(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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TEXAS AND VIRGINIA 75-1743247
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
THREE LINCOLN CENTRE, SUITE 1800 75240
5430 LBJ FREEWAY, DALLAS, TEXAS (Zip Code)
(Address of principal executive offices)
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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 [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes [X] No [ ]
Number of shares outstanding of each of the issuer's classes of common stock, as of August 1, 2003.
CLASS SHARES OUTSTANDING ----- ------------------ No Par Value 51,279,963 |
ITEM 1. FINANCIAL STATEMENTS
JUNE 30, SEPTEMBER 30,
2003 2002
----------- -------------
(UNAUDITED)
(IN THOUSANDS)
ASSETS
Property, plant and equipment............................... $2,504,655 $2,127,827
Less accumulated depreciation and amortization............ 1,010,210 827,507
---------- ----------
Net property, plant and equipment...................... 1,494,445 1,300,320
Current assets
Cash and cash equivalents................................. 17,321 46,827
Cash held on deposit in margin account.................... -- 10,192
Accounts receivable, net.................................. 251,418 136,227
Inventories............................................... 5,489 3,769
Gas stored underground.................................... 79,485 91,783
Assets from risk management activities.................... 18,646 27,984
Other current assets and prepayments...................... 10,605 13,209
---------- ----------
Total current assets................................... 382,964 329,991
Intangible assets........................................... 5,248 5,365
Goodwill.................................................... 275,021 185,015
Noncurrent assets from risk management activities........... 1,635 5,241
Deferred charges and other assets........................... 219,027 154,289
---------- ----------
$2,378,340 $1,980,221
========== ==========
SHAREHOLDERS' EQUITY AND LIABILITIES
Shareholders' equity
Common stock.............................................. $ 255 $ 208
Additional paid-in capital................................ 727,686 508,265
Retained earnings......................................... 140,373 106,142
Accumulated other comprehensive loss...................... (40,861) (41,380)
---------- ----------
Shareholders' equity................................... 827,453 573,235
Long-term debt.............................................. 864,348 670,463
---------- ----------
Total capitalization................................... 1,691,801 1,243,698
Current liabilities
Current maturities of long-term debt...................... 9,747 21,980
Short-term debt........................................... 700 145,791
Accounts payable and accrued liabilities.................. 203,588 135,609
Taxes payable............................................. 35,545 15,626
Customers' deposits....................................... 39,221 31,147
Liabilities from risk management activities............... 13,256 18,487
Deferred gas cost......................................... 29,862 21,947
Other current liabilities................................. 50,184 72,520
---------- ----------
Total current liabilities.............................. 382,103 463,107
Deferred income taxes....................................... 163,443 134,540
Noncurrent liabilities from risk management activities...... 549 3,663
Deferred credits and other liabilities...................... 140,444 135,213
---------- ----------
$2,378,340 $1,980,221
========== ==========
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See accompanying notes to condensed consolidated financial statements.
THREE MONTHS ENDED
JUNE 30,
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS,
EXCEPT PER SHARE DATA)
Operating revenues.......................................... $247,789 $161,800
Purchased gas cost.......................................... 160,583 87,967
-------- --------
Gross profit.............................................. 87,206 73,833
Gas trading margin.......................................... 7,858 12,259
Operating expenses
Operation and maintenance................................. 45,141 37,832
Depreciation and amortization............................. 23,192 20,362
Taxes, other than income.................................. 12,675 8,720
-------- --------
Total operating expenses............................... 81,008 66,914
-------- --------
Operating income............................................ 14,056 19,178
Miscellaneous income (expense).............................. 686 (182)
Interest charges............................................ 16,042 13,823
-------- --------
Income (loss) before income taxes........................... (1,300) 5,173
Income tax expense (benefit)................................ (1,099) 1,919
-------- --------
Net income (loss)...................................... $ (201) $ 3,254
======== ========
Per Share Data
Basic net income (loss) per share......................... $ (0.00) $ 0.08
======== ========
Diluted net income (loss) per share....................... $ (0.00) $ 0.08
======== ========
Cash dividends per share.................................... $ .300 $ .295
======== ========
Weighted average shares outstanding:
Basic..................................................... 45,997 41,265
======== ========
Diluted................................................... 45,997 41,370
======== ========
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See accompanying notes to condensed consolidated financial statements.
NINE MONTHS ENDED
JUNE 30,
-----------------------
2003 2002
----------- ---------
(IN THOUSANDS,
EXCEPT PER SHARE DATA)
Operating revenues.......................................... $1,349,697 $812,623
Purchased gas cost.......................................... 929,300 479,542
---------- --------
Gross profit.............................................. 420,397 333,081
Gas trading margin.......................................... 14,801 29,026
Operating expenses
Operation and maintenance................................. 151,310 122,614
Depreciation and amortization............................. 65,273 60,875
Taxes, other than income.................................. 44,057 29,661
---------- --------
Total operating expenses............................... 260,640 213,150
---------- --------
Operating income............................................ 174,558 148,957
Miscellaneous income (expense).............................. 3,321 (893)
Interest charges............................................ 47,679 44,304
---------- --------
Income before income taxes and cumulative effect of
accounting change......................................... 130,200 103,760
Income tax expense.......................................... 48,303 38,495
---------- --------
Income before cumulative effect of accounting change........ 81,897 65,265
Cumulative effect of accounting change, net of income tax
benefit................................................... (7,773) --
---------- --------
Net income............................................. $ 74,124 $ 65,265
========== ========
Per Share Data
Basic income per share:
Income before cumulative effect of accounting change... $ 1.83 $ 1.59
Cumulative effect of accounting change, net of income
tax benefit........................................... (.17) --
---------- --------
Net income............................................. $ 1.66 $ 1.59
========== ========
Diluted income per share:
Income before cumulative effect of accounting change... $ 1.82 $ 1.59
Cumulative effect of accounting change, net of income
tax benefit........................................... (.17) --
---------- --------
Net income............................................. $ 1.65 $ 1.59
========== ========
Cash dividends per share.................................... $ .900 $ .885
========== ========
Weighted average shares outstanding:
Basic..................................................... 44,679 41,049
========== ========
Diluted................................................... 44,879 41,144
========== ========
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See accompanying notes to condensed consolidated financial statements.
NINE MONTHS ENDED
JUNE 30,
---------------------
2003 2002
--------- ---------
(UNAUDITED)
(IN THOUSANDS)
Cash Flows From Operating Activities
Net income................................................ $ 74,124 $ 65,265
Adjustments to reconcile net income to net cash provided
by operating activities:
Cumulative effect of accounting change, net of income
tax benefit........................................... 7,773 --
Depreciation and amortization:
Charged to depreciation and amortization............. 65,273 60,875
Charged to other accounts............................ 1,676 1,931
Deferred income tax expense............................ 9,148 18,454
Other.................................................. (5,403) (3,223)
Net assets/liabilities from risk management
activities............................................ (4,200) (10,780)
Net change in operating assets and liabilities......... (31,099) 169,144
--------- ---------
Net cash provided by operating activities............ 117,292 301,666
Cash Flows From Investing Activities
Capital expenditures...................................... (113,452) (89,768)
Acquisitions.............................................. (74,650) (15,747)
Retirements of property, plant and equipment, net......... 315 (1,930)
Assets for leasing activities............................. (185) (6,880)
--------- ---------
Net cash used in investing activities................ (187,972) (114,325)
Cash Flows From Financing Activities
Net decrease in short-term debt........................... (145,091) (155,755)
Cash dividends paid....................................... (39,893) (36,391)
Repayment of long-term debt............................... (72,333) (16,925)
Repayment of Mississippi Valley Gas debt.................. (70,938) --
Net proceeds from issuance of long-term debt.............. 253,267 --
Proceeds from Bridge loan................................. 147,000 --
Repayment of Bridge loan.................................. (147,000) --
Issuance of common stock.................................. 19,336 13,470
Net proceeds from equity offering......................... 96,826 --
--------- ---------
Net cash provided (used) by financing activities..... 41,174 (195,601)
--------- ---------
Net decrease in cash and cash equivalents................... (29,506) (8,260)
Cash and cash equivalents at beginning of period............ 46,827 15,263
--------- ---------
Cash and cash equivalents at end of period.................. $ 17,321 $ 7,003
========= =========
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See accompanying notes to condensed consolidated financial statements.
1. UNAUDITED INTERIM FINANCIAL INFORMATION
In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim period financial statements. These consolidated interim period financial statements 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 ("Atmos" or "the Company") in its Annual Report on Form 10-K for the fiscal year ended September 30, 2002. Because of seasonal and other factors, the results of operations for the nine month period ended June 30, 2003 are not indicative of expected results of operations for the year ending September 30, 2003.
Principles of consolidation -- The accompanying condensed consolidated financial statements include the accounts of Atmos and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated.
Use of estimates -- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. We based our estimates on historical experience and various other assumptions that we believed to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, goodwill and pension and other post retirement plans. Actual results may differ from estimates.
Common stock -- At June 30, 2003, we had 100,000,000 shares of common stock, no par value (stated at $.005 per share), authorized and 51,106,074 shares issued and outstanding. At September 30, 2002, we had 41,675,932 shares issued and outstanding.
Goodwill -- The following table summarizes our goodwill balances as of June 30, 2003 and September 30, 2002:
JUNE 30, SEPTEMBER 30,
2003 2002
----------- -------------
(UNAUDITED)
(IN THOUSANDS)
Utility segment............................................. $240,294 $150,287
Natural gas marketing segment............................... 22,600 21,288
Other non-utility segment................................... 12,127 13,440
-------- --------
Total Goodwill............................................ $275,021 $185,015
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The increase in the utility segment's goodwill as of June 30, 2003 is attributable to our acquisition of Mississippi Valley Gas Company on December 3, 2002 as further described in Note 2.
Under the provisions of Statement of Financial Accounting Standards (SFAS) 142, Goodwill and Other Intangible Assets, we annually evaluate our goodwill balances for impairment during our second fiscal quarter or as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting groups. If our projections of estimated future cash flows change, those changes could result in a reduction in the carrying value of our goodwill. Our evaluation performed during the quarter ended March 31, 2003 resulted in no impairment.
Impairment of Long-Lived Assets -- We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded. To date, no such impairment has been recognized.
Asset Retirement Obligations -- Effective October 1, 2002, we adopted SFAS 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The adoption of this Statement had no material impact to our financial condition or results of operations based on the perpetual nature of our franchise agreements and on our experience in the businesses in which we operate.
Revenue recognition -- Sales of natural gas are billed on a monthly cycle basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for natural gas revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense.
Accounts receivable and allowance for doubtful accounts -- Accounts receivable consists of natural gas sales to residential, commercial, industrial, agricultural and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on an aging of those receivable balances. We apply percentages to each aging category based on our collections experience. On certain other receivables where we are aware of a specific customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. We believe our allowance for doubtful accounts is adequate. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different.
Risk management assets and liabilities, utility segment -- We use a combination of storage and financial hedges to protect us and our customers against unusually large winter period gas price increases. The financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However, because these costs will ultimately be recovered through our rates, current period changes in the assets and liabilities from 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 as a result of the use of these financial instruments. The changes in the assets and liabilities from risk management activities are recognized in purchased gas cost in the income statement when the related costs are recovered through our rates.
Risk management assets and liabilities, natural gas marketing segment -- The principal business of Atmos Energy Marketing, L.L.C. (AEM), including the activities of Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the southeastern and midwestern United States. AEM also supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis. Because AEM's operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Additionally, AEM's credit risk has increased due to higher natural gas prices this year as compared with the prior year. However, this risk is somewhat mitigated because a larger percentage of our business in the current year is with municipal customers as compared with the prior year.
In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. AEM links these gas futures to physical delivery of natural gas and typically balances its futures positions at the end of each trading day. However, at any point in time, AEM may not have completely offset its risk on these activities.
AEM also engages in limited speculative natural gas trading for its own account primarily related to its storage activity. Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day.
These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings, Inc. Compliance with this risk management policy is monitored on a daily basis. In addition, Woodward Marketing's bank credit facility limits trading positions that are not closed at the end of the day (open positions) to 5.0 Bcf of natural gas. AEM's open trading positions are monitored daily but are not required to be closed if they remain within the limits set by the bank loan agreement. At June 30, 2003, AEM's net open positions in its trading operations totaled 0.3 Bcf.
Those futures contracts that are designated as fair value hedges are recorded at fair value, on the balance sheet with an offsetting adjustment to the underlying item being hedged. Those financial contracts that are not designated as hedges are recorded on the balance sheet at fair value with current period changes in these contracts recorded as net gains or losses in our gas trading margin on the condensed consolidated statement of income. Any mark-to-market gains or losses on affiliate contracts are eliminated in consolidation.
Changes in the valuation of assets and liabilities arising from risk management activities primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. Market prices and models used to value these transactions reflect our best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under present market conditions. Changes in market prices directly affect our estimate of the fair value of these transactions.
As more fully described in Note 9, on October 25, 2002, the Emerging Issues Task Force (EITF) issued EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133. Prior to the issuance of EITF 02-03, we accounted for all energy trading contracts under the mark-to-market method in accordance with EITF 98-10. We recognized a cumulative effect of accounting change of $7.8 million, net of income tax benefit, upon the adoption of EITF 02-03 in the second quarter of fiscal 2003.
Comprehensive income -- The following table presents the components of comprehensive income, net of related tax, for the three-month and nine-month periods ended June 30, 2003 and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED
JUNE 30, JUNE 30,
------------------ -----------------
2003 2002 2003 2002
------- ------- ------- -------
(IN THOUSANDS)
Net income (loss)............................... $ (201) $3,254 $74,124 $65,265
Unrealized holding gains (losses) on
investments, net of tax expense of $808 and
tax benefit of $54 for the three months ended
June 30, 2003 and 2002 and of tax expense of
$319 and $100 for the nine months ended June
30, 2003 and 2002............................. 1,318 (92) 519 169
------ ------ ------- -------
Comprehensive income............................ $1,117 $3,162 $74,643 $65,434
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The only components of accumulated other comprehensive loss relate to unrealized holding gains and losses associated with certain available for sale investments and the minimum pension liability.
Stock-based compensation plans -- We have two stock-based compensation plans that provide for the granting of stock options and restricted stock to officers, key employees and non-employee directors. The objectives of these plans 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.
In October 1995, SFAS 123, Accounting for Stock-Based Compensation, was issued. This statement established a fair value-based method of accounting for employee stock options or similar equity instruments and encourages, but does not require, all companies to adopt that method of accounting for all of their employee stock compensation plans. SFAS 123 allows companies to continue to measure compensation cost for employee stock options or similar equity instruments using the intrinsic value method of accounting described in Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. We have elected to continue using the intrinsic value method as prescribed by APB 25. Under this method, no compensation cost for stock options is recognized for stock option awards granted at or above fair market value.
Prior to the merger with Atmos, certain United Cities Gas Company officers and key employees participated in the United Cities Long-Term Stock Plan implemented in 1989. At the time of the merger on July 31, 1997, we adopted this plan by registering a total of 250,000 shares of our common stock to be issued under the Long-Term Stock Plan for the Mid-States Division. Under this plan, incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock or any combination thereof may be granted to officers and key employees of the Mid-States Division. Options granted under the plan become exercisable at a rate of 20 percent per year and expire 10 years after the date of grant. For the nine months ended June 30, 2003, 13,000 options were exercised under the plan. For the nine months ended June 30, 2002, no options were exercised under the plan. At June 30, 2003, there were 6,300 options outstanding, all of which were fully vested. No incentive stock options, nonqualified stock options, stock appreciation rights or restricted stock have been granted under the plan since 1996. Because of the limited activities of this plan, the pro forma effects of applying SFAS 123 would have less than a $.01 per diluted share effect on earnings per share or $416 and $895 for the three months ended June 30, 2003 and 2002 and $1,922 and $3,277 for the nine months ended June 30, 2003 and 2002.
On August 12, 1998, our Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by our shareholders. An amendment to this plan increasing the share reserve by 2,500,000 shares was approved by the shareholders at the Company's annual meeting on February 13, 2002. The Long-Term Incentive Plan represents a part of our Total Rewards strategy which we developed as a result of a study we conducted of all employee, executive and non-employee director compensation and benefits. 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, restricted stock and performance-based stock to help attract, retain and reward employees and non-employee directors of Atmos and our subsidiaries.
We are authorized to grant awards for up to a maximum of 4,000,000 shares of common stock under the Long-Term Incentive Plan subject to certain adjustment provisions. As of June 30, 2003, only non-qualified stock options, bonus stock and restricted stock have been issued. The option price is equal to the market price of our stock at the date of grant. The stock options expire 10 years from the date of the grant and options vest annually over a service period ranging from one to three years. Awards of restricted stock are generally valued at the market price of the Company's common stock on the date of grant and recorded as unearned compensation within shareholders' equity. The unearned compensation is amortized to operation and maintenance expense over the vesting period of the restricted stock.
At June 30, 2003, we had 1,844,967 options outstanding under the Long-Term Incentive Plan at an exercise price ranging from $14.68 to $25.66. At June 30, 2002, we had 1,557,606 options outstanding under the Long-Term Incentive Plan at an exercise price ranging from $14.68 to $25.66. A summary of activity for grants of stock options under the Long-Term Incentive Plan for the nine months ended June 30, 2003 and 2002 follows:
NUMBER OF OPTIONS
-----------------------------
JUNE 30, 2003 JUNE 30, 2002
------------- -------------
Outstanding -- September 30................................. 1,557,606 1,009,330
Granted................................................... 142,360 148,877
Exercised................................................. -- --
Forfeited................................................. (30,000) (24,499)
--------- ---------
Outstanding -- December 31.................................. 1,669,966 1,133,708
--------- ---------
Granted................................................... 265,300 447,000
Exercised................................................. (333) (10,000)
Forfeited................................................. (2,500) --
--------- ---------
Outstanding -- March 31..................................... 1,932,433 1,570,708
--------- ---------
Granted................................................... 4,200 12,000
Exercised................................................. (74,999) (9,102)
Forfeited................................................. (16,667) (16,000)
--------- ---------
Outstanding -- June 30...................................... 1,844,967 1,557,606
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Restricted stock grants totaled 82,933 shares for the nine months ended June 30, 2003 and have a weighted average intrinsic value of $21.34 per share. Restricted stock grants totaled 22,204 shares for the nine months ended June 30, 2002 and have a weighted average intrinsic value of $21.30 per share.
Had compensation expense for our stock options been recognized based on the fair value on the grant date under the methodology prescribed by SFAS 123, our net income(loss) and earnings (loss) per share for the three and nine months ended June 30, 2003 and 2002 would have been impacted as shown in the following table:
THREE MONTHS ENDED NINE MONTHS ENDED
JUNE 30, JUNE 30,
------------------ -----------------
2003 2002 2003 2002
------- ------- ------- -------
(IN THOUSANDS)
Net income (loss) -- as reported........................ $ (201) $3,254 $74,124 $65,265
Restricted stock compensation expense included in
income, net of tax.................................... 14 117 187 378
Total stock-based employee compensation expense
determined under fair value based method for all
awards, net of taxes.................................. (271) (349) (884) (915)
------ ------ ------- -------
Net income (loss) -- pro forma.......................... $ (458) $3,022 $73,427 $64,728
====== ====== ======= =======
Earnings per share:
Basic earnings per share -- as reported............... $(0.00) $ 0.08 $ 1.66 $ 1.59
====== ====== ======= =======
Basic earnings per share -- pro forma................. $(0.01) $ 0.07 $ 1.64 $ 1.58
====== ====== ======= =======
Diluted earnings per share -- as reported............. $(0.00) $ 0.08 $ 1.65 $ 1.59
====== ====== ======= =======
Diluted earnings per share -- pro forma............... $(0.01) $ 0.07 $ 1.64 $ 1.57
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Recent Accounting Developments -- In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interest held in VIEs acquired prior to February 1, 2003, FIN 46 is effective July 1, 2003. We believe that the adoption of this interpretation will not have a material impact on our financial position, results of operations or net cash flows because Atmos currently does not have any interests in VIEs.
In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies the accounting and reporting for derivative instruments, including hedges. This statement amends SFAS 133 for decisions made by the Derivatives Implementation Group and by the FASB in connection with other projects dealing with financial instruments, and clarifies other implementation issues. SFAS 149 is effective for the Company on a prospective basis for contracts entered into or modified after June 30, 2003. We believe that the adoption of this statement will not have a material impact on our financial position, results of operations or net cash flows.
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Under SFAS 150, mandatorily redeemable financial instruments, obligations to repurchase the issuer's shares by transferring assets and certain obligations to issue a variable number of shares to settle that obligation must be classified as liabilities on the balance sheet and initially recorded at fair value. SFAS 150 is effective for the Company for financial instruments entered into or modified after May 31, 2003, and on July 1, 2003 for previously existing financial instruments. The adoption of SFAS 150 will not impact our financial position, results of operations or net cash flows as we currently do not use any of the financial instruments subject to this statement.
Reclassifications -- Certain prior period amounts have been reclassified to conform with the current year presentation.
2. ACQUISITION OF MISSISSIPPI VALLEY GAS COMPANY
On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), Mississippi's largest natural gas utility. We paid approximately $74.7 million in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. We also repaid approximately $70.9 million of MVG's outstanding debt. Beginning in December 2002, the results of operations of MVG have been consolidated with our results of operations.
The following table summarizes the fair values of the assets acquired and liabilities assumed, in thousands:
Net property, plant and equipment........................... $156,516
Current assets.............................................. 43,838
Other intangible assets..................................... 11,746
Goodwill.................................................... 90,007
Deferred charges and other assets........................... 10,670
--------
Total assets acquired..................................... 312,777
Current liabilities......................................... (47,637)
Noncurrent liabilities...................................... (92,613)
Other acquisition related costs............................. (23,227)
--------
Purchase price............................................ $149,300
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Other intangible assets represent the fair value of rights-of-way. The value assigned to goodwill was based on our belief that the acquisition of MVG will enable us to leverage our existing technology in order to add value to Atmos. We expect that the goodwill amount will not be deductible for tax purposes. Other acquisition-related costs consist of $13.1 million of make-whole premiums related to the repayment of MVG's debt and other costs including termination benefits.
The table below reflects the unaudited pro forma results of the Company and MVG for the three months ended June 30, 2002 as if the acquisition had taken place at the beginning of fiscal 2002.
THREE MONTHS ENDED
JUNE 30, 2002
------------------
(IN THOUSANDS)
Operating revenue........................................... $201,452
Net income.................................................. 3,976
Net income per diluted share................................ $ .09
|
The table below reflects the unaudited pro forma results of the Company and MVG for the nine months ended June 30, 2003 and 2002 as if the acquisition had taken place at the beginning of fiscal 2002.
NINE MONTHS ENDED
JUNE 30,
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS)
Operating revenue........................................... $1,385,454 $1,003,049
Income before cumulative effect of accounting change........ 78,729 78,361
Net income.................................................. 70,956 78,361
Income before cumulative effect of accounting change per
diluted share............................................. $ 1.75 $ 1.76
Net income per diluted share................................ $ 1.58 $ 1.76
|
3. CONTINGENCIES
On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto, against more than 200 companies in the natural gas industry including us and our Colorado-Kansas Division. The plaintiffs, who purport to represent a class consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, allege the defendants have underpaid royalties on gas taken from wells situated on non-federal and non-Indian lands throughout the United States and offshore waters predicated upon allegations that the defendants' gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. On April 10, 2000, this case was consolidated for pre-trial proceedings with other similar pending litigation in federal court in Wyoming in which we are also a defendant along with over 200 other defendants in the case of In Re Natural Gas Royalties Qui Tam Litigation. In January 2001, the federal court elected to remand this case back to the Kansas state court. A reconsideration of remand was filed, but it was denied. The state court now has jurisdiction over this proceeding and has issued a preliminary case management order. On April 10, 2003, the court denied the plaintiffs' motion to certify this proceeding as a class action, which ruling was appealed by the plaintiffs. The plaintiffs have filed a motion with the court for leave to amend their pleadings to which the defendants have filed an objection. Oral arguments were held on July 8, 2003, at which time the court indicated that it will make a ruling on the plaintiffs' motion in due course. We believe that the plaintiffs' claims are lacking in merit, and we intend to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.
On February 13, 2002, a suit was filed in the 287th District Court of Parmer County, Texas by Anderson Brothers, a Partnership, against Atmos Energy Corporation, et al. The plaintiffs' claims arise out of an alleged breach of contract by us and by a number of our divisions and subsidiaries concerning the sale of natural gas used in irrigation activities since 1998 and an alleged violation of the Texas Agricultural Gas Users Act of 1985. The court has ruled proper venue to be in Parmer County, Texas. We have been responding to numerous discovery requests from the plaintiffs. We also filed suit in Travis County, Texas to have the Texas Agricultural Gas Users Act of 1985 declared unconstitutional. The court denied our motion for summary judgment which we have appealed. The plaintiffs seek class action status and to recover unspecified damages plus attorneys' fees. We have denied any liability and intend to vigorously defend against the plaintiffs' claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.
We are a plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc. and ONEOK Energy Marketing and Trading Company II, filed in December 2001, pending in the District Court of Lubbock County, Texas, 72nd Judicial District. In this case, we are seeking to collect our receivable related to approximately 5.0 Bcf of natural gas that we believe was not delivered. We have signed a definitive purchase agreement that will allow us to receive certain distribution assets in exchange for a partial reduction of the outstanding receivable. We continue to seek collection of the remaining outstanding balance and believe this amount is fully recoverable.
United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a party to an action filed in June 2000 which is pending in the Circuit Court of Sevier County, Tennessee. The plaintiffs' claims arise out of injuries alleged to have been caused by a low-level propane explosion. The plaintiffs seek to recover damages of $13.0 million. Discovery activities have begun in this case. We have denied any liability, and we intend to vigorously defend against the plaintiffs' claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.
We are a party to other litigation and claims that arise in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims will not have a material adverse effect on our financial condition, results of operations or net cash flows.
We are the owner or previous owner of manufactured gas plant sites in Johnson City and Bristol, Tennessee and Hannibal, Missouri which were used to supply gas prior to the availability of natural gas. The gas manufacturing process resulted in certain by-products and residual materials including coal tar. The manufacturing process used by our predecessors was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, we may be responsible for response actions with respect to such materials if response actions are necessary.
United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of 1997 which we have continued through June 30, 2003. The investigative phase of the work at the site has been completed and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We have completed a risk assessment report which is currently under review by the TDEC. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements.
In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site which was completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site and we have proposed performing a focused removal action to remove any such residuals. The TDEC has requested that the focused removal action be conducted pursuant to a voluntary agreement. We are in the process of negotiating the voluntary agreement with TDEC and hope to conduct the focused removal action later this year.
On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources addressing the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action, a subsequent site evaluation and to reimburse the response costs incurred by the state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site evaluation field work was conducted in August 1999. A risk assessment for the site has been completed and is currently under review by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site use limitations including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water.
As of June 30, 2003, we had incurred costs of approximately $1.1 million for the investigations of the Johnson City and Bristol, Tennessee and Hannibal, Missouri sites and had a remaining accrual relating to these sites of $0.8 million.
We have completed investigation and remediation activities pursuant to Consent Orders between the Kansas Department of Health and Environment (KDHE) and United Cities Gas Company. The Orders provided for the investigation and remediation of mercury contamination at gas pipeline sites which utilize or formerly utilized mercury meter equipment in Kansas. The Final Interim Characterization and Remediation Report has been submitted to the KDHE. We amended the Orders with the KDHE to include all mercury meters that belonged to our Colorado-Kansas Division before the merger with United Cities Gas Company on July 31, 1997. All work on these sites has been completed. A report describing the results of the work has been submitted to the KDHE. As of June 30, 2003, we had incurred costs of $0.3 million for these sites and had a remaining accrual of $0.2 million for recovery.
We are a party to other environmental matters and claims that arise out of our ordinary business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance.
The limited partnership agreement of U.S. Propane, L.P., an entity in which we own an approximate 19 percent membership interest, requires that in the event of liquidation, all limited partners would be required to restore capital account deficiencies, including any unsatisfied obligations of the partnership. Under the agreement, our maximum capital account restoration is $4.7 million. As of June 30, 2003, our capital account was positive.
4. EQUITY OFFERING
On June 23, 2003, we completed a public offering of 4,000,000 shares of our common stock. The offering was priced at $25.31 per share and generated net proceeds of approximately $96.8 million. The proceeds were used to partially fund our pension plan, to repay short-term debt and to fund general corporate purposes including the purchase of natural gas for storage. We sold an additional 100,000 shares of our common stock in July 2003 when our underwriters exercised their overallotment option, which generated net proceeds of approximately $2.4 million.
5. PENSION PLAN CONTRIBUTION
In June 2003, we contributed into the Atmos Master Retirement Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. Of the total cash contributed, $26.1 million represented a fiscal 2002 contribution, which was deducted on our 2002 tax return. The cash contribution was financed through a combination of cash on hand and a portion of the net proceeds received from our June 2003 public offering discussed above.
6. SHORT-TERM DEBT
At June 30, 2003, short-term debt consisted of $0.7 million of commercial paper.
We have two short-term committed credit facilities totaling $318.0 million. The first short-term unsecured credit facility is for $300.0 million and serves as a backup liquidity facility for our commercial paper program. Our commercial paper is rated A-2 by Standard and Poor's, P-2 by Moody's and F-2 by Fitch. At June 30, 2003, $0.7 million of commercial paper was outstanding. We have a second unsecured facility in place for $18.0 million. At June 30, 2003, there were no borrowings under this credit facility. These credit facilities are negotiated at least annually and are used for working capital purposes. In July 2003, we successfully negotiated a renewal of the first credit facility and increased the level of commitment to $350.0 million. The new facility contains substantially the same terms as those of the prior facility and will expire in July 2004.
On October 7, 2002, we entered into a $150.0 million short-term unsecured committed credit facility. This credit facility was used to provide initial funding for the cash portion of the MVG acquisition and to repay MVG's existing debt. A total of $147.0 million was borrowed under this credit facility during the first quarter. This amount was refinanced in January 2003 with a portion of the proceeds of our $250.0 million debt offering, as discussed in Note 7.
Our Woodward Marketing subsidiary has a $210.0 million uncommitted demand working capital credit facility. Atmos Energy Holdings, Inc. (AEH) and Atmos Energy Marketing, L.L.C., our wholly-owned subsidiaries, are guarantors of all amounts outstanding under this facility. At June 30, 2003, no amount was outstanding under this credit facility, although letters of credit totaling $99.2 million reduced the amount available. 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 Woodward Marketing under this credit facility at June 30, 2003 was $64.4 million. This credit facility expires on March 31, 2004.
We also have an unsecured short-term uncommitted credit line for $20.0 million. There were no borrowings under this uncommitted credit facility at June 30, 2003. 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 a when- and as-available basis at the discretion of the bank. This facility is also used for working capital purposes.
In addition, Woodward Marketing has a $100.0 million intercompany credit facility with AEH for its non-utility business. Any outstanding amounts under this facility are subordinated to Woodward Marketing's $210.0 million uncommitted demand credit facility described above. At June 30, 2003, $50.0 million was outstanding under this facility. In July 2003, Woodward and AEH agreed to increase the interest rate on the intercompany credit facility from LIBOR plus 1.25 percent to LIBOR plus 2.75 percent.
7. LONG-TERM DEBT
On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013 under our existing $600.0 million shelf registration statement. The net proceeds of $249.3 million were used to repay $147.0 million borrowed under a short-term acquisition credit facility used to provide the initial financing of our acquisition of MVG, as well as for general corporate purposes.
In addition, we repaid $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program with a portion of the net proceeds received from the debt offering. The repayment of the unsecured senior notes resulted in a make-whole premium of $9.3 million.
8. EARNINGS PER SHARE
Basic earnings per share has been computed by dividing net income (loss) for the period by the weighted average number of common shares outstanding during the period. Diluted earnings per share has been computed by dividing net income (loss) for the period by the weighted average number of common shares outstanding during the period adjusted for restricted stock and other contingently issuable shares of common stock. Net income (loss) for basic and diluted earnings per share are the same, as there is no income impact from assumed conversions of potentially dilutive securities. A reconciliation between basic and diluted weighted average common shares outstanding follows:
FOR THE FOR THE
THREE MONTHS ENDED NINE MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2003 2002 2003 2002
------- ------- ------- -------
(IN THOUSANDS)
Weighted average common shares -- basic.......... 45,997 41,265 44,679 41,049
Effect of dilutive securities:
Restricted stock............................... -- 67 122 67
Stock options.................................. -- 38 78 28
------ ------ ------ ------
Weighted average common shares -- assuming
dilution....................................... 45,997 41,370 44,879 41,144
====== ====== ====== ======
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There were approximately 84,000 options and approximately 122,000 shares of restricted stock excluded from the computation of diluted earnings per share for the three months ended June 30, 2003 as their inclusion in the computation would be anti-dilutive. There were no options or shares of restricted stock excluded from the computation of diluted earnings per share for the remaining periods presented above.
9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We conduct our risk management activities through both our utility and natural gas marketing segments. The following table shows our risk management assets and liabilities by segment at June 30, 2003.
NATURAL GAS
UTILITY MARKETING TOTAL
------- ----------- --------
(IN THOUSANDS)
Assets from risk management activities, current...... $ 1,039 $ 17,607 $ 18,646
Assets from risk management activities, noncurrent... -- 1,635 1,635
Liabilities from risk management activities,
current............................................ (1,837) (11,419) (13,256)
Liabilities from risk management activities,
noncurrent......................................... -- (549) (549)
------- -------- --------
Net assets (liabilities)............................. $ (798) $ 7,274 $ 6,476
======= ======== ========
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For the 2002-2003 heating season, we covered approximately 51 percent of our anticipated flowing gas requirements through a combination of storage, financial hedges and fixed forward contracts at a weighted average cost of less than $4.00 per Mcf. This provided a measure of protection to us and our customers against potential sharp increases in the price of natural gas during the 2002-2003 heating season.
Our non-utility hedging activities are conducted through AEM, which include the activities of Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. At the close of business on June 30, 2003, we had outstanding contracts representing 0.3 Bcf of net notional volumes with average contract maturities of less than three years. As of June 30, 2003, contracts representing 99 percent of the fair value of these contracts are scheduled to mature within three years.
AEM also engages in limited speculative natural gas trading for its own account primarily related to its storage activity. These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings. Compliance with this risk management policy is monitored on a daily basis. In addition, Woodward Marketing's bank credit facility limits trading positions that are not closed at the end of the day (open positions) to 5.0 Bcf of natural gas. AEM's open trading positions are monitored daily but are not required to be closed if they remain within the limits set by the bank loan agreement. At June 30, 2003, AEM's net open positions in its trading operations totaled 0.3 Bcf.
For the three months ended June 30, 2003, our gas trading margin consisted of an $11.9 million realized trading gain and a $4.1 million unrealized trading loss. For the three months ended June 30, 2002, our gas trading margin consisted of a $2.8 million realized trading gain and a $9.5 million unrealized trading gain.
For the nine months ended June 30, 2003, our gas trading margin consisted of a $7.6 million realized trading gain and a $7.2 million unrealized trading gain. For the nine months ended June 30, 2002, our gas trading margin consisted of a $37.1 million realized trading gain and an $8.1 million unrealized trading loss.
On October 25, 2002, through the issuance of EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, the EITF rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, thereby precluding the use of mark-to-market accounting for inventory and energy trading contracts that are not derivatives. During the quarter ended December 31, 2002, energy trading contracts entered into on or before October 25, 2002 were marked to market pursuant to the provisions of EITF 98-10. Energy trading contracts entered into after October 25, 2002 have been prospectively accounted for pursuant to the provisions of SFAS 133.
Prior to December 31, 2002, we had recorded $12.9 million of unrealized income related to our storage contracts and certain full requirements contracts in accordance with EITF 98-10. On January 1, 2003, we reversed this unrealized income, which was reported as a cumulative effect of a change in accounting principle in accordance with APB 20, Accounting Changes.
Additionally, beginning January 1, 2003, all energy trading contracts are being accounted for pursuant to the provisions of SFAS 133. As a result, many of our index priced contracts qualify for the normal purchases and sales exception under SFAS 133 and are not marked to market for changes in value subsequent to December 31, 2002.
Finally, effective January 1, 2003, we designated a portion of our futures contracts as fair value hedges of the natural gas marketing segment's gas inventory. Accordingly, the inventory was adjusted to cost as of January 1, 2003 as part of the cumulative effect adjustment, but subsequent changes in fair value will be recognized as an adjustment to the carrying value of the hedged inventory.
The cumulative noncash charge in the second quarter of fiscal 2003 was $7.8 million, net of $5.1 million of applicable income tax benefit. As performance under these inventory, storage and transportation contracts is completed, the applicable income is recognized. Originally, $6.0 million was expected to be realized in net income in fiscal 2003, $1.2 million in fiscal 2004 and $0.6 million thereafter. However, actual results to date are less than originally estimated, due to the extreme market volatility.
From time to time, Woodward Marketing borrows money to fund its natural gas purchases and to fulfill its obligations to maintain deposit accounts with its counterparties. See Note 6 to the condensed consolidated financial statements.
Financial instruments, which subject AEM to counterparty risk, consist primarily of financial instruments arising from trading and risk management activities that are not insured. Counterparty risk is the risk of loss from nonperformance by financial counterparties to a contract. Exchange-traded future and option contracts are generally guaranteed by the exchanges.
In June 2001, we purchased a three year weather insurance policy with an option to cancel the third year of coverage. The insurance was designed for our Texas and Louisiana operations to protect against weather that was at least seven percent warmer than normal for the entire heating season of October to March beginning with the 2001-2002 heating season. The cost of the three year policy was $13.2 million, which was prepaid and was amortized over the appropriate heating seasons based on degree days. Because weather was not at least seven percent warmer than normal, no income was recognized under this insurance policy during the nine months ended June 30, 2003 and 2002. Amortization expense of $5.0 million and $4.4 million was recognized during the nine months ended June 30, 2003 and 2002. Included in the amortization expense for the nine months ended June 30, 2003 was a third quarter charge of $0.6 million, net of cash received, related to the cancellation of the third year of coverage on our weather insurance policy primarily as a result of rate relief in Louisiana and prospects for weather normalization adjustments in Texas.
10. SEGMENT INFORMATION
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. The accounting policies of the segments are the same as those described in the summary of significant accounting policies included in Note 1 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended September 30, 2002. All intersegment sales prices are market based. We evaluate performance based on net income or loss of the respective operating units.
In accordance with SFAS 131, Disclosures about Segments of an Enterprise and Related Information, we have identified the Utility, Natural Gas Marketing and Other Non-Utility segments. For an expanded description of these segments, please refer to Note 1 to the consolidated financial statements in our Annual Report on Form 10-K for the year ended September 30, 2002. We consider each division within our utility segment to be a reporting unit of the utility segment and not a reportable segment. The individual operations that comprise the other non-utility segment are not currently material to our consolidated financial position or results of operations and therefore do not require separate reporting. Income from our other non-utility segment is generated primarily from pipeline and storage operations.
Included in purchased gas cost for the utility segment were purchases from AEM of $80.2 million and $51.0 million for the three months ended June 30, 2003 and 2002 and $272.2 million and $157.2 million for the nine months ended June 30, 2003 and 2002. Volumes purchased were 14.7 Bcf and 14.8 Bcf for the three months ended June 30, 2003 and 2002 and 50.5 Bcf and 56.7 Bcf for the nine months ended June 30, 2003 and 2002. These purchases were made in a competitive open bidding process and reflect market prices. Average prices per Mcf for gas purchased from AEM were $5.45 and $3.45 for the three months ended June 30, 2003 and 2002 and $5.38 and $2.77 for the nine months ended June 30, 2003 and 2002. In addition, our regulated utility divisions have entered into contracts with AEM to manage a significant portion of our regulated utility divisions' underground storage facilities. AEM has acted as agent in placing financial instruments for the various regulated utility divisions that partially protect us and our customers from unusually large winter period gas price increases.
Summarized financial information concerning our reportable segments for the three and nine months ended June 30, 2003 and 2002 are shown in the following table:
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY TOTAL
---------- ----------- ----------- ----------
(IN THOUSANDS)
For the three months ended June 30,
2003:
Operating revenues for reportable
segments............................ $ 245,998 $ 152 $ 3,685 $ 249,835
Elimination of intersegment
revenues............................ (257) (152) (1,637) (2,046)
---------- -------- ------- ----------
Total operating revenues......... 245,741 -- 2,048 247,789
Gas trading margin.................... -- 7,858 -- 7,858
Net income (loss)..................... (4,617) 3,516 900 (201)
For the three months ended June 30,
2002:
Operating revenues for reportable
segments............................ $ 159,493 $ 169 $ 3,889 $ 163,551
Elimination of intersegment
revenues............................ (271) -- (1,480) (1,751)
---------- -------- ------- ----------
Total operating revenues......... 159,222 169 2,409 161,800
Gas trading margin.................... -- 12,259 -- 12,259
Net income (loss)..................... (1,954) 5,167 41 3,254
As of and for the nine months ended
June 30, 2003:
Operating revenues for reportable
segments............................ $1,342,527 $ 468 $16,242 $1,359,237
Elimination of intersegment
revenues............................ (969) (468) (8,103) (9,540)
---------- -------- ------- ----------
Total operating revenues......... 1,341,558 -- 8,139 1,349,697
Gas trading margin.................... -- 14,801 -- 14,801
Cumulative effect of accounting
change, net of income tax benefit... -- (7,773) -- (7,773)
Net income (loss)..................... 70,494 (4,563) 8,193 74,124
Total assets.......................... 2,192,316 299,148 96,652 2,588,116
As of and for the nine months ended
June 30, 2002:
Operating revenues for reportable
segments............................ $ 801,460 $ 509 $20,848 $ 822,817
Elimination of intersegment
revenues............................ (1,219) -- (8,975) (10,194)
---------- -------- ------- ----------
Total operating revenues......... 800,241 509 11,873 812,623
Gas trading margin.................... -- 29,026 -- 29,026
Net income............................ 51,567 9,726 3,972 65,265
Total assets.......................... 1,748,231 237,292 73,383 2,058,906
|
A reconciliation of total assets for the reportable segments to total consolidated assets for June 30, 2003 and 2002 is presented below:
JUNE 30,
-----------------------
2003 2002
---------- ----------
(IN THOUSANDS)
Total assets for reportable segments........................ $2,588,116 $2,058,906
Elimination of intercompany accounts........................ (209,776) (137,934)
---------- ----------
Total consolidated assets................................. $2,378,340 $1,920,972
========== ==========
|
11. SUPPLEMENTAL DISCLOSURES
The following supplemental condensed financial statements show our three operating segments and the elimination of material intercompany transactions. The following supplemental condensed balance sheet is as of June 30, 2003.
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
ASSETS
Property, plant and equipment,
net............................. $1,426,975 $ 9,267 $ 58,203 $ -- $1,494,445
Investment in subsidiaries........ 127,664 (2,669) -- (124,995) --
Current assets
Cash and cash equivalents....... 86 17,495 (260) -- 17,321
Accounts receivable, net........ 102,670 182,398 50,894 (84,544) 251,418
Inventories..................... 5,271 -- 218 -- 5,489
Gas stored underground.......... 45,439 32,478 1,568 -- 79,485
Assets from risk management
activities................... 1,039 17,844 -- (237) 18,646
Other current assets and
prepayments.................. (390) 7,443 3,552 -- 10,605
Intercompany receivables........ 76,827 2,812 (79,639) -- --
---------- -------- -------- --------- ----------
Total current assets......... 230,942 260,470 (23,667) (84,781) 382,964
Intangible assets................. -- 5,248 -- -- 5,248
Goodwill.......................... 240,294 22,600 12,127 -- 275,021
Noncurrent assets from risk
management activities........... -- 1,635 -- -- 1,635
Deferred charges and other
assets.......................... 166,441 2,597 49,989 -- 219,027
---------- -------- -------- --------- ----------
$2,192,316 $299,148 $ 96,652 $(209,776) $2,378,340
========== ======== ======== ========= ==========
SHAREHOLDERS' EQUITY AND
LIABILITIES
Shareholders' equity.............. $ 827,453 $ 71,166 $ 56,498 $(127,664) $ 827,453
Long-term debt.................... 858,720 -- 5,628 -- 864,348
---------- -------- -------- --------- ----------
Total capitalization......... 1,686,173 71,166 62,126 (127,664) 1,691,801
Current liabilities
Current maturities of long-term
debt......................... 8,227 -- 1,520 -- 9,747
Short-term debt................. 700 -- -- -- 700
Liabilities from risk management
activities................... 1,837 11,419 -- -- 13,256
Deferred gas cost............... 19,351 9,586 925 -- 29,862
Other current liabilities....... 187,550 207,881 15,219 (82,112) 328,538
---------- -------- -------- --------- ----------
Total current liabilities.... 217,665 228,886 17,664 (82,112) 382,103
Deferred income taxes............. 159,623 (3,228) 7,048 -- 163,443
Noncurrent liabilities from risk
management activities........... -- 549 -- -- 549
Deferred credits and other
liabilities..................... 128,855 1,775 9,814 -- 140,444
---------- -------- -------- --------- ----------
$2,192,316 $299,148 $ 96,652 $(209,776) $2,378,340
========== ======== ======== ========= ==========
|
The following supplemental condensed statement of income is for the three months ended June 30, 2003.
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
-------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
Operating revenues.................. $245,998 $377,766 $3,685 $(379,660) $247,789
Purchased gas cost.................. 161,426 367,395 467 (368,705) 160,583
-------- -------- ------ --------- --------
Gross profit...................... 84,572 10,371 3,218 (10,955) 87,206
Gas trading margin.................. -- (2,795) -- 10,653 7,858
Operating expenses.................. 78,306 1,375 1,490 (163) 81,008
-------- -------- ------ --------- --------
Operating income (loss)............. 6,266 6,201 1,728 (139) 14,056
Miscellaneous income (expense)...... 1,347 430 662 (1,753) 686
Interest charges.................... (16,235) (662) (898) 1,753 (16,042)
-------- -------- ------ --------- --------
Income (loss) before income taxes... (8,622) 5,969 1,492 (139) (1,300)
Income tax expense (benefit)........ (4,005) 2,370 592 (56) (1,099)
-------- -------- ------ --------- --------
Net income (loss).............. $ (4,617) $ 3,599 $ 900 $ (83) $ (201)
======== ======== ====== ========= ========
|
The following supplemental condensed statement of income is for the nine months ended June 30, 2003.
NATURAL GAS OTHER
UTILITY MARKETING NON-UTILITY ELIMINATIONS CONSOLIDATED
---------- ----------- ----------- ------------ ------------
(IN THOUSANDS)
Operating revenues............... $1,342,527 $1,330,479 $16,242 $(1,339,551) $1,349,697
Purchased gas cost............... 934,649 1,325,655 1,475 (1,332,479) 929,300
---------- ---------- ------- ----------- ----------
Gross profit................... 407,878 4,824 14,767 (7,072) 420,397
Gas trading margin............... -- 6,353 -- 8,448 14,801
Operating expenses............... 248,485 7,366 5,313 (524) 260,640
---------- ---------- ------- ----------- ----------
Operating income................. 159,393 3,811 9,454 1,900 174,558
Miscellaneous income (expense)... (872) 1,703 6,067 (3,577) 3,321
Interest charges................. (47,231) (2,090) (1,935) 3,577 (47,679)
---------- ---------- ------- ----------- ----------
Income before income taxes and
cumulative effect of accounting
change......................... 111,290 3,424 13,586 1,900 130,200
Income tax expense............... 40,796 1,360 5,393 754 48,303
---------- ---------- ------- ----------- ----------
Income before cumulative effect
of accounting change........... 70,494 2,064 8,193 1,146 81,897
Cumulative effect of accounting
change, net of income taxes
(benefit)...................... -- (9,710) -- 1,937 (7,773)
---------- ---------- ------- ----------- ----------
Net income (loss)........... $ 70,494 $ (7,646) $ 8,193 $ 3,083 $ 74,124
========== ========== ======= =========== ==========
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Organization -- Atmos Energy Corporation distributes natural gas in 12 states through its regulated utility operating divisions -- Colorado-Kansas Division, Kentucky Division, Louisiana Division, Mid-States Division, Mississippi Valley Gas Company Division and Texas Division. Our nonutility operations are organized under Atmos Energy Holdings, Inc., which includes Atmos Energy Marketing, L.L.C., Atmos Pipeline and Storage, Inc., Atmos Power Systems, Inc. and an indirect equity interest in Heritage Propane Partners, L.P. Atmos Energy Marketing includes the operations of Woodward Marketing and Trans Louisiana Industrial Gas Company.
Consolidating Financial Statements -- The column headed "Utility" consists of the operations of Atmos' six utility operating divisions. The column headed "Natural Gas Marketing" consists of Atmos Energy Marketing, Woodward Marketing and Trans Louisiana Industrial Gas Company. The column headed "Other Non-Utility" consists of our nonutility operations excluding natural gas marketing. Operating revenues and purchased gas costs from our natural gas marketing operations are shown on a gross basis in the "Natural Gas Marketing" column. Such natural gas marketing activities are reclassified in the elimination column as gas trading margin.
Current and noncurrent assets and liabilities from risk management activities on the supplemental condensed consolidated balance sheet consist of the fair value, inclusive of future servicing costs and valuation adjustments, of our forwards, over-the-counter and exchange traded options, futures and swap contracts.
The gas trading margin on the supplemental condensed consolidated statement of income consists primarily of the difference between revenue arising from Natural Gas Marketing's sale of physical natural gas to its customers less the cost to purchase natural gas and current period changes in assets and liabilities from risk management activities.
Eliminations -- Included in purchased gas cost in the Utility column are natural gas purchases from Atmos Energy Marketing. These purchases were made in a competitive open bidding process and reflect market prices. In addition, our utility divisions have entered into contracts with Atmos Energy Marketing to manage a significant portion of their underground storage facilities. Atmos Energy Marketing has acted as agent in obtaining hedging agreements for our utility divisions that protect them and our utility customers from unusually large winter period gas price increases.
The Board of Directors
Atmos Energy Corporation
We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of June 30, 2003 and the related condensed consolidated statements of income for the three-month periods and nine-month periods ended June 30, 2003 and 2002 and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2003 and 2002. These financial statements are the responsibility of the Company's management.
We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should be made to the accompanying condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2002, and the related consolidated statements of income, shareholders' equity and cash flows for the year then ended (not presented herein) and in our report dated November 8, 2002, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Dallas, Texas
August 8, 2003
INTRODUCTION
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management's Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2002.
The statements contained in this Quarterly Report on Form 10-Q may contain "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of the Company's documents or oral presentations, the words "anticipate," "expect," "estimate," "plans," "believes," "objective," "forecast," "goal" or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to the Company's strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions such as warmer than normal weather in the Company's service territories; national, regional and local economic conditions, including competition from other energy suppliers as well as alternative forms of energy; regulatory approvals, including the impact of rate proceedings before various state regulatory commissions; successful completion and integration of future acquisitions; inflation and increased gas costs, including their effect on commodity prices for natural gas; increased competition; further deregulation or "unbundling" of the natural gas distribution industry; hedging and market risk activities and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. A discussion of these risks and uncertainties may be found in the Company's Form 10-K for the year ended September 30, 2002. Accordingly, while the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.
OVERVIEW
Atmos Energy Corporation and its subsidiaries are primarily engaged in the natural gas utility business as well as certain non-utility businesses. Our operations are divided into three segments: the utility segment, which includes our regulated natural gas distribution and sales operations; the natural gas marketing segment, which includes Atmos Energy Marketing, L.L.C., Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc.; and our other non-utility segment, which includes all of our other non-utility operations.
Our utility business distributes natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers. Our utility business is composed of six regulated utility divisions:
- Atmos Energy Colorado-Kansas Division
- Atmos Energy Kentucky Division
- Atmos Energy Louisiana Division
- Atmos Energy Mid-States Division
- Atmos Energy Texas Division
The service areas of our divisions are located in Colorado, Georgia, Illinois, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Tennessee, Texas and Virginia. Our utility business is subject to regulation by state and/or local authorities in each of the states in which we operate. We receive gas deliveries in our utility operations through 36 pipeline transportation companies, both interstate and intrastate, to satisfy our sales requirements. The pipeline transportation agreements are uninterruptible and many of them have pipeline no-notice storage service, which provides for daily balancing between system requirements and physical quantities requested by our customers. We also transport natural gas for others through our distribution system.
The effects of weather that is above or below normal are offset partially in the Tennessee and Georgia jurisdictions served by the Mid-States Division, in the Mississippi jurisdiction served by the Mississippi Valley Gas Company Division, in the Kentucky jurisdiction served by the Kentucky Division and, beginning in fiscal 2004, in the Kansas jurisdiction served by the Colorado-Kansas Division, through weather normalization adjustments (WNA). The Tennessee Regulatory Authority, the Georgia Public Service Commission, the Mississippi Public Service Commission and the Kentucky Public Service Commission have approved WNA. WNA, effective from October through May each year in Georgia, November through May each year in Mississippi and November through April of each year in Tennessee and Kentucky, allows us to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. Approximately 659,000 or 39 percent of our meters in service are located in Tennessee, Georgia, Mississippi and Kentucky. In May 2003, we received approval from the Kansas Public Service Commission for WNA in our Kansas jurisdiction served by our Colorado-Kansas Division. The WNA in Kansas will be effective October through May of each year beginning in fiscal 2004. We do not have WNA in our other service areas.
Our natural gas marketing and other non-utility segments, which are organized under Atmos Energy Holdings, Inc., have operations in 18 states. Atmos Energy Marketing, L.L.C. (AEM), together with its wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprise our natural gas marketing segment. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services primarily consist of the furnishing of natural gas supplies at fixed and market-based prices, load forecasting and management, gas storage and transportation services, peaking sales and balancing services and gas price hedging through the use of derivative products. In addition, Trans Louisiana Industrial Gas Company markets natural gas primarily to commercial customers in Louisiana.
AEM's management of natural gas requirements involves the sale of natural gas and the management of storage and transportation contracts under contracts with customers generally having one to two year terms. At June 30, 2003, AEM had a total of 589 industrial customers and 140 municipal customers. AEM also sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. In addition, AEM supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis.
We own or have an interest in underground storage fields in Kansas, Kentucky, Louisiana and Mississippi which are used to help meet customer requirements in Kansas, Kentucky, Louisiana, Mississippi, Tennessee and other states during peak demand periods and to reduce the need to contract for additional pipeline capacity to meet such peak demand periods. The total storage capacity that we own is approximately 30.6 Bcf. However, approximately 14.7 Bcf of gas in the storage facilities must be retained as cushion gas to maintain reservoir pressure. In addition, we have access to additional storage with a total capacity of 6.9 Bcf.
We purchase our gas supply from various producers and marketers. Supply arrangements are contracted on an uninterruptible basis with various terms and at market prices.
We also construct and operate electrical peaking power generating plants and associated facilities and may enter into agreements to either lease or sell such plants.
Finally, we own an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies. As of June 30, 2003, USP owned all of the general partnership interest and approximately 26 percent of the limited partnership interest in Heritage Propane Partners, L.P. a marketer of propane through a nationwide retail distribution network.
HIGHLIGHTS
- Net loss of $0.2 million or $0.0 per diluted share for the three months ended June 30, 2003, compared to net income of $3.3 million, or $.08 per diluted share for the three months ended June 30, 2002. Net income of $74.1 million or $1.65 per diluted share for the nine months ended June 30, 2003, compared to $65.3 million, or $1.59 per diluted share for the nine months ended June 30, 2002.
- On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), a privately held utility, for approximately $150.0 million, which consisted of approximately $74.7 million in cash and 3,386,287 unregistered shares of our common stock. In addition, we paid approximately $70.9 million to repay outstanding debt of MVG. Our Mississippi Valley Gas Company Division provides natural gas distribution service to approximately 283,000 residential, industrial and other customers located primarily in the northern and central regions of Mississippi.
- In January 2003, as a result of the adoption of EITF 02-03, we recorded a cumulative effect adjustment of $12.9 million ($7.8 million, net of income tax benefit) on the condensed consolidated statements of income.
- On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013. The net proceeds were used to repay debt under a short-term acquisition credit facility used to partially finance the MVG acquisition, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes.
- On June 23, 2003, we completed a public offering of 4,000,000 shares of our common stock. The offering was priced at $25.31 per share and generated net proceeds of approximately $96.8 million. The proceeds were used to partially fund our pension plan, to repay short-term debt and to fund general corporate purposes including the purchase of natural gas for storage. We sold an additional 100,000 shares of our common stock in July 2003 when our underwriters exercised their overallotment option, which generated net proceeds of approximately $2.4 million.
- In June 2003, we contributed into the Atmos Master Retirement Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million. The cash contribution was financed through a combination of cash on hand and a portion of the net proceeds received from our June 2003 public offering discussed previously.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
General -- Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements required us to make estimates and judgments that affected the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believed to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, goodwill and pension and other post retirement plans. Actual results may differ from estimates.
Regulation -- Our utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates.
Risk management assets and liabilities, utility segment -- We use a combination of storage and financial hedges to protect us and our customers against unusually large winter period gas price increases. The financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However, because these costs will ultimately be recovered through our rates, current period changes in the assets and liabilities from risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71. Accordingly, there is no earnings impact as a result of the use of these financial instruments. The changes in the assets and liabilities from risk management activities are recognized in purchased gas cost in the income statement when the related costs are recovered through our rates.
Risk management assets and liabilities, natural gas marketing segment -- The principal business of AEM, including the activities of Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the southeastern and midwestern United States. AEM also supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis. Because AEM's operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Additionally, AEM's credit risk has increased due to higher natural gas prices this year as compared with the prior year. However, this risk is somewhat mitigated because a larger percentage of our business in the current year is with municipal customers as compared with the prior year.
In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. AEM links these gas futures to physical delivery of natural gas and typically balances its futures positions at the end of each trading day. However, at any point in time, AEM may not have completely offset its price risk on these activities.
AEM also engages in limited speculative natural gas trading for its own account primarily related to its storage activity. Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day.
These trading activities are subject to a risk management policy which limits the level of trading loss to a maximum of 25 percent of the budgeted annual operating income of Atmos Energy Holdings, Inc.
Those futures contracts that are designated as fair value hedges are recorded at fair value on the balance sheet with an offsetting adjustment to the underlying item being hedged. Those financial contracts that are not designated as hedges are recorded on the balance sheet at fair value with current period changes in these contracts recorded as net gains or losses in our gas trading margin on the condensed consolidated statement of income. Any mark-to-market gains or losses on affiliate contracts are eliminated in consolidation.
Changes in the valuation of assets and liabilities arising from risk management activities primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. Market prices and models used to value these transactions reflect our best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under present market conditions. Changes in market prices directly affect our estimate of the fair value of these transactions.
As more fully described in Note 9 to the condensed consolidated financial statements, on October 25, 2002, the Emerging Issues Task Force (EITF) issued EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, which rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Prior to the issuance of EITF 02-03, we accounted for all energy trading contracts under the mark-to-market method in accordance with EITF 98-10. We recognized a cumulative effect of accounting change of $7.8 million, net of income tax benefit, upon the adoption of EITF 02-03 in the second quarter of fiscal 2003.
Allowance for Doubtful Accounts -- For the majority of our receivables, we establish an allowance for doubtful accounts based on an aging of those receivable balances. We apply percentages to each aging category based on our collections experience. On certain other receivables where we are aware of a specific customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. We believe our allowance for doubtful accounts is adequate. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions.
Goodwill -- We annually evaluate our goodwill balances for impairment during our second fiscal quarter or as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting groups. If our projections of estimated future cash flows change, those changes could result in a reduction in the carrying value of our goodwill. Our evaluation performed during the quarter ended March 31, 2003 resulted in no impairment.
Pension and Other Postretirement Plans -- Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The assumed return on plan assets is based on management's expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities generally is based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid.
The primary factors that impact our results of utility operations are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas sales to residential, commercial and public authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Accordingly, our second fiscal quarter historically has been our most critical earnings quarter with an average of 76 percent of our net income having been earned in the second quarter during the three most recently completed fiscal years. Sales to industrial customers are much less weather sensitive. Sales to agricultural customers, who typically use natural gas to power irrigation pumps during the period from March through September, are primarily affected by rainfall amounts and the price of natural gas. Changes in the cost of gas impact revenue but do not directly affect our gross profit from utility operations because the fluctuations in gas prices are passed through to the customer.
Our non-utility segment generates income from its industrial, utility and municipal customers through negotiated prices based on the volume of gas supplied to the customer. It also generates income by taking advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices by utilizing storage and transportation capacity that it controls.
At times, we maintain a net open position related to our physical storage when we believe that future changes in prices and market conditions may result in profitable positions. Net open positions may result in an adverse impact on our financial condition or results of operations if the market price does not react in the manner or direction that we expected. Our risk management control policy contains limits associated with the overall size of open positions.
The following table presents our financial highlights for the three and nine months ended June 30, 2003 and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED
JUNE 30, JUNE 30,
------------------- ---------------------
2003 2002 2003 2002
-------- -------- ---------- --------
(IN THOUSANDS, UNLESS OTHERWISE NOTED)
Operating revenues....................... $247,789 $161,800 $1,349,697 $812,623
Gross profit............................. 87,206 73,833 420,397 333,081
Realized margin.......................... 11,921 2,790 7,564 37,147
Unrealized margin........................ (4,063) 9,469 7,237 (8,121)
-------- -------- ---------- --------
Gas trading margin..................... 7,858 12,259 14,801 29,026
Operating expenses....................... 81,008 66,914 260,640 213,150
Miscellaneous income (expense)........... 686 (182) 3,321 (893)
Interest charges......................... 16,042 13,823 47,679 44,304
Income (loss) before income taxes and
cumulative effect of accounting
change................................. (1,300) 5,173 130,200 103,760
Cumulative effect of accounting change,
net of income tax benefit.............. -- -- (7,773) --
Net income (loss)........................ $ (201) $ 3,254 $ 74,124 $ 65,265
Sales Volumes -- MMcf.................... 25,904 22,354 161,654 126,764
Transportation volumes -- MMcf........... 13,902 14,309 50,159 49,560
-------- -------- ---------- --------
Total throughput -- MMcf................. 39,806 36,663 211,813 176,324
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THREE MONTHS ENDED JUNE 30, 2003, COMPARED WITH THREE MONTHS ENDED JUNE 30, 2002
Gross profit -- Gross profit primarily consists of gas service margins generated by our six utility operating divisions from the sale of natural gas to approximately 1.7 million residential, commercial, industrial, agricultural and other customers in the twelve states that comprise our utility service areas.
Gross profit increased to $87.2 million for the three months ended June 30, 2003 from $73.8 million for the three months ended June 30, 2002. Total throughput for our utility business was 39.8 billion cubic feet (Bcf) during the current quarter compared to 36.7 Bcf during the same quarter last year. The increase in gross profit and total throughput was primarily attributable to the impact of the MVG acquisition in December 2002, which increased gross profit and total throughput by $9.2 million and 5.7 Bcf. The increase in gross profit was also attributable to a $3.6 million increase in our base charges primarily in Louisiana as a result of our annual rate stabilization clause filing which became effective in November 2002. Also contributing to the increase in gross profit was a $2.1 million increase from WNA as a result of weather in our WNA service