UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-Q

 

 

 

 

(972) 934-9227
(Registrant’s telephone number, including area code)

 

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, or a non-accelerated filer. See definition of “Accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  þ      Accelerated filer  o      Non-accelerated filer  o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o      No  þ

 

Number of shares outstanding of each of the issuer’s classes of common stock, as of July 31, 2006.

 

 

TABLE OF CONTENTS

 

 

PART I. FINANCIAL INFORMATION

 

 

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2006

 

 

Atmos Energy Corporation (“Atmos” or “the Company”) and its subsidiaries are engaged primarily in the natural gas utility business as well as other natural gas nonutility businesses. Our natural gas utility business distributes natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated natural gas utility divisions, in the service areas described below:

 

 

 

 

Our nonutility businesses operate in 22 states and include our natural gas marketing operations, pipeline and storage operations and other nonutility operations. These operations are either organized under or managed by Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by the Company.

 

Our natural gas marketing operations are managed by 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 southeastern and midwestern states and to our Kentucky, Louisiana and Mid-States utility divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative instruments.

 

Our pipeline and storage business includes the regulated operations of our Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and the nonregulated operations of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. The Atmos Pipeline — Texas Division transports natural gas to our Atmos Energy Mid-Tex Division and to third parties, as well as manages five underground storage reservoirs in Texas. Through APS, we own or have an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.

 

Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are each wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices in exchange for revenues that are equal to the costs incurred to provide these services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and have entered into agreements to lease these plants.

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

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 and notes 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 in its Annual Report on Form 10-K for the fiscal year ended September 30, 2005. Because of seasonal and other factors, the results of operations for the three and nine-month periods ended June 30, 2006 are not indicative of expected results of operations for the full 2006 fiscal year, which ends September 30, 2006.

 

Basis of comparison

 

Certain prior-period amounts have been reclassified to conform with the current year’s presentation.

 

Significant accounting policies

 

Our accounting policies are described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2005. Except for the Company’s adoption of Statement of Financial Accounting Standards (SFAS) 123 (revised), Share-Based Payment, discussed below, there were no significant changes to our accounting policies during the nine months ended June 30, 2006.

 

Additionally, during the second quarter of fiscal 2006, we completed our annual goodwill impairment assessment. Based on the assessment performed, our goodwill was not considered to be impaired.

 

Stock-based compensation plans

 

Our 1998 Long-Term Incentive Plan provides for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units to officers, division presidents and other key employees. Non-employee directors are also eligible to receive stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock.

 

On October 1, 2005, the Company adopted SFAS 123 (revised), Share-Based Payment (SFAS 123(R)). This standard revises SFAS 123, Accounting for Stock-Based Compensation and supersedes Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), the Company is required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award.

 

We adopted SFAS 123(R) using the modified prospective method. Under this transition method, stock-based compensation expense for the three and nine months ended June 30, 2006 included: (i) compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of October 1, 2005, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123; and (ii) compensation expense for all stock-based compensation awards granted subsequent to October 1, 2005, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). We recognize compensation expense on a straight-line basis over the requisite service period of the award. The impact of adoption on total stock-based compensation expense included in our statement of income for the three and nine months ended June 30, 2006 was less than $0.1 million and $0.4 million and was recorded as a component of operation and maintenance expense. In accordance with the modified prospective method, financial results for prior periods have not been restated.

 

Prior to October 1, 2005, we accounted for these plans under the intrinsic-value method described in APB Opinion 25, as permitted by SFAS 123. Under this method, no compensation cost for stock options was recognized

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for stock-option awards granted at or above fair-market value. Awards of restricted stock were valued at the market price of the Company’s common stock on the date of grant. The unearned compensation was amortized as a component of operation and maintenance expense over the vesting period of the restricted stock.

 

Total stock-based compensation expense for the three and nine months ended June 30, 2006 was $2.1 million and $4.3 million as compared to $0.9 million and $2.4 million for the three and nine months ended June 30, 2005. Had compensation expense for our stock-based awards been recognized as prescribed by SFAS 123, our net income and earnings per share for the three and nine months ended June 30, 2005 would have been impacted as shown in the following table:

 

 

Regulatory assets and liabilities

 

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 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 separately reported.

 

 

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging 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.

 

 

Accumulated other comprehensive loss, net of tax, as of June 30, 2006 and September 30, 2005 consisted of the following unrealized gains (losses):

 

 

Recent accounting pronouncements

 

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred — generally upon acquisition, construction or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligation. We will be required to apply the provisions of FIN 47 by September 30, 2006. We are currently evaluating the impact that FIN 47 may have on our financial position, results of operations and cash flows.

 

In February 2006, the FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments , which amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities and SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities . SFAS 155 (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, (c) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and (e) amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued by us after October 1, 2006 but is not expected to have a material impact on our financial position, results of operations and cash flows.

 

In March 2006, the FASB issued SFAS 156, Accounting for Servicing Financial Assets , which amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.   SFAS 156 (a) revises guidance on when a servicing asset and servicing liability should be recognized, (b) requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable, (c) permits an entity to choose to measure servicing assets and servicing liabilities under the amortization method or fair value measurement method, (d) at initial adoption, permits a one-time reclassification of available-for-sale securities to trading securities by entities with recognized servicing rights, without calling into question the treatment of other available-for-sale securities under SFAS 115, provided that the available-for-sale securities are identified as offsetting the exposure to changes in the fair value of servicing assets or liabilities that the servicer elects to subsequently measure at fair value and (e) requires separate presentation of servicing assets and servicing liabilities subsequently measured at fair value in the statement of financial position and additional footnote disclosure. We will be required to apply the provisions of SFAS 156 beginning October 1, 2006 but such application is not expected to have a material impact on our financial position, results of operations and cash flows.

 

In March 2006, the FASB issued the exposure draft Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) . The exposure draft, if adopted in its current form, would make a significant change to the existing rules by requiring recognition in the balance sheet of the overfunded or underfunded positions of defined benefit pension and other postretirement plans, along with a corresponding noncash, after-tax adjustment to stockholders’ equity. The proposed standard, if adopted, will be effective for fiscal 2007. We are monitoring the status of the exposure draft and assessing the impact it will have on our financial position, results of operations and cash flows.

 

In June 2006, the Emerging Issues Task Force (EITF) ratified EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation) . The EITF reached a consensus that the scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include sales, use, value added, and some excise taxes. The EITF also reached a consensus that entities may present these taxes on either a gross or net basis. If the taxes are significant, an entity should disclose its policy of presenting taxes and the amounts of taxes that are recognized on a gross basis in interim and annual financial statements. We will be required to apply the provisions of EITF 06-3 beginning January 1, 2007. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

 

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes by establishing standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. This interpretation also provides guidance on derecognition of income tax assets and

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties, accounting for income taxes in interim periods and income tax disclosures. We will be required to apply the provisions of FIN 48 beginning October 1, 2007. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

 

 

We conduct risk management activities through both our utility and natural gas marketing segments. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying derivative. Our determination of the fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains and losses on open contracts. In our determination of fair value, we consider various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Effective October 1, 2005, the Company changed its mark to market measurement from Inside FERC to Gas Daily to better reflect the prices of our physical commodity. This change did not have a material impact on our financial position on the date of adoption.

 

The following table shows the fair values of our risk management assets and liabilities by segment at June 30, 2006 and September 30, 2005:

 

 

Utility Hedging Activities

 

We use a combination of storage, fixed physical contracts and fixed financial contracts to partially insulate us and our customers against gas price volatility during the winter heating season. Because the gains or losses of financial derivatives used in our utility segment ultimately will be recovered through our rates, current period changes in the assets and liabilities from these risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation . Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. Our utility hedging activities also include the cost of our Treasury lock agreements which are described in further detail below.

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Nonutility Hedging Activities

 

AEM manages its exposure to the risk of natural gas price changes through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our financial derivative activities include fair value hedges to offset changes in the fair value of our natural gas inventory and cash flow hedges to offset anticipated purchases and sales of gas in the future. AEM also utilizes basis swaps and other non-hedge derivative instruments to manage its exposure to market volatility.

 

For the three and nine-month periods ended June 30, 2006, the change in the deferred hedging position in accumulated other comprehensive loss was attributable to decreases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition for the nine months ended June 30, 2006 of $3.4 million in net deferred hedging gains ($4.8 million in net deferred hedging losses during the three months ended June 30, 2006) in net income when the derivative contracts matured according to their terms. The net deferred hedging loss associated with open cash flow hedges remains subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. The majority of the deferred hedging balance as of June 30, 2006 is expected to be recognized in net income in fiscal 2006 along with the corresponding hedged purchases and sales of natural gas. The remainder of the deferred hedging balance is expected to be recognized in net income in fiscal 2007 and beyond.

 

Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We may 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 June 30, 2006, AEH had no net open positions (including existing storage).

 

Treasury Activities

 

During fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the then anticipated issuance of $875 million of long-term debt in October 2004. We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. This payment was recorded in accumulated other comprehensive loss and is being recognized as a component of interest expense over a period of five to ten years. During the three and nine-month periods ended June 30, 2006, we recognized approximately $1.4 million and $4.2 million of this amount as a component of interest expense.

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Long-term debt

 

Long-term debt at June 30, 2006 and September 30, 2005 consisted of the following:

 

 

Our unsecured floating rate debt bears interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At June 30, 2006, the interest rate on our floating rate debt was 5.452 percent.

 

Short-term debt

 

At June 30, 2006 and September 30, 2005, there was $297.1 million and $144.8 million outstanding under our commercial paper program and bank credit facilities.

 

Credit facilities

 

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the banks. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder winter months. Our working capital needs can vary significantly due to changes in the price of natural gas and the increased gas supplies required to meet customers’ needs during periods of cold weather.

 

Committed credit facilities

 

As of June 30, 2006, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a three-year unsecured facility, expiring October 2008, for $600 million that bears interest at a base rate or at the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings, and serves

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

as a backup liquidity facility for our $600 million commercial paper program. At June 30, 2006, there was $281.9 million outstanding under our commercial paper program.

 

We have a second unsecured facility in place which is a 364-day facility expiring November 2006, for $300 million that bears interest at a base rate or the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings. At June 30, 2006, there were no borrowings under this facility.

 

We have a third unsecured facility in place for $18 million that bears interest at the Federal Funds rate plus 0.5 percent. This facility expired on March 31, 2006 and was renewed effective April 1, 2006 for one year with no material changes to its terms and pricing. At June 30, 2006, there was $15.2 million outstanding under this facility.

 

The availability of funds under our 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 both our $600 million three-year credit facility and $300 million 364-day credit facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2006, our total-debt-to-total-capitalization ratio, as defined, was 62 percent. In addition, the fees that we pay on unused amounts under both the $600 million and $300 million credit facilities are subject to adjustment depending upon our credit ratings.

 

Uncommitted credit facilities

 

On November 28, 2005, AEM amended its $250 million uncommitted demand working capital credit facility to increase the amount of credit available from $250 million to a maximum of $580 million. On March 31, 2006, AEM amended and extended this uncommitted demand working capital credit facility to March 31, 2007.

 

Borrowings under the credit facility can be made either as revolving loans or offshore rate loans. Revolving loan borrowings will bear interest at a floating rate equal to a base rate (defined as the higher of 0.50 percent per annum above the Federal Funds rate or the lender’s prime rate) plus 0.25 percent. Offshore rate loan borrowings will bear interest at a floating rate equal to a base rate based upon LIBOR plus an applicable margin, ranging from 1.25 percent to 1.625 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. Borrowings drawn down under letters of credit issued by the banks will bear interest at a floating rate equal to the base rate, as defined above, plus an applicable margin, which will range from 1.00 percent to 1.875 percent per annum, depending on the excess tangible net worth of AEM and whether the letters of credit are swap-related standby letters of credit.

 

AEM is required by the financial covenants in the credit facility to maintain a maximum ratio of total liabilities to tangible net worth of 5 to 1, along with minimum levels of net working capital ranging from $20 million to $120 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $121 million, and must not have a maximum cumulative loss from March 30, 2005 exceeding $4 million to $23 million, depending on the total amount of borrowing elected from time to time by AEM. At June 30, 2006, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.00 to 1.

 

At June 30, 2006, there were no borrowings outstanding under this credit facility. However, at June 30, 2006, AEM letters of credit totaling $70.4 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 $129.6 million at June 30, 2006. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

 

The Company also has an unsecured short-term uncommitted credit line for $25 million that is used for working-capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at June 30, 2006, but letters of credit reduced the amount available by $4.5 million. This uncommitted line is renewed

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

or renegotiated at least annually with varying terms, and we pay no fee for the availability of the line. Borrowings under this line are made on a when-and-as-available basis at the discretion of the bank.

 

AEH, the parent company of AEM, has a $100 million intercompany uncommitted demand credit facility with the Company which bears interest at LIBOR plus 2.75 percent. This facility has been approved by our state regulators through December 31, 2006. At June 30, 2006, $88.4 million was outstanding under this facility. On July 1, 2006, this facility was renewed for one year with no material changes to its terms.

 

In addition, AEM has a $120 million intercompany uncommitted demand credit facility with AEH for its nonutility business which bears interest at LIBOR plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility described above. This facility is used to supplement AEM’s $580 million credit facility. At June 30, 2006, $82.0 million was outstanding under this facility. On July 1, 2006, this facility was renewed for one year with no material changes to its terms.

 

Debt Covenants

 

We have other covenants in addition to those described above. Our Series P First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, after November 2007, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1985 may not exceed the sum of accumulated net income for periods after December 31, 1985 plus $9 million. At June 30, 2006 approximately $223.0 million of retained earnings was unrestricted with respect to the payment of dividends.

 

We were in compliance with all of our debt covenants as of June 30, 2006. If we were unable to comply with our debt covenants, we could be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our two public debt indentures relating to our senior notes and debentures, as well as our $600 million and $300 million 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. In addition, 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. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.

 

Except as described above, we have no 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.

 

 

Stock-Based Compensation Plans

 

On August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by our shareholders. The Long-Term Incentive Plan is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units to certain employees and non-employee directors of Atmos and its subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock. We are authorized to grant awards for up to a maximum of four million shares of common stock under this plan subject to certain adjustment provisions. As of June 30, 2006, non-qualified stock options, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units had been issued

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

under this plan and 715,699 shares were available for issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years.

 

We used the Black-Scholes pricing model to estimate the fair value of each option granted with the following weighted average assumptions:

 

 

 

 

A summary of option activity as of June 30, 2006, and changes during the nine months then ended, is presented below:

 

 

The stock options had a weighted-average fair value per share on the date of grant of $3.74 and $3.69 for the nine months ended June 30, 2006 and 2005. There were no stock options granted during the three months ended June 30, 2006 and 2005. Net cash proceeds from the exercise of stock options during the nine months ended June 30, 2006 and 2005 were $0.5 million and $10.1 million and during the three months ended June 30, 2006 and 2005 were $0.5 and $1.0 million. The associated income tax benefit from stock options exercised during the nine months ended June 30, 2006 and 2005 was less than $0.1 million and $1.1 million, and during the three months ended June 30, 2006 and 2005 was less than $0.1 million and $0.1 million. The total intrinsic value of options exercised during the nine months ended June 30, 2006 and 2005 was less than $0.1 million and $1.7 million, and during the three months ended June 30, 2006 and 2005 was less than $0.1 million and $0.2 million.

 

As of June 30, 2006, there was less than $0.1 million of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a weighted-average period of 1.5 years.

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Restricted Stock Plans

 

As noted above, the 1998 Long-Term Incentive Plan provides for discretionary awards of time-lapse restricted stock and performance-based restricted stock units to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The associated expense is recognized ratably over the vesting period.

 

A summary of the status of the Company’s nonvested restricted shares as of June 30, 2006, and changes during the nine months then ended, is presented below:

 

 

As of June 30, 2006, there was $16.0 million of total unrecognized compensation cost related to nonvested restricted shares granted under the 1998 Long-Term Incentive Plan. That cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of restricted stock vested during the nine months ended June 30, 2006 and 2005 was $2.5 million and $0.5 million, and during the three months ended June 30, 2006 was $0.9 million. There were no restricted stock grants that vested during the three months ended June 30, 2005.

 

 

Basic and diluted earnings per share for the three and nine months ended June 30, 2006 and 2005 are calculated as follows:

 

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

There were approximately 396,000 restricted and other shares and approximately 102,000 stock options that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2006 as their inclusion in the computation would be anti-dilutive.

 

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2006 and 2005 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 and nine months ended June 30, 2006 and 2005 are presented in the following tables. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility 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 and nine months ended June 30, 2006 and 2005 are as follows:

 

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. During the nine months ended June 30, 2006, we contributed $2.8 million to the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. The current year contribution achieved a desired level of funding by satisfying the minimum funding requirements while maximizing the tax deductible contribution for this plan for plan year 2005. We anticipate making no additional contributions to our pension plans for the remainder of fiscal 2006. However, we contributed $7.9 million to our other postretirement plans, and we expect to contribute approximately $12 million to these plans during fiscal 2006.

 

 

Litigation and Environmental Matters

 

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2005, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2006. 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 net 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 net cash flows.

 

Purchase Commitments

 

AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2006, AEM was committed to purchase 64.8 Bcf within one year, 53.7 Bcf within one to three years and 3.1 Bcf after three years under indexed contracts. AEM is committed to purchase 2.7 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $5.45 to $12.00. Purchases under these contracts totaled $398.9 million and $294.0 million for the three months ended June 30, 2006 and 2005 and $1,718.4 million and $999.4 million for the nine months ended June 30, 2006 and 2005.

 

Our utility operations, other than the 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 prices. The estimated fiscal year commitments under these contracts as of June 30, 2006 are as follows (in thousands):

 

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Regulatory Matters

 

In February 2005, the Attorney General of the State of Kentucky filed a complaint with the Kentucky Public Service Commission (KPSC) alleging that our rates were producing revenues in excess of reasonable levels. We answered the complaint and filed a Motion to Dismiss with the KPSC. On February 2, 2006, the KPSC issued an Order denying our Motion to Dismiss and on March 3, 2006 set a procedural schedule for the case. The Attorney General is currently conducting discovery. A hearing should be scheduled for early 2007. We believe that the Attorney General will not be able to demonstrate that our present rates are in excess of reasonable levels.

 

In May 2006, the Mid-Tex Division filed a Statement of Intent seeking incremental annual revenues of $60 million and several rate design changes including Weather Normalization Adjustment (WNA), revenue stabilization, and recovery of the gas cost component of bad debt. The Statement of Intent consolidated “show cause” resolutions that had been filed in approximately 80 cities served by the Mid-Tex Division, including the City of Dallas, which requires the Mid-Tex Division to demonstrate that existing distribution rates are just and reasonable.

 

In July 2006, the Mid-Tex Division and the Railroad Commission of Texas (RRC) agreed to implement WNA on both an interim and permanent basis, effective October 1, 2006. The agreement provided that the interim WNA will use 30 years of weather history, while the permanent WNA would allow the parties to contest the appropriate period of weather data to use in calculating normal weather. The permanent WNA would also be modified or adjusted to conform to the rate design that the RRC ultimately approves in the case, which is anticipated no later than the first quarter of calendar 2007. Any rate increase will be effective prospectively from the date of the final order; however, any rate decrease will be effective from May 31, 2006.

 

In November 2005, we received a notice from the Tennessee Regulatory Authority (TRA) that it was opening an investigation into allegations by the Consumer Advocate and Protection Division of the Tennessee Attorney General’s Office that we are overcharging customers in parts of Tennessee by approximately $10 million per year. We have responded to numerous data requests from the TRA Staff. On April 24, 2006, the TRA Staff filed a Report and Recommendation in which it recommended that the TRA convene a contested case procedure for the purpose of establishing a fair and reasonable return. The TRA convened to consider the Staff’s recommendation on May 15, 2006 and set a procedural schedule. All parties filed direct testimony on July 17, 2006, with rebuttal due August 18, 2006. A hearing is scheduled for August 29, 2006. We believe that the Consumer Advocate and Protection Division will not be able to demonstrate that our present rates are in excess of reasonable levels.

 

In January 2006, the Lubbock, Texas City Council passed a resolution requiring Atmos to submit copies of all documentation necessary for the city to review the rates of Atmos’ West Texas Division to ensure they are just and reasonable. Information was provided to the city on February 28, 2006. We believe that we will be able to ultimately demonstrate to the City of Lubbock that our rates are just and reasonable.

 

In May 2006, Atmos began receiving “show cause” ordinances from several of the cities in the West Texas Division. The ordinances request a filing to be made no later than September 15, 2006. We believe that we will be able to ultimately demonstrate to the West Texas cities that our rates are just and reasonable.

 

Other

 

On November 30, 2005, we entered into an agreement with a third party to jointly construct, own and operate a 45-mile large diameter natural gas pipeline in the northern portion of the Dallas/Fort Worth Metroplex (North Side Loop). Under the terms of the agreement, we are responsible for contributing no more than $42.5 million to the construction costs of the pipeline. We are also responsible for 50 percent of the costs of the compression facilities. The North Side Loop was fully placed into service in May 2006. As of June 30, 2006, we had spent $46.1 million for the North Side Loop project and expect to spend approximately $5.3 million in the remainder of fiscal 2006 for this project.

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

During the third quarter of fiscal 2005, we entered into two agreements with third parties to transport natural gas through our Texas intrastate pipeline system beginning in fiscal 2006. To handle the increased volumes for these projects, we installed compression equipment and other pipeline infrastructure. We have spent approximately $30 million in fiscal 2006 for these projects, which were placed in service at the end of the third quarter of fiscal 2006.

 

On August 29, 2005, Hurricane Katrina struck the Gulf Coast, inflicting significant damage to our eastern Louisiana operations. The hardest hit areas in our service territory were in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes. In total, approximately 230,000 of our natural gas customers were affected in these areas. Although service has been restored for many of our customers, a significant number of customers will not require gas service for some time because of sustained damages. We cannot predict with certainty how many of these customers will return to these service areas and over what time period they may return. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. We are implementing new rates, subject to refund, in August 2006 that reflect the reduced customer count and enable us to recoup costs attributable to Hurricane Katrina.

 

In May 2006, we announced plans to form a joint venture with a local natural gas producer to construct a natural gas gathering system in Eastern Kentucky that will originate in Floyd County, Kentucky, and extend north approximately 65 miles to interconnect with the Tennessee Gas Pipeline in Carter County, Kentucky. Tennessee Gas Pipeline’s interstate system delivers natural gas to the northeastern United States, including New York City and Boston. The new system is expected to relieve severe gas gathering and transportation constraints that historically have burdened natural gas producers in the area and should improve delivery reliability to natural gas customers. More than a dozen other producers have signed memoranda of understanding to commit gas volumes to the new system and to enter into agreements on commercially reasonable terms.

 

The project is expected to cost between $75 million to $80 million. Upon receiving all required regulatory approvals, construction is expected to begin in the first half of fiscal 2007, with operations expected to begin in fiscal 2008. Final terms of the joint venture are still under negotiation; however, we anticipate that we will have the ability to consolidate the joint venture.

 

 

Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the utility segment is mitigated by the large number of individual customers and diversity in our customer base.

 

Customer diversification also helps mitigate AEM’s exposure to credit risk. AEM maintains credit policies with respect to its counterparties that it believes minimizes overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. AEM also monitors the financial condition of existing counterparties on an ongoing basis. Customers not meeting minimum standards are required to provide adequate assurance of financial performance.

 

AEM maintains a provision for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

 

AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable,

 

ATMOS ENERGY CORPORATION

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by AEM’s credit department, but are primarily based on external ratings provided by Moody’s Investors Service Inc. (Moody’s) and/or Standard & Poor’s Corporation (S&P). For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrial and commercial customers is non-investment grade. The following table shows the percentages related to the investment ratings as of June 30, 2006 and September 30, 2005.

 

 

The following table presents our derivative counterparty credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of June 30, 2006. Investment grade counterparties have minimum credit ratings of BBB-, assigned by S&P; or Baa3, assigned by Moody’s. Non-investment grade counterparties are composed of counterparties that are below investment grade or that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is composed of numerous smaller counterparties, none of which is individually significant.

 

 

 

 

 

Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

 

Through our nonutility businesses we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 22 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.

 

Our operations are divided into four segments:

 

 

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 utility segment operations are geographically dispersed, they are reported as a single segment as each utility 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, 2005. We evaluate performance based on net income or loss of the respective operating units.

 

Income statements for the three and nine-month periods ended June 30, 2006 and 2005 by segment are presented in the following tables: