Atmos Energy - 10-Q quarterly report FY

 

 

 

 

 

 

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” inRule 12b-2of the Exchange Act. (Check one):

 

Large Accelerated Filer þ  Accelerated Filer o  Non-Accelerated Filer o  Smaller Reporting Company o

 

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Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2of 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.

 

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements

 

 

 

See accompanying notes to condensed consolidated financial statements

 

 

 

See accompanying notes to condensed consolidated financial statements

 

 

 

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:

 

 

 

 

In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulationand/orregulation 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.

 

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.

 

 

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 toForm 10-Qand should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report onForm 10-Kfor 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 onForm 10-Kfor 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

 

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 aninstrument-by-instrumentbasis. 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:

 

 

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.

 

 

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:

 

 

Accumulated other comprehensive loss, net of tax, as of December 31, 2008 and September 30, 2008 consisted of the following unrealized gains (losses):

 

 

 

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 onForm 10-Kfor 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

 

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 the2008-2009heating 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 transportationand/orstorage 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

 

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

 

to sell the commodity. As of December 31, 2008, we had net long/(short) commodity contracts outstanding in the following quantities:

 

 

 

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.

 

 

 

 

 

 

 

 

 

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.

 

 

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.

 

 

 

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.

 

 

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.

 

 

 

 

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.

 

 

 

 

 

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:

 

 

 

 

 

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.

 

 

 

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 FSPFAS 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

 

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:

 

 

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 FSPFAS 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:

 

 

 

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.

 

 

 

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.

 

 

 

 

 

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:

 

 

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.

 

 

 

Long-term debt at December 31, 2008 and September 30, 2008 consisted of the following:

 

 

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

 

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 unsecured364-dayfacility 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.

 

 

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 a364-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 million364-dayfacility 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 million364-dayfacility 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.

 

 

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 stockand/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.

 

 

Basic and diluted earnings per share for the three months ended December 31, 2008 and 2007 are calculated as follows:

 

 

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.

 

 

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.

 

 

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2008 and 2007 are as follows:

 

 

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.

 

 

 

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 onForm 10-Kfor 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.

 

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):

 

 

 

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.

 

 

Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report onForm 10-Kfor 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.

 

 

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:

 

 

 

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 onForm 10-Kfor 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: