tax expense of $790
    1,288        
Amortization of interest rate hedging transactions, net of tax expense of $482 and $482
    787       787  
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $(13,817) and $4,937
    (22,544 )     8,053  
                 
Comprehensive income
  $ 50,061     $ 83,808  
                 
 
Accumulated other comprehensive loss, net of tax, as of December 31, 2008 and September 30, 2008 consisted of the following unrealized gains (losses):
 
                 
    December 31,
    September 30,
 
    2008     2008  
    (In thousands)  
 
Accumulated other comprehensive loss:
               
Unrealized holding gains (losses) on investments
  $ (3,235 )   $ 910  
Treasury lock agreements
    (10,317 )     (11,104 )
Cash flow hedges
    (48,297 )     (25,753 )
                 
    $ (61,849 )   $ (35,947 )
                 
 
3.   Financial Instruments
 
We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically utilize financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Currently, we utilize financial instruments in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. However, our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment.
 
Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.
 
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. If the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2008-2009 heating season, in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 29 percent, or 25,450 MMcf of the anticipated winter flowing gas requirements. We have not designated these financial instruments as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.
 
The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk 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 SFAS 71. 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, through AEM, aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request.
 
We also perform asset optimization activities in both our natural gas marketing segment and pipeline, storage and other segment. Through asset optimization activities, we seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the financial instruments, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.
 
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 such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Future contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.
 
We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our natural gas marketing segment associated with deliveries


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 54 months. The effective portion of the unrealized gains and losses arising from the use of cash flow hedges is recorded as a component of accumulated other comprehensive income (AOCI) on the balance sheet. Amounts associated with cash flow hedges recognized in the income statement include (1) the amount of unrealized gain or loss that has been reclassified from AOCI when the hedged volumes are sold and (2) the amount of ineffectiveness associated with these hedges in the period the ineffectiveness arises.
 
We use financial instruments, designated as fair value hedges, to hedge the exposure to changes in the fair value of our natural gas inventory used in our asset optimization activities in our natural gas marketing and pipeline, storage and other segments. Therefore, gains and losses arising from these financial instruments should offset the changes in the fair value of the hedged item to the extent the hedging relationship is effective. Ineffectiveness is recognized in the income statement in the period the ineffectiveness arises.
 
Also, in our natural gas marketing segment, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.
 
Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. Our risk management committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.
 
Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on December 31, 2008, AEH had a net open position (including existing storage) of 0.1 Bcf.
 
 
Currently, we are not managing interest rate risk with financial instruments. However, in prior years, we periodically managed interest rate risk by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. These Treasury locks were settled at various times at a net loss. These realized gains and losses were recorded as a component of accumulated other comprehensive income (loss) and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these Treasury locks extend through fiscal 2035. However, the majority of the remaining amounts of these Treasury locks will be recognized as a component of interest expense through fiscal 2017.
 
 
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
 
As of December 31, 2008, our financial instruments were comprised of both long and short commodity positions, whereby a long position is a contract to purchase the commodity, while a short position is a contract


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
to sell the commodity. As of December 31, 2008, we had net long/(short) commodity contracts outstanding in the following quantities:
 
                             
        Natural
    Natural
    Pipeline,
 
    Hedge
  Gas
    Gas
    Storage
 
Contract Type   Designation   Distribution     Marketing     and Other  
        Quantity (MMcf)  
 
Commodity contracts
  Fair Value           (13,655 )     (1,883 )
    Cash Flow           44,641       (3,390 )
    Not designated     14,314       51,467       1,428  
                             
          14,314       82,453       (3,845 )
                             
 
Financial Instruments on the Balance Sheet
 
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2008 and September 30, 2008. As required by SFAS 161, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $75.8 million and $56.6 million of cash held on deposit in margin accounts as of December 31, 2008 and September 30, 2008 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our condensed consolidated balance sheet, nor will they agree to the fair value information presented for our financial instruments in Note 4.
 
                             
        Natural
    Natural
       
        Gas
    Gas
       
    Balance Sheet Location   Distribution     Marketing(1)     Total  
        (In thousands)  
 
December 31, 2008:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 115,937     $ 115,937  
Noncurrent commodity contracts
  Deferred charges and other assets           10,678       10,678  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (145,464 )     (145,464 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (1,246 )     (1,246 )
                             
Total
              (20,095 )     (20,095 )
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets           252,168       252,168  
Noncurrent commodity contracts
  Deferred charges and other assets     19       44,524       44,543  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (47,448 )     (264,359 )     (311,807 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (3,885 )     (40,836 )     (44,721 )
                             
Total
        (51,314 )     (8,503 )     (59,817 )
                             
Total Financial Instruments
      $ (51,314 )   $ (28,598 )   $ (79,912 )
                             
 
 
(1) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
                             
        Natural
    Natural
       
        Gas
    Gas
       
    Balance Sheet Location   Distribution     Marketing(1)     Total  
        (In thousands)  
 
September 30, 2008:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 110,696     $ 110,696  
Noncurrent commodity contracts
  Deferred charges and other assets           4,984       4,984  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (98,900 )     (98,900 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (206 )     (206 )
                             
Total
              16,574       16,574  
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets           115,200       115,200  
Noncurrent commodity contracts
  Deferred charges and other assets           7,071       7,071  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (58,566 )     (115,337 )     (173,903 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (5,111 )     (6,966 )     (12,077 )
                             
Total
        (63,677 )     (32 )     (63,709 )
                             
Total Financial Instruments
      $ (63,677 )   $ 16,542     $ (47,135 )
                             
 
 
(1) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.
 
Impact of Financial Instruments on the Income Statement
 
The following tables present the impact that financial instruments had on our condensed consolidated income statement, by operating segment, as applicable, for the three months ended December 31, 2008 and 2007.
 
Unrealized margins recorded in our natural gas marketing and pipeline, storage and other segments are comprised of various components, including, but not limited to, unrealized gains and losses arising from hedge ineffectiveness. Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative instrument and the hedged item and could materially affect our results of operations for the reported period. For the three months ended December 31, 2008 and 2007 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $20.4 million and $38.8 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below. Although these unrealized gains and losses are currently recorded in our income statement, they are not necessarily indicative of the economic gross profit we anticipate realizing when the underlying physical and financial transactions are settled.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Fair Value Hedges
 
The impact of commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2008 and 2007 is presented below.
 
                         
    Three Months Ended December 31, 2008  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ 25,683     $ 3,939     $ 29,622  
Fair value adjustment for natural gas inventory designated as the hedged item
    (11,860 )     (1,553 )     (13,413 )
                         
Total impact on revenue
  $ 13,823     $ 2,386     $ 16,209  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ 1,952     $     $ 1,952  
Timing ineffectiveness
    11,871       2,386       14,257  
                         
    $ 13,823     $ 2,386     $ 16,209  
                         
 
                         
    Three Months Ended December 31, 2007  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ 17,227     $ 2,123     $ 19,350  
Fair value adjustment for natural gas inventory designated as the hedged item
    17,601       1,057       18,658  
                         
Total impact on revenue
  $ 34,828     $ 3,180     $ 38,008  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ 1,956     $     $ 1,956  
Timing ineffectiveness
    32,872       3,180       36,052  
                         
    $ 34,828     $ 3,180     $ 38,008  
                         
 
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot to forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on revenue.
 
Cash Flow Hedges
 
The impact of cash flow hedges on our condensed consolidated income statement for the three months ended December 31, 2008 and 2007 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Three Months Ended December 31, 2008  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (28,244 )   $ 7,968     $ (20,276 )
Gain arising from ineffective portion of commodity contracts
          4,192             4,192  
                                 
Total impact on revenue
          (24,052 )     7,968       (16,084 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,269 )                 (1,269 )
                                 
Total Impact from Cash Flow Hedges
  $ (1,269 )   $ (24,052 )   $ 7,968     $ (17,353 )
                                 
 
                                 
    Three Months Ended December 31, 2007  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (9,254 )   $ 425     $ (8,829 )
Gain arising from ineffective portion of commodity contracts
          759             759  
                                 
Total impact on revenue
          (8,495 )     425       (8,070 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,269 )                 (1,269 )
                                 
Total Impact from Cash Flow Hedges
  $ (1,269 )   $ (8,495 )   $ 425     $ (9,339 )
                                 
 
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three months ended December 31, 2008 and 2007. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (In thousands)  
 
Increase (decrease) in fair value:
               
Treasury lock agreements
  $     $  
Forward commodity contracts
    (35,115 )     2,579  
Recognition of losses in earnings due to settlements:
               
Treasury lock agreements
    787       787  
Forward commodity contracts
    12,571       5,474  
                 
Total other comprehensive income (loss) from hedging, net of tax(1)
  $ (21,757 )   $ 8,840  
                 
 
 
(1) Utilizing an income tax rate of approximately 38 percent comprised of the effective rates in each taxing jurisdiction.

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2008:
 
                         
    Treasury
             
    Lock
    Commodity
       
    Agreements     Contracts     Total  
    (In thousands)  
 
Next twelve months
  $ (2,908 )   $ (45,271 )   $ (48,179 )
Thereafter
    (7,409 )     (3,026 )     (10,435 )
                         
Total(1)
  $ (10,317 )   $ (48,297 )   $ (58,614 )
                         
 
 
(1) Utilizing an income tax rate of approximately 38 percent comprised of the effective rates in each taxing jurisdiction.
 
Financial Instruments Not Designated as Hedges
 
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statement for the three months ended December 31, 2008 and 2007 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact to our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are 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. Accordingly, the impact of these financial instruments is excluded from this presentation.
 
                 
    Three Months
 
    Ended
 
    December 31  
    2008     2007  
    (In thousands)  
 
Natural gas marketing commodity contracts
  $ (3,832 )   $ 326  
Pipeline, storage and other commodity contracts
    (83 )     (644 )
                 
Total impact on revenue
  $ (3,915 )   $ (318 )
                 
 
4.   Fair Value Measurements
 
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) and expands disclosures about fair value measurements. This Statement does not require any new fair value measurements; rather it provides guidance on how to perform fair value measurements as required or permitted under previous accounting pronouncements.
 
We prospectively adopted the provisions of SFAS 157 on October 1, 2008 for most of the financial assets and liabilities recorded on our balance sheet at fair value. Adoption of this statement for these assets and liabilities did not have a material impact on our financial position, results of operations or cash flows.
 
In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157, which provided a one-year deferral of SFAS 157 for nonrecurring fair value measurements associated with our


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
nonfinancial assets and liabilities. Under this partial deferral, SFAS 157 will not be effective until October 1, 2009 for fair value measurements in the following areas:
 
  •  Asset retirement obligations
 
  •  Most nonfinancial assets and liabilities that may be acquired in a business combination
 
  •  Impairment analyses performed for nonfinancial assets
 
We believe the adoption of SFAS 157 to these nonfinancial areas will not have a material impact on our financial position, results of operations or cash flows.
 
In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, which clarified the application of SFAS 157 in inactive markets. This FSP did not impact our financial position, results of operations or cash flows.
 
SFAS 157 also applies to the valuation of our pension and post-retirement plan assets, and the adoption of this standard did not affect these valuations. SFAS 157 specifically excluded pension and post-retirement assets from its prescribed disclosure provisions. Accordingly, these plan assets are not included in the tabular disclosures below. However, in December 2008, the FASB issued FSP FAS 132(R)-1 — Employers’ Disclosures about Postretirement Benefit Plan Assets, which will, among other things, require disclosure about fair value measurements similar to those required by SFAS 157. This FSP will impact our annual disclosure requirements beginning in fiscal 2010.
 
 
SFAS 157 defines fair value 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 SFAS 157. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed. We 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.
 
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:
 
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities.
 
Level 2 — Pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from or corroborated by observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments such as over-the-counter options and swaps where market data for pricing is observable.
 
Level 3 — Generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. Currently, we have no assets or liabilities recorded at fair value that would qualify for Level 3 reporting.
 
Quantitative Disclosures
 
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. The following table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required under SFAS 157, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
                                         
    Quoted
    Significant
    Significant
             
    Prices in
    Other
    Other
             
    Active
    Observable
    Unobservable
    Netting of
       
    Markets
    Inputs
    Inputs
    Cash
    December 31,
 
    (Level 1)     (Level 2)     (Level 3)     Collateral(1)     2008  
    (In thousands)  
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 19     $      —     $     $ 19  
Natural gas marketing segment
          39,031             14,258       53,289  
                                         
Total financial instruments
          39,050             14,258       53,308  
Hedged portion of gas stored underground Natural gas marketing segment
    71,478                         71,478  
Pipeline, storage and other segment(2)
    6,812                         6,812  
                                         
Total gas stored underground
    78,290                         78,290  
Available-for-sale securities
    27,983                         27,983  
                                         
Total assets
  $ 106,273     $ 39,050     $     $ 14,258     $ 159,581  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 51,333     $     $     $ 51,333  
Natural gas marketing segment
    61,567       6,062             (61,567 )     6,062  
                                         
Total liabilities
  $ 61,567     $ 57,395     $     $ (61,567 )   $ 57,395  
                                         
 
 
(1) As of December 31, 2008, we had $75.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $61.6 million was used to offset financial instruments in a liability position. The remaining $14.2 million has been reflected as a financial instrument asset.
 
(2) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Our long-term debt, including current maturities, is recorded on our balance sheet at carrying value. However, SFAS 107, Disclosures about Fair Value of Financial Instruments, requires disclosure concerning the fair value of our debt. The fair value of our debt is determined using a discounted cash flow analysis based upon borrowing rates currently available to us, the remaining average maturities and our credit rating. The following table presents the carrying value and fair value of our debt as of December 31, 2008:
 
         
    December 31, 2008  
    (In thousands)  
 
Carrying Amount
  $ 2,123,334  
Fair Value
  $ 1,773,869  
 
The fair value as of December 31, 2008 was calculated utilizing discount rates ranging from 6.8 percent to 9.4 percent, remaining average maturities ranging from one to 26 years, and a credit adjustment of 6.4 percent.
 
5.   Debt
 
 
Long-term debt at December 31, 2008 and September 30, 2008 consisted of the following:
 
                 
    December 31,
    September 30,
 
    2008     2008  
    (In thousands)  
 
Unsecured 4.00% Senior Notes, due October 2009
  $ 400,000     $ 400,000  
Unsecured 7.375% Senior Notes, due 2011
    350,000       350,000  
Unsecured 10% Notes, due 2011
    2,303       2,303  
Unsecured 5.125% Senior Notes, due 2013
    250,000       250,000  
Unsecured 4.95% Senior Notes, due 2014
    500,000       500,000  
Unsecured 6.35% Senior Notes, due 2017
    250,000       250,000  
Unsecured 5.95% Senior Notes, due 2034
    200,000       200,000  
Medium term notes
               
Series A, 1995-2, 6.27%, due 2010
    10,000       10,000  
Series A, 1995-1, 6.67%, due 2025
    10,000       10,000  
Unsecured 6.75% Debentures, due 2028
    150,000       150,000  
Other term notes due in installments through 2013
    1,031       1,309  
                 
Total long-term debt
    2,123,334       2,123,612  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (2,907 )     (3,035 )
Current maturities
    (400,507 )     (785 )
                 
    $ 1,719,920     $ 2,119,792  
                 
 
As noted above, our unsecured 4.00% senior notes will mature in October 2009; accordingly, they have been classified within the current maturities of long-term debt. We are currently evaluating alternatives to refinance this debt, and we believe this refinancing effort will be successful.
 
 
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
could significantly affect our borrowing requirements. Our short-term borrowings reach their highest levels in the winter months.
 
We finance our short-term borrowing requirements through a combination of a $600 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide $1.2 billion of working capital funding. At December 31, 2008, there was $360.8 million of short-term debt outstanding, comprised of $202.9 million under our bank credit facilities and $157.9 million outstanding under our commercial paper program. At September 30, 2008, there was $350.5 million of short-term debt outstanding, comprised of $330.5 million outstanding under our bank credit facilities and $20.0 million outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.
 
 
We fund our regulated operations as needed primarily through a $600 million commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $800 million of working capital funding. The first facility is a five-year unsecured facility, expiring December 2011, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At the time this credit facility was established, borrowings under this facility were limited to $600 million. However, in September 2008, the limit on borrowings was effectively reduced to $566.7 million after one lender with a 5.55% share of the commitments ceased funding under the facility. At December 31, 2008, the total amount used under this facility was $360.8 million and $205.9 million was available.
 
The second facility is a $212.5 million unsecured 364-day facility expiring October 2009, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 1.25 percent to 2.50 percent, based on the Company’s credit ratings. At December 31, 2008, there were no borrowings outstanding under this facility.
 
The third facility is an $18 million unsecured facility expiring in March 2009 that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. At December 31, 2008, there were no borrowings outstanding under this facility.
 
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2008, our total-debt-to-total-capitalization ratio, as defined, was 57 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
 
In addition to these third-party facilities, our regulated operations had a $200 million intercompany revolving credit facility with AEH. Through December 31, 2008, this facility bore interest at the one-month LIBOR rate plus 0.20 percent. There was $40.9 million outstanding under this facility at December 31, 2008. In January 2009, this facility was replaced with a new $200 million 364 day-facility that bears interest at the lower of (i) the one-month LIBOR rate plus 0.45 percent or (ii) the marginal borrowing rate available to the Company on the date of borrowing. The marginal borrowing rate is defined as the lower of (i) a rate based upon the lower of the Prime Rate or the Eurodollar rate under the five year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved the new facility through December 31, 2009.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
On December 30, 2008, AEM and the participating banks amended and restated AEM’s former uncommitted credit facility, primarily to convert the $580 million uncommitted demand credit facility to a 364-day $375 million committed revolving credit facility and extend it to December 29, 2009.
 
The amended facility also provides the ability for AEM to increase the borrowing base up to a maximum of $450 million, subject to the approval of the participating banks; adds a swing line loan feature; adjusts the interest rate on borrowings as discussed below and increases the fees paid to reflect the facility’s conversion to a committed facility and current credit market conditions.
 
AEM will use this facility primarily to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. At AEM’s option, borrowings made under the credit facility are based on a base rate or an offshore rate, in each case plus an applicable margin. The base rate is a floating rate equal to the higher of: (a) 0.50 percent per annum above the latest federal funds rate; (b) the per annum rate of interest established by BNP Paribas from time to time as its “prime rate” or “base rate” for U.S. dollar loans; (c) an offshore rate (based on LIBOR with a one-month interest period) as in effect from time to time; and (d) the “cost of funds” rate based on an average of interest rates reported by one or more of the lenders to the administrative agent. The offshore rate is a floating rate equal to the higher of (a) an offshore rate based upon LIBOR for the applicable interest period; and (b) a “cost of funds” rate referred to above. In the case of both base rate and offshore rate loans, the applicable margin ranges from 2.250 percent to 2.625 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.
 
At December 31, 2008, there were no borrowings outstanding under this credit facility. However, at December 31, 2008, AEM letters of credit totaling $100.0 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $177.8 million at December 31, 2008.
 
AEM is required by the financial covenants in this facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At December 31, 2008, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.48 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $75 million to $112.5 million. As defined in the financial covenants, at December 31, 2008, AEM’s net working capital was $215.2 million and its tangible net worth was $240.2 million.
 
To supplement borrowings under this facility, through December 31, 2008, AEM had a $200 million intercompany demand credit facility with AEH, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Amounts outstanding under this facility are subordinated to AEM’s committed credit facility. There were no borrowings outstanding under this facility at December 31, 2008. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent.
 
Finally, through December 31, 2008, AEH had a $200 million intercompany demand credit facility with AEC, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. There were no borrowings outstanding under this facility at December 31, 2008. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved the new facility through December 31, 2009.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
On December 4, 2006, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in new common stock and/or debt securities. As of December 31, 2008, we had approximately $450 million of availability remaining under the registration statement. Due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we are permitted to issue a total of approximately $200 million of equity securities and $250 million of senior debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard & Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until we received an investment grade rating from all of the three credit rating agencies.
 
 
In addition to the financial covenants described above, our debt instruments contain various covenants that are usual and customary for debt instruments of these types.
 
Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.
 
Further, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate.
 
Finally, AEM’s credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2. We have no other triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.
 
We were in compliance with all of our debt covenants as of December 31, 2008. If we were unable to comply with our debt covenants, we may be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
6.   Earnings Per Share
 
Basic and diluted earnings per share for the three months ended December 31, 2008 and 2007 are calculated as follows:
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (In thousands, except per share amounts)  
 
Net income
  $ 75,963     $ 73,803  
                 
Denominator for basic income per share — weighted average common shares
    90,471       89,006  
Effect of dilutive securities:
               
Restricted and other shares
    559       496  
Stock options
    36       106  
                 
Denominator for diluted income per share — weighted average common shares
    91,066       89,608  
                 
Income per share — basic
  $ 0.84     $ 0.83  
                 
Income per share — diluted
  $ 0.83     $ 0.82  
                 
 
There were approximately 231,000 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2008. There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2007 as their exercise price was less than the average market price of the common stock during that period.
 
7.   Interim Pension and Other Postretirement Benefit Plan Information
 
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2008 and 2007 are presented in the following table. All of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
                                 
    Three Months Ended December 31  
    Pension Benefits     Other Benefits  
    2008     2007     2008     2007  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 3,703     $ 3,878     $ 2,946     $ 3,341  
Interest cost
    7,554       6,736       3,520       2,912  
Expected return on assets
    (6,238 )     (6,310 )     (573 )     (715 )
Amortization of transition asset
                378       378  
Amortization of prior service cost
    (183 )     (171 )            
Amortization of actuarial loss
    955       1,926              
                                 
Net periodic pension cost
  $ 5,791     $ 6,059     $ 6,271     $ 5,916  
                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2008 and 2007 are as follows:
 
                                 
    Pension Benefits     Other Benefits  
    2008     2007     2008     2007  
 
Discount rate
    7.57 %     6.30 %     7.57 %     6.30 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %
Expected return on plan assets
    8.25 %     8.25 %     5.00 %     5.00 %
 
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act (PPA), we determined the funded status of our plans as of January 1, 2009. Based upon this valuation, we expect we will be required to contribute less than $25 million to our pension plans by September 15, 2009.
 
We contributed $2.6 million to our other post-retirement benefit plans during the three months ended December 31, 2008. We expect to contribute a total of approximately $10 million to these plans during fiscal 2009.
 
8.   Commitments and Contingencies
 
 
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 12 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2008. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
In addition, we are involved in other litigation and environmental-related matters or claims that arise in the ordinary course of our business. While the ultimate results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we believe the final outcome of such litigation and response actions will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
 
AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2008, AEM was committed to purchase 77.6 Bcf within one year, 30.2 Bcf within one to three years and 1.2 Bcf after three years under indexed contracts. AEM is committed to purchase 1.6 Bcf within one year under fixed price contracts with prices ranging from $4.14 to $13.20 per Mcf. Purchases under these contracts totaled $527.5 million and $572.0 million for the three months ended December 31, 2008 and 2007.
 
Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of December 31, 2008 are as follows (in thousands):
 
         
2009
  $ 243,310  
2010
    90,146  
2011
    8,240  
2012
    8,006  
2013
    8,102  
Thereafter
    2,727  
         
    $ 360,531  
         
 
 
During the three months ended December 31, 2008, we concluded annual rate filing mechanisms we had filed in our Mid-Tex and West Texas service areas. As of December 31, 2008, rate cases were in progress in our City of Dallas and Tennessee service areas. These regulatory proceedings are discussed in further detail in Management’s Discussion and Analysis — Recent Ratemaking Developments.
 
9.   Concentration of Credit Risk
 
Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. During the three months ended December 31, 2008, there were no material changes in our concentration of credit risk.
 
10.   Segment Information
 
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage business as well as other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local distribution companies and industrial customers primarily in the Midwest and Southeast. Additionally, we provide natural gas transportation and storage services to certain of our natural gas distribution operations and to third parties.
 
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 the Atmos Pipeline — Texas Division.
 
  •  The natural gas marketing segment, which includes a variety of nonregulated natural gas management services.
 
  •  The pipeline, storage and other segment, which includes our nonregulated natural gas transmission and storage services.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. We evaluate performance based on net income or loss of the respective operating units.
 
Income statements for the three-month periods ended December 31, 2008 and 2007 by segment are presented in the following tables:
 
                                                 
    Three Months Ended December 31, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,055,772     $ 30,222     $ 616,844     $ 13,494     $     $ 1,716,332  
Intersegment revenues
    196       24,460       170,651       2,954       (198,261 )      
                                                 
      1,055,968       54,682       787,495       16,448       (198,261 )     1,716,332  
Purchased gas cost
    757,584             757,472       3,903       (197,839 )     1,321,120  
                                                 
Gross profit
    298,384       54,682       30,023       12,545       (422 )     395,212  
Operating expenses
                                               
Operation and maintenance
    97,994       27,569       8,516       1,184       (508 )     134,755  
Depreciation and amortization
    47,139       4,955       401       631             53,126  
Taxes, other than income
    40,746       2,788       593       10             44,137  
                                                 
Total operating expenses
    185,879       35,312       9,510       1,825       (508 )     232,018  
                                                 
Operating income
    112,505       19,370       20,513       10,720       86       163,194  
Miscellaneous income (expense)
    3,121       815       301       2,161       (6,699 )     (301 )
Interest charges
    32,887       8,079       3,902       736       (6,613 )     38,991  
                                                 
Income before income taxes
    82,739       12,106       16,912       12,145             123,902  
Income tax expense
    32,606       4,445       6,337       4,551             47,939  
                                                 
Net income
  $ 50,133     $ 7,661     $ 10,575     $ 7,594     $     $ 75,963  
                                                 
Capital expenditures
  $ 89,003     $ 5,060     $ 29     $ 13,275     $     $ 107,367  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Three Months Ended December 31, 2007  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 928,029     $ 22,437     $ 702,722     $ 4,322     $     $ 1,657,510  
Intersegment revenues
    148       22,609       137,995       2,405       (163,157 )      
                                                 
      928,177       45,046       840,717       6,727       (163,157 )     1,657,510  
Purchased gas cost
    654,977             794,754       729       (162,588 )     1,287,872  
                                                 
Gross profit
    273,200       45,046       45,963       5,998       (569 )     369,638  
Operating expenses
                                               
Operation and maintenance
    97,247       15,432       7,877       1,288       (655 )     121,189  
Depreciation and amortization
    42,832       4,916       387       378             48,513  
Taxes, other than income
    35,618       2,444       3,000       365             41,427  
                                                 
Total operating expenses
    175,697       22,792       11,264       2,031       (655 )     211,129  
                                                 
Operating income
    97,503       22,254       34,699       3,967       86       158,509  
Miscellaneous income (expense)
    476       174       796       2,028       (3,567 )     (93 )
Interest charges
    31,214       7,071       1,314       699       (3,481 )     36,817  
                                                 
Income before income taxes
    66,765       15,357       34,181       5,296             121,599  
Income tax expense
    26,601       5,510       13,581       2,104             47,796  
                                                 
Net income
  $ 40,164     $ 9,847     $ 20,600     $ 3,192     $     $ 73,803  
                                                 
Capital expenditures
  $ 84,313     $ 8,382     $ 31     $ 1,429     $     $ 94,155  
                                                 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at December 31, 2008 and September 30, 2008 by segment is presented in the following tables:
 
                                                 
    December 31, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
Property, plant and equipment, net
  $ 3,533,249     $ 584,882     $ 7,387     $ 69,230     $     $ 4,194,748  
Investment in subsidiaries
    466,443             (2,096 )           (464,347 )      
Current assets
                                               
Cash and cash equivalents
    36,931             32,052       816             69,799  
Assets from risk management activities
                41,016       24,608       (25,549 )     40,075  
Other current assets
    1,151,129       27,029       413,676       62,728       (81,328 )     1,573,234  
Intercompany receivables
    534,996                   142,753       (677,749 )      
                                                 
Total current assets
    1,723,056       27,029       486,744       230,905       (784,626 )     1,683,108  
Intangible assets
                1,931                   1,931  
Goodwill
    569,920       132,367       24,282       10,429             736,998  
Noncurrent assets from risk management activities
    19             13,214       44       (44 )     13,233  
Deferred charges and other assets
    166,669       6,718       853       14,641             188,881  
                                                 
    $ 6,459,356     $ 750,996     $ 532,315     $ 325,249     $ (1,249,017 )   $ 6,818,899  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 2,078,076     $ 137,805     $ 102,735     $ 225,903     $ (466,443 )   $ 2,078,076  
Long-term debt
    1,719,396                   524             1,719,920  
                                                 
Total capitalization
    3,797,472       137,805       102,735       226,427       (466,443 )     3,797,996  
Current liabilities
                                               
Current maturities of long-term debt
    400,000                   507             400,507  
Short-term debt
    401,683                         (40,850 )     360,833  
Liabilities from risk management activities
    47,448             30,596       937       (25,549 )     53,432  
Other current liabilities
    863,569       8,330       291,154       78,442       (38,351 )     1,203,144  
Intercompany payables
          535,064       142,685             (677,749 )      
                                                 
Total current liabilities
    1,712,700       543,394       464,435       79,886       (782,499 )     2,017,916  
Deferred income taxes
    385,547       65,874       (35,664 )     15,598       (31 )     431,324  
Noncurrent liabilities from risk management activities
    3,885             122             (44 )     3,963  
Regulatory cost of removal obligation
    305,784                               305,784  
Deferred credits and other liabilities
    253,968       3,923       687       3,338             261,916  
                                                 
    $ 6,459,356     $ 750,996     $ 532,315     $ 325,249     $ (1,249,017 )   $ 6,818,899  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    September 30, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
Property, plant and equipment, net
  $ 3,483,556     $ 585,160     $ 7,520     $ 60,623     $     $ 4,136,859  
Investment in subsidiaries
    463,158             (2,096 )           (461,062 )      
Current assets
                                               
Cash and cash equivalents
    30,878             9,120       6,719             46,717  
Assets from risk management activities
                69,008       20,239       (20,956 )     68,291  
Other current assets
    774,933       18,396       411,648       56,791       (91,672 )     1,170,096  
Intercompany receivables
    578,833                   135,795       (714,628 )      
                                                 
Total current assets
    1,384,644       18,396       489,776       219,544       (827,256 )     1,285,104  
Intangible assets
                2,088                   2,088  
Goodwill
    569,920       132,367       24,282       10,429             736,998  
Noncurrent assets from risk management activities
                5,473                   5,473  
Deferred charges and other assets
    195,985       11,212       1,182       11,798             220,177  
                                                 
    $ 6,097,263     $ 747,135     $ 528,225     $ 302,394     $ (1,288,318 )   $ 6,386,699  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 2,052,492     $ 130,144     $ 114,559     $ 218,455     $ (463,158 )   $ 2,052,492  
Long-term debt
    2,119,267                   525             2,119,792  
                                                 
Total capitalization
    4,171,759       130,144       114,559       218,980       (463,158 )     4,172,284  
Current liabilities
                                               
Current maturities of long-term debt
                      785             785  
Short-term debt
    385,592             6,500             (41,550 )     350,542  
Liabilities from risk management activities
    58,566             20,688       616       (20,956 )     58,914  
Other current liabilities
    538,777       7,053       236,217       62,796       (47,997 )     796,846  
Intercompany payables
          543,384       171,244             (714,628 )      
                                                 
Total current liabilities
    982,935       550,437       434,649       64,197       (825,131 )     1,207,087  
Deferred income taxes
    384,860       62,720       (21,936 )     15,687       (29 )     441,302  
Noncurrent liabilities from risk management activities
    5,111             258                   5,369  
Regulatory cost of removal obligation
    298,645                               298,645  
Deferred credits and other liabilities
    253,953       3,834       695       3,530             262,012  
                                                 
    $ 6,097,263     $ 747,135     $ 528,225     $ 302,394     $ (1,288,318 )   $ 6,386,699  
                                                 

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The Board of Directors and Shareholders of
Atmos Energy Corporation
 
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of December 31, 2008, and the related condensed consolidated statements of income and cash flows for the three-month periods ended December 31, 2008 and 2007. These financial statements are the responsibility of the Company’s management.
 
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
 
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
 
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2008, and the related consolidated statements of income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 18, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2008, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
/s/  Ernst & Young LLP
 
Dallas, Texas
February 3, 2009


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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2008.
 
 
The statements contained in this Quarterly Report on Form 10-Q 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, which are discussed in more detail in our Annual Report on Form 10-K for the year ended September 30, 2008, 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 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, 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.
 
 
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.


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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 the Atmos Pipeline — Texas Division,
 
  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services and
 
  •  the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.
 
 
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
 
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008 and include the following:
 
  •  Regulation
 
  •  Revenue Recognition
 
  •  Allowance for Doubtful Accounts
 
  •  Derivatives and Hedging Activities
 
  •  Impairment Assessments
 
  •  Pension and Other Postretirement Plans
 
Our critical accounting policies are reviewed quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the three months ended December 31, 2008.


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RESULTS OF OPERATIONS
 
The following table presents our consolidated financial highlights for the three months ended December 31, 2008 and 2007:
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (In thousands, except per share data)  
 
Operating revenues
  $ 1,716,332     $ 1,657,510  
Gross profit
    395,212       369,638  
Operating expenses
    232,018       211,129  
Operating income
    163,194       158,509  
Miscellaneous expense
    (301 )     (93 )
Interest charges
    38,991       36,817  
Income before income taxes
    123,902       121,599  
Income tax expense
    47,939       47,796  
Net income
  $ 75,963     $ 73,803  
Diluted net income per share
  $ 0.83     $ 0.82  
 
Our consolidated net income during the three months ended December 31, 2008 and 2007 was earned in each of our business segments as follows:
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 50,133     $ 40,164     $ 9,969  
Regulated transmission and storage segment
    7,661       9,847       (2,186 )
Natural gas marketing segment
    10,575       20,600       (10,025 )
Pipeline, storage and other segment
    7,594       3,192       4,402  
                         
Net income
  $ 75,963     $ 73,803     $ 2,160  
                         
 
The following tables segregate our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 57,794     $ 50,011     $ 7,783  
Nonregulated operations
    18,169       23,792       (5,623 )
                         
Consolidated net income
  $ 75,963     $ 73,803     $ 2,160  
                         
Diluted EPS from regulated operations
  $ 0.63     $ 0.56     $ 0.07  
Diluted EPS from nonregulated operations
    0.20       0.26       (0.06 )
                         
Consolidated diluted EPS
  $ 0.83     $ 0.82     $ 0.01  
                         
 
The following summarizes the results of our operations and other significant events for the three months ended December 31, 2008:
 
  •  Regulated operations generated 76 percent of our net income during the three months ended December 31, 2008 compared to 68 percent during the three months ended December 31, 2007. The $7.8 million increase in our regulated operations net income primarily reflects favorable ratemaking


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  activity coupled with higher transportation and priority reservation fees, which were partially offset by an 11 percent increase in operating expenses.
 
  •  Nonregulated operations contributed 24 percent of net income during the three months ended December 31, 2008 compared to 32 percent during the three months ended December 31, 2007. The $5.6 million decrease in our nonregulated operations net income primarily reflects a decrease in unrealized margins partially offset by favorable asset optimization margins.
 
  •  For the three months ended December 31, 2008, we generated $150.7 million in operating cash flow compared with $61.4 million for the three months ended December 31, 2007, primarily reflecting the timing of accounts receivable collections and purchases of gas stored underground.
 
  •  During the first quarter of fiscal 2009, we entered into two new 364-day committed credit facilities that will provide $587.5 million to help fund our natural gas purchases and working capital needs.
 
Three Months Ended December 31, 2008 compared with Three Months Ended December 31, 2007
 
 
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 of return 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.
 
Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 90 percent of our residential and commercial meters in the following states for the following time periods:
 
     
Georgia
  October – May
Kansas
  October – May
Kentucky
  November – April
Louisiana
  December – March
Mississippi
  November – April
Tennessee
  November – April
Texas: Mid-Tex
  November – April
Texas: West Texas
  October – May
Virginia
  January – December
 
Our 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 associated tax expense as a component of taxes, other than income. Although changes in revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income. Timing differences exist between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. The effect of these timing differences can be significant in periods of volatile gas prices, particularly in our Mid-Tex Division. These timing differences may favorably or unfavorably affect net income; however, these amounts should offset over time with no permanent impact on net income.


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Beginning January 1, 2009, changes in our franchise fee agreements will become effective that should significantly reduce the impact of this timing difference on a prospective basis.
 
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.
 
 
Financial and operational highlights for our natural gas distribution segment for the three months ended December 31, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 298,384     $ 273,200     $ 25,184  
Operating expenses
    185,879       175,697       10,182  
                         
Operating income
    112,505       97,503       15,002  
Miscellaneous income
    3,121       476       2,645  
Interest charges
    32,887       31,214       1,673  
                         
Income before income taxes
    82,739       66,765       15,974  
Income tax expense
    32,606       26,601       6,005  
                         
Net income
  $ 50,133     $ 40,164     $ 9,969  
                         
Consolidated natural gas distribution sales volumes — MMcf
    91,446       84,767       6,679  
Consolidated natural gas distribution transportation volumes — MMcf
    34,336       33,749       587  
                         
Total consolidated natural gas distribution throughput — MMcf
    125,782       118,516       7,266  
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.45     $ 0.44     $ 0.01  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 8.28     $ 7.73     $ 0.55  
 
The following table shows our operating income by natural gas distribution division for the three months ended December 31, 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.
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands)  
 
Mid-Tex
  $ 52,678     $ 50,225     $ 2,453  
Kentucky/Mid-States
    19,025       14,168       4,857  
Louisiana
    14,584       11,932       2,652  
West Texas
    8,013       4,976       3,037  
Mississippi
    8,435       7,829       606  
Colorado-Kansas
    8,601       6,688       1,913  
Other
    1,169       1,685       (516 )
                         
Total
  $ 112,505     $ 97,503     $ 15,002  
                         


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The $25.2 million increase in natural gas distribution gross profit primarily reflects a $15.3 million increase in rates. The net increase in rates primarily was attributable to the Mid-Tex Division, which increased $11.3 million 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 (the Settled Cities). The current year period also reflects $4.0 million in rate adjustments primarily in Georgia, Kansas, Louisiana and West Texas. In addition, the increase in gross profit reflects a six percent increase in distribution throughput. Finally, gross profit increased $8.1 million compared with the prior-year quarter due 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.
 
Partially offsetting these increases was a decrease of approximately $0.3 million in revenue-related taxes primarily due to lower revenues, on which the tax is calculated, in the current-year quarter compared to the prior-year quarter. This decrease, combined with an $8.1 million quarter-over-quarter increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in an $8.4 million decrease in operating income when compared with the prior-year quarter.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $10.2 million.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $2.2 million, primarily due to a $2.1 million noncash charge to impair certain available-for-sale investments due to the recent deterioration of the financial markets.
 
Depreciation and amortization expense increased $4.3 million for the first quarter of fiscal 2009 compared with first quarter of fiscal 2008. The increase primarily was attributable to additional assets placed in service during the current-year period.
 
Interest charges allocated to the natural gas distribution segment increased $1.7 million due to higher average short-term debt balances, interest rates and commitment fees experienced during the current-year quarter compared to the prior-year quarter. These increases are associated with the recent adverse conditions in the credit markets.
 
 
Significant ratemaking developments that occurred during the three months ended December 31, 2008 are discussed below. The amounts described below represent the gross revenues that were requested or received in each rate filing, which may not necessarily reflect the increase in operating income obtained, as certain operating costs may have increased as a result of a commission’s final ruling.
 
Annual Rate Filing Mechanisms
 
In April 2008, the Mid-Tex Division filed its first RRM with the Settled Cities. The filing requested an increase in rates of $33.3 million on a system-wide basis, of which $26.7 million applied to the Settled Cities. We reached an agreement with representatives of the Settled Cities to increase rates $20.0 million on a system-wide basis, which were implemented beginning in November 2008. The impact to the Mid-Tex Division for the Settled Cities is approximately $16.0 million.
 
In the West Texas Division, the Company reached an agreement with representatives of the West Texas Cities with respect to its RRM filing to increase rates a total of $3.9 million. The $3.9 million will be collected through the true-up portion of the RRM tariff rates over a 91/2 month period beginning in November 2008.
 
In May 2008, the City of Lubbock approved its Conservation and Customer Value Plan (CCVP), which contained an annual rate review mechanism that would adjust rates to reflect changes in the West Texas Division’s cost of service and rate base. The West Texas Division filed its annual review filing under the CCVP in June 2008. The Company and city officials were unable to reach a mutually agreeable settlement,


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and in December 2008, the City Council passed an ordinance withdrawing the CCVP tariff. The Company is currently evaluating it options.
 
In December 2008, we filed our TransLa annual rate stabilization clause with the Louisiana Public Service Commission requesting an increase of $0.9 million. The filing was for the test year ended September 30, 2008. We anticipate final resolution of this proceeding by March 2009.
 
In September 2008, we filed our Mississippi stable rate filing with the Mississippi Public Service Commission (MPSC) requesting an increase of $3.5 million. In January 2009, we withdrew this request after we were unable to reach a mutually agreeable settlement with the MPSC.
 
GRIP Filings
 
In May 2008, the Mid-Tex Division made a GRIP filing seeking a $10.3 million increase on a system-wide basis. However, this filing is only applicable to the City of Dallas and the Mid-Tex environs and seeks a $1.8 million increase for customers in those service areas only. Rates were approved for this filing in December 2008 and will be implemented in February 2009.
 
Rate Case Filings
 
In October 2008, our Kentucky/Mid-States Division filed a rate case with the Tennessee Regulatory Authority seeking a rate increase of $6.3 million. The filing includes a rate base of approximately $191.0 million, a 50/50 capital structure and requests an authorized return on equity of 11.7 percent. We are currently working through discovery on the case. In January 2009, the Consumer Advocate and Protection Division recommended a decrease in rates of $3.7 million. Any adjustment to rates is expected to be implemented no later than April 2009.
 
In November 2008, the Mid-Tex Division filed a statement of intent to increase rates for customers within the City of Dallas by $9.1 million. The City of Dallas suspended the filing on December 10, 2008 and is expected to take final action on the filing by the end of February 2009.
 
Other Ratemaking Activity
 
In May 2007, our Mid-Tex Division filed for a 36-month gas contract review filing. This filing is mandated by prior Railroad Commission of Texas (RRC) orders and relates to the prudency of gas purchases made from November 2003 through October 2006, which total approximately $2.7 billion. The intervening parties recommended disallowances ranging from $58 million to $89 million. A hearing was held at the RRC in September 2008. In December 2008, a proposal for decision was issued by the Hearing Examiner recommending no gas cost disallowance. The RRC is expected to render it decision in February 2009.
 
 
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 and lending arrangements and sales of inventory on hand.
 
Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.


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Financial and operational highlights for our regulated transmission and storage segment for the three months ended December 31, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 24,352     $ 22,388     $ 1,964  
Third-party transportation
    25,366       18,232       7,134  
Storage and park and lend services
    2,357       2,039       318  
Other
    2,607       2,387       220  
                         
Gross profit
    54,682       45,046       9,636  
Operating expenses
    35,312       22,792       12,520  
                         
Operating income
    19,370       22,254       (2,884 )
Miscellaneous income
    815       174       641  
Interest charges
    8,079       7,071       1,008  
                         
Income before income taxes
    12,106       15,357       (3,251 )
Income tax expense
    4,445       5,510       (1,065 )
                         
Net income
  $ 7,661     $ 9,847     $ (2,186 )
                         
Gross pipeline transportation volumes — MMcf
    192,172       188,864       3,308  
                         
Consolidated pipeline transportation volumes — MMcf
    135,858       136,200       (342 )
                         
 
The $9.6 million increase in gross profit primarily was attributable to a $3.7 million increase resulting from higher transportation fees on through-system deliveries due to market conditions and a $3.3 million increase from higher priority reservation fees. The improvement in gross profit also reflects a $1.4 million increase due to our 2006 and 2007 GRIP filings. Throughput was flat as increased city-gate, electrical generation and HUB deliveries offset decreased Barnett Shale receipts and industrial deliveries.
 
Operating expenses increased $12.5 million primarily due to increased employee and pipeline maintenance costs.
 
 
Our natural gas marketing activities are conducted through Atmos Energy Marketing, LLC (AEM). AEM aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues received for services we deliver.
 
Our asset optimization activities seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost


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alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time.
 
AEM continually manages its net physical position to attempt to increase in the future the potential economic gross 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 execution of 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.
 
 
Financial and operational highlights for our natural gas marketing segment for the three months ended December 31, 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 gas 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 (spot) and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.
 


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    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Delivered gas
  $ 18,553     $ 18,173     $ 380  
Asset optimization
    36,939       (525 )     37,464  
                         
      55,492       17,648       37,844  
Unrealized margins
    (25,469 )     28,315       (53,784 )
                         
Gross profit
    30,023       45,963       (15,940 )
Operating expenses
    9,510       11,264       (1,754 )
                         
Operating income
    20,513       34,699       (14,186 )
Miscellaneous income
    301       796       (495 )
Interest charges
    3,902       1,314       2,588  
                         
Income before income taxes
    16,912       34,181       (17,269 )
Income tax expense
    6,337       13,581       (7,244 )
                         
Net income
  $ 10,575     $ 20,600     $ (10,025 )
                         
Gross natural gas marketing sales volumes — MMcf
    110,658       108,709       1,949  
                         
Consolidated natural gas marketing sales volumes — MMcf
    93,308       96,206       (2,898 )
                         
Net physical position (Bcf)
    16.3       17.7       (1.4 )
                         
 
The $15.9 million decrease in our natural gas marketing segment’s gross profit primarily was driven by a $53.8 million decrease in unrealized margins. This decrease primarily reflects the recognition of previously unrecognized margins in realized margins, as a result of cycling more gas from storage and settlement of the corresponding financial instruments. This decrease was partially offset by a smaller widening during the current quarter compared with the prior-year quarter of the spreads between current cash prices and forward natural gas prices as cash prices have declined more rapidly than prices for the forward delivery months.
 
The decrease in unrealized margins was partially offset by a $37.5 million increase in asset optimization margins. In the prior year, as a result of a less volatile natural gas market, AEM elected to defer storage withdrawals and reset the corresponding financial instruments to increase the potential gross profit it could realize in future periods from its asset optimization activities. During the quarter, AEM realized substantially all of the gains it had captured as a result of deferring storage in prior periods as the storage was withdrawn and the corresponding financial instruments were settled.
 
In addition, the decrease in gross profit generated from unrealized margins was also partially offset by a $0.4 million increase in realized delivered gas margins. The increase was largely attributable to higher gross sales volumes combined with slightly higher per-unit margins, compared with the prior-year quarter.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, decreased $1.8 million primarily due to the absence in the current year of $2.4 million related to tax matters incurred in the prior-year quarter partially offset by an increase in employee and other administrative costs.
 
Economic Gross Profit
 
AEM monitors the impact of its asset optimization efforts by estimating the gross profit, before associated storage fees, that it captured through the purchase and sale of physical natural gas and the execution of the

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associated financial instruments. This economic gross profit, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement is referred to as the potential gross profit.(1) The following table presents AEM’s economic gross profit and its potential gross profit at December 31, 2008 and September 30, 2008.
 
                                 
                Associated Net
       
    Net Physical
    Economic
    Unrealized
    Potential Gross
 
Period Ending
  Position     Gross Profit     Gain     Profit(1)  
    (Bcf)     (In millions)     (In millions)     (In millions)  
 
December 31, 2008
    16.3     $ 20.7     $ 4.8     $ 15.9  
September 30, 2008
    8.0     $ 48.5     $ 36.4     $ 12.1  
 
 
(1) Potential gross profit represents the increase in AEM’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include storage and other operating expenses and increased 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 gross profit 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 our investors a more comprehensive view of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.
 
As of December 31, 2008, based upon AEM’s planned inventory withdrawal schedule and associated planned settlement of financial instruments, the economic gross profit was $20.7 million. This amount will be reduced by $4.8 million of net unrealized gains recorded in the financial statements as of December 31, 2008 that will reverse when the inventory is withdrawn and the accompanying financial instruments are settled. Therefore, the potential gross profit was $15.9 million at December 31, 2008.
 
The $3.8 million increase in potential gross profit as compared to September 30, 2008, is comprised of a $31.6 million decrease in unrealized gains and an unfavorable movement in the market prices used to value our natural gas storage inventory, partially offset by a $27.8 million decrease in the economic gross profit, principally due to the withdrawal of physical inventory and the realization of financial instruments settled during the period. During this process, AEM increased its net physical position 8.3 Bcf; however, the captured spreads were lower than in prior periods.
 
The economic gross profit 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 gross profit or the potential gross profit calculated as of December 31, 2008 will be fully realized in the future nor can we predict 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 December 31, 2008, without encountering operational or other issues, we anticipate that approximately half of the potential gross profit as of December 31, 2008 will be recognized during the second quarter of fiscal 2009.
 
 
Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS) and Atmos Power Systems, Inc., which are each wholly owned by Atmos Energy Holdings, Inc.
 
APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, beginning in fiscal 2006, APS initiated activities in the natural gas gathering business. As of December 31, 2008, these activities did not represent a significant portion of this segment’s operations.


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Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.
 
Results for this segment are primarily impacted by seasonal weather patterns and volatility in the natural gas markets. Additionally, this segment’s results include an unrealized component as APS hedges its risk associated with its asset optimization activities.
 
 
Financial and operational highlights for our pipeline, storage and other segment for the three months ended December 31, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    December 31  
    2008     2007     Change  
    (In thousands)  
 
Storage and transportation services
  $ 2,988     $ 2,981     $ 7  
Asset optimization
    4,340       (231 )     4,571  
Other
    2,443       875       1,568  
Unrealized margins
    2,774       2,373       401  
                         
Gross profit
    12,545       5,998       6,547  
Operating expenses
    1,825       2,031       (206 )
                         
Operating income
    10,720       3,967       6,753  
Miscellaneous income
    2,161       2,028       133  
Interest charges
    736       699       37  
                         
Income before income taxes
    12,145       5,296       6,849  
Income tax expense
    4,551       2,104       2,447  
                         
Net income
  $ 7,594     $ 3,192     $ 4,402  
                         
 
Gross profit from our pipeline, storage and other segment increased $6.5 million primarily due to a $4.6 million increase in asset optimization margins as a result of strong transportation margins earned on excess pipeline capacity under certain asset management agreements in the current-year period coupled with a sale of inventory in the quarter.
 
Operating expenses for the three months ended December 31, 2008 were consistent with the prior-year quarter.
 
 
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
 
The primary means we use to fund our working capital needs and growth is to utilize internally generated funds and to access the commercial paper markets. Recent adverse developments in global financial and credit markets have made it more difficult and more expensive for the Company to access the short-term capital markets, including the commercial paper market, to satisfy our liquidity requirements. Consequently, during the quarter, we experienced higher than normal borrowings under our five-year credit facility used to backstop our commercial paper program in lieu of commercial paper borrowings to fund our working capital needs. At December 31, 2008, the total amount used under this facility was $360.8 million and $205.9 million was available. However, subsequent to quarter end, credit market conditions have improved, both as to availability


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and interest rates, and we have been able to obtain sufficient levels of commercial paper to substantially reduce direct borrowings on this facility.
 
During the first quarter of fiscal 2009, we strengthened the sources of our liquidity with the execution of two new committed credit facilities. In October 2008, we replaced our former $300 million 364-day committed credit facility with a new facility that will allow borrowings up to $212.5 million and expires in October 2009. In December 2008, we converted AEM’s former $580 million uncommitted credit facility to a $375 million committed credit facility that will expire in December 2009. As a result of executing these new agreements, we have a total of $1.2 billion available to us under four committed credit facilities. As of December 31, 2008, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $614 million.
 
Our $18 million unsecured committed credit facility expires in March 2009. We are working to renew this credit facility and we believe these renewal efforts will be successful. Additionally, our $400 million 4.00% unsecured senior notes will mature in October 2009. We are currently evaluating alternatives to finance this debt, and we believe we will be able to successfully refinance these notes.
 
We believe the liquidity provided by our committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2009.
 
 
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
 
 
Period-over-period changes in our operating cash flows primarily are attributable to changes in net income and working capital changes, particularly within our natural gas distribution segment resulting from the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
 
For the three months ended December 31, 2008, we generated operating cash flow of $150.7 million from operating activities compared with $61.4 million for the three months ended December 31, 2007. Period over period, the $89.3 million increase primarily was attributable to favorable changes in accounts receivable and gas stored underground, which increased operating cash flow by $83.9 million. These changes reflect improved timing of accounts receivable collections and purchases of natural gas to fill our storage facilities.
 
 
In recent years, a substantial portion of our cash resources has been used to fund growth projects, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
 
Capital expenditures for fiscal 2009 are expected to range from $500 million to $515 million. For the three months ended December 31, 2008, capital expenditures were $107.4 million compared with $94.2 million for the three months ended December 31, 2007. The increase in capital spending primarily reflects spending


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for nonregulated growth projects and increased levels of regulatory compliance-related spending in the Mid-Tex Division.
 
 
For the three months ended December 31, 2008, our financing activities reflected a use of cash of $19.1 million. For the three months ended December 31, 2007, financing activities provided $25.7 million. Our significant financing activities for the three months ended December 31, 2008 and 2007 are summarized as follows:
 
  •  During the three months ended December 31, 2008, we increased our borrowings by a net $5.3 million under our short-term credit facilities compared with $50.7 million in the prior-year quarter. The reduction in the net borrowings reflects the timing of the use of our line of credit to finance natural gas purchases and working capital.
 
  •  We repaid $0.3 million of long-term debt during the three months ended December 31, 2008 compared with $1.7 million during the three months ended December 31, 2007. Payments in both periods reflected regularly scheduled payments in accordance with our various debt agreements.
 
  •  During the three months ended December 31, 2008, we paid $30.2 million in cash dividends compared with $29.2 million for the three months ended December 31, 2007. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.325 per share during the three months ended December 31, 2007 to $0.33 per share during the three months ended December 31, 2008 combined with new share issuances under our various equity plans.
 
  •  During the three months ended December 31, 2008, we issued 0.3 million shares of common stock under our various equity plans, which generated net proceeds of $6.1 million. In addition, we granted 0.5 million shares of common stock under our 1998 Long-Term Incentive Plan.
 
The following table summarizes our share issuances for the three months ended December 31, 2008 and 2007.
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
 
Shares issued:
               
Direct Stock Purchase Plan
    108,582       95,891  
Retirement Savings Plan and Trust
    155,195       140,071  
1998 Long-Term Incentive Plan
    520,124       343,673  
Outside Directors Stock-for-Fee Plan
    911       817  
                 
Total shares issued
    784,812       580,452  
                 
 
 
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements. However, our short-term borrowings reach their highest levels in the winter months.
 
We finance our short-term borrowing requirements through a combination of a $600 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide $1.2 billion of working capital funding. As of December 31, 2008, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $614 million. These facilities are described in further detail in Note 5 to the unaudited condensed consolidated financial statements.


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On December 4, 2006, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in new common stock and/or debt securities. As of December 31, 2008, we had approximately $450 million available for issuance under the registration statement. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the registration statement, we are permitted to issue a total of approximately $200 million of equity securities and $250 million of senior debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard & Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until an investment grade rating from all three credit rating agencies was achieved.
 
 
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
 
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). In December 2008, S&P upgraded our credit rating from BBB to BBB+ and affirmed a stable outlook. S&P cited improved financial performance and rate case decisions that have increased cash flow as the key drivers for the upgrade. Additionally, in January 2009, Moody’s changed our rating outlook from stable to positive. Fitch still maintains its stable outlook. Our current debt ratings are all considered investment grade and are as follows:
 
                         
    S&P     Moody’s     Fitch  
 
Unsecured senior long-term debt
    BBB+       Baa3       BBB+  
Commercial paper
    A-2       P-3       F-2  
 
None of our ratings are currently under review. However, a significant degradation in our operating performance, a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of the recent adverse global financial and credit conditions or our inability to refinance on a timely basis our $400 million 4.00% unsecured senior notes maturing in October 2009 could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean even more limited access to the private and public credit markets and an increase in the costs of such borrowings.
 
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
 
 
We were in compliance with all of our debt covenants as of December 31, 2008. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.


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The following table presents our capitalization as of December 31, 2008, September 30, 2008 and December 31, 2007:
 
                                                 
    December 31, 2008     September 30, 2008     December 31, 2007  
    (In thousands, except percentages)  
 
Short-term debt
  $ 360,833       7.9 %   $ 350,542       7.7 %   $ 202,244       4.6 %
Long-term debt
    2,120,427       46.5 %     2,120,577       46.9 %     2,128,533       48.8 %
Shareholders’ equity
    2,078,076       45.6 %     2,052,492       45.4 %     2,032,483       46.6 %
                                                 
Total capitalization
  $ 4,559,336       100.0 %   $ 4,523,611       100.0 %   $ 4,363,260       100.0 %
                                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 54.4 percent at December 31, 2008, 54.6 percent at September 30, 2008 and 53.4 percent at December 31, 2007. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.
 
 
Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the three months ended December 31, 2008.
 
In February 2008, Atmos Pipeline and Storage, LLC announced plans to construct and operate a salt-cavern gas storage project in Franklin Parish, Louisiana. The project, located near several large interstate pipelines, includes the development of three 5 billion cubic feet (Bcf) caverns for a total of 15 Bcf of working gas storage, with six-turn injection and withdrawal capacity. We have drilled a test well and are currently evaluating the results. Additionally, we have submitted a pre-filing request with the Federal Energy Regulatory Commission (FERC) to construct and operate the project. We expect approval of this request in the third quarter of fiscal 2009. Finally, we have engaged the services of an investment bank to assist us in determining the optimal ownership and/or development alternatives with respect to this project.
 
 
We conduct risk management activities through our natural gas distribution, natural gas marketing and pipeline, storage and other segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.
 
In our natural gas marketing and pipeline, storage and other segments, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.


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The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three months ended December 31, 2008 and 2007:
 
                 
    Three Months Ended
 
    December 31  
    2008     2007  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (63,677 )   $ (21,053 )
Contracts realized/settled
    (53,766 )     (22,338 )
Fair value of new contracts
    (3,223 )     (1,681 )
Other changes in value
    69,352       23,544  
                 
Fair value of contracts at end of period
  $ (51,314 )   $ (21,528 )
                 
 
The fair value of our natural gas distribution segment’s financial instruments at December 31, 2008 is presented below by time period and fair value source:
 
                                         
    Fair Value of Contracts at December 31, 2008  
    Maturity in Years        
                      Greater
    Total Fair
 
Source of Fair Value
  Less than 1     1-3     4-5     than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ (47,448 )   $ (3,866 )   $     $     $ (51,314 )
Prices based on models and other valuation methods
                             
                                         
Total Fair Value
  $ (47,448 )   $ (3,866 )   $     $     $ (51,314 )
                                         
 
The following table shows the components of the change in fair value of our natural gas marketing segment’s financial instruments for the three months ended December 31, 2008 and 2007:
 
                 
    Three Months Ended
 
    December 31  
    2008     2007