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, or a non-accelerated filer. See definition of “Accelerated filer and large accelerated filer” inRule 12b-2of 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 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 31, 2007.

 

 

 

 

 

 

 

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” or “the Company”) and our 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 six regulated natural gas utility divisions, in the service areas described below:

 

 

 

 

In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulationand/orregulation by local authorities in each of the states in which the utility divisions operate. Our shared services division is located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

 

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 Louisiana and Kentucky/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 have provided natural gas management services to our utility operations, other than the Mid-Tex Division. These services included aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to

 

our utility service areas at competitive prices. The revenues of AES represent charges to our utility divisions equal to the costs incurred to provide those services. Effective January 1, 2007, our shared services division began providing these services to our utility operations, which were formerly provided by AES. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through sales-type lease agreements.

 

 

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 its Annual Report onForm 10-Kfor the fiscal year ended September 30, 2006. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2006 are not indicative of expected results of operations for the full 2007 fiscal year, which ends September 30, 2007.

 

 

Our accounting policies are described in Note 2 to our Annual Report onForm 10-Kfor the year ended September 30, 2006. There were no significant changes to those accounting policies during the three months ended December 31, 2006.

 

 

We record certain costs as regulatory assets in accordance with Statement of Financial Accounting Standards (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 separately reported.

 

 

Significant regulatory assets and liabilities as of December 31, 2006 and September 30, 2006 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, net of related tax, for the three-month periods ended December 31, 2006 and 2005:

 

 

Accumulated other comprehensive loss, net of tax, as of December 31, 2006 and September 30, 2006 consisted of the following unrealized gains (losses):

 

 

 

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). The new standard makes 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. Additionally, this standard requires that the measurement date must correspond to the fiscal year end balance sheet date. This standard does not change how net periodic pension and postretirement cost or the projected benefit obligation is determined. The balance sheet recognition guidance of this standard will be effective as of September 30, 2007 and the measurement date provisions of this guidance can be adopted as late as fiscal 2008 for our company.

 

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 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 andover-the-counterquotations, time value and volatility factors underlying the contracts. These risk management assets and liabilities are subject to continuing market risk until the underlying derivative contracts are settled.

 

 

The following table shows the fair values of our risk management assets and liabilities by segment at December 31, 2006 and September 30, 2006:

 

 

 

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.

 

 

AEM manages its exposure to the risk of natural gas price changes through a combination of storage and financial derivatives, including futures,over-the-counterand 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-month period ended December 31, 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 three months ended December 31, 2006 of $21.0 million in net deferred hedging losses 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 December 31, 2006 is expected to be recognized in net income in fiscal 2007 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 2008 and beyond.

 

 

Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative hedging instrument and the hedged item and could materially affect our results as ineffectiveness is recognized in the income statement. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments is referred to as basis ineffectiveness. Fair value hedge ineffectiveness arising from the timing of the settlement of physical contracts and the settlement of the related fair value hedge is referred to as timing ineffectiveness. Gains and losses arising from basis and timing ineffectiveness for the three months ended December 31, 2006 and 2005 is as follows:

 

 

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 December 31, 2006, AEH had a net open position (including existing storage) of less than 0.1 Bcf.

 

 

 

 

Long-term debt at December 31, 2006 and September 30, 2006 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 December 31, 2006, the interest rate on our floating rate debt was 5.749 percent.

 

 

At December 31, 2006 and September 30, 2006, there was $154.5 million and $382.4 million outstanding under our commercial paper program and bank credit facilities.

 

 

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 available for issuance, including approximately $401.5 million of capacity carried over from our prior shelf registration statement filed with the SEC in August 2004. As discussed in Note 5, in December 2006, we sold 6.3 million shares of common stock under the new registration statement, the net proceeds of which were used to reduce short-term debt. As of December 31, 2006, we have approximately $701 million of availability remaining under the registration statement.

 

 

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on awhen-and-as-neededbasis 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.

 

 

As of December 31, 2006, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a five-year unsecured facility for $600 million that we entered into in December 2006. This credit facility replaced our $600 million three-year revolving credit facility entered into in October 2005. The new facility, expiring December 2011, bears interest at a base rate or at the LIBOR rate plus from 0.30 percent to 0.75 percent, based on the Company’s credit ratings, and serves as a backup liquidity facility for our $600 million commercial paper program. At December 31, 2006, there was $154.5 million outstanding under our commercial paper program.

 

We have a second unsecured facility in place which is a364-dayfacility expiring November 2007, for $300 million that bears interest at a base rate or at the LIBOR rate plus from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. At December 31, 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 expires in March 2007. At December 31, 2006, there were no borrowings 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 five-year credit facility and $300 million364-daycredit 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 December 31, 2006, ourtotal-debt-to-total-capitalizationratio, as defined, was 58 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.

 

 

AEM has a $580 million uncommitted demand working capital credit facility that expires in March 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 December 31, 2006, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.61 to 1.

 

At December 31, 2006, there were no borrowings outstanding under this credit facility. However, at December 31, 2006, AEM letters of credit totaling $153.9 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 $21.1 million at December 31, 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 of $25 million that is used for working-capital andletter-of-creditpurposes. There were no borrowings under this uncommitted credit facility at December 31, 2006, but letters of credit reduced the amount available by $5.4 million. This uncommitted line is renewed 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 awhen-and-as-availablebasis 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. State regulators have approved this facility through December 31, 2007 and have authorized an increase in the intercompany facility to $200 million. At December 31, 2006, there were no borrowings under this facility.

 

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 December 31, 2006, there were no borrowings under this facility.

 

 

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 December 31, 2006 approximately $258.3 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 December 31, 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.

 

 

On December 13, 2006, we completed the public offering of 6,325,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 825,000 shares. The offering was priced at $31.50 and generated net proceeds of approximately $192 million. We used the net proceeds from this offering to reduce short-term debt.

 

 

 

Basic and diluted earnings per share for the three months ended December 31, 2006 and 2005 are calculated as follows:

 

 

There were noout-of-the-moneyoptions excluded from the computation of diluted earnings per share for the three months ended December 31, 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 months ended December 31, 2006 and 2005 are presented in the following table. 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 months ended December 31, 2006 and 2005 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 is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. However, additional voluntary contributions are made to satisfy regulatory requirements in certain of our jurisdictions. During the three months ended December 31, 2006, we contributed $2.8 million to our other postretirement plans, and we expect to contribute a total of approximately $11 million to these plans during fiscal 2007.

 

 

 

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to our annual report onForm 10-Kfor the year ended September 30, 2006, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 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 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, 2006, AEM was committed to purchase 89.5 Bcf within one year and 56.7 Bcf within one to three years under indexed contracts. AEM is committed to purchase 1.6 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $5.26 to $12.00. Purchases under these contracts totaled $420.4 million and $787.7 million for the three months ended December 31, 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 December 31, 2006 are as follows (in thousands):

 

 

 

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. In February 2006, the KPSC issued an Order denying our Motion to Dismiss but stated that the Attorney General had not met his burden of proof concerning his complaint. In November 2006, we requested dismissal of the case through our filing of a notice of intent to file a general rate case in December 2006. Upon receipt of the notice of intent, the KPSC suspended the procedural schedule until it issues a decision regarding the motion for dismissal. 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 December 2006, the Company filed a rate application for an increase in base rates of $10.4 million in Kentucky. Additionally, we proposed to implement a process to review our rates annually and to collect the bad debt portion of gas costs directly rather than through the base rate. A decision is expected in the case in July 2007.

 

During fiscal 2006, we received “show cause” resolutions from approximately 80 cities served by our Mid-Tex Division, including the City of Dallas, which require the Mid-Tex Division to demonstrate that the existing distribution rates are just and reasonable. In May 2006, the Mid-Tex Division filed a Statement of Intent with the Railroad Commission of Texas (RRC) which consolidated the “show cause” resolutions and seeks incremental annual revenues of approximately $60 million and several rate design changes including WNA, revenue stabilization and recovery of the gas cost component of bad debt expense. In exchange for an agreement to provide the intervening parties in the case an additional two months to prepare for the hearing, the Mid-Tex Division obtained an agreement and approval to implement WNA in its rates for the2006-2007winter season and to implement WNA in the final rates in this proceeding. The hearing was completed on November 17, 2006. The hearing examiners in the case issued their Proposal for Decision (PFD) on February 2, 2007, which contained their recommendations to the RRC. In the PFD, the examiners recommended a total annual decrease in the Mid-Tex Division’s rates of approximately $22.8 million, a customer refund of $2.6 million and a permanent weather normalization adjustment mechanism based on10-yearweather data. We are in the process of preparing our responses to the recommendations in the PFD. We continue to believe that the evidence presented in the case supports our request to increase rates in order to earn a fair rate of return. While the RRC is required by statute to issue its final decision by April 2, 2007, it could issue a final order sometime in March 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 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 in February 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. We made a filing in response to the ordinances in October 2006. We believe that we will be able to ultimately demonstrate to the West Texas cities that our rates are just and reasonable.

 

 

In May 2006, we announced plans to form a joint venture and construct a natural gas gathering system in Eastern Kentucky, referred to as the Straight Creek Project. The Company is continuing to evaluate the scale and scope of the original project design, as well as the in-service date.

 

 

Information regarding our concentration of credit risk is disclosed in Note 15 to our annual report onForm 10-Kfor the year ended September 30, 2006. During the three months ended December 31, 2006, there were no material changes in our concentration of credit risk.

 

 

Atmos Energy Corporation and our 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 six 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:

 

 

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 onForm 10-Kfor the fiscal year ended September 30, 2006. We evaluate performance based on net income or loss of the respective operating units.

 

Income statements for the three-month periods ended December 31, 2006 and 2005 by segment are presented in the following tables:

 

 

 

 

Balance sheet information at December 31, 2006 and September 30, 2006 by segment is presented in the following tables: