UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended June 30, 2012
or
For the transition period from to
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
75240
(Zip code)
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer þ
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ¨ No þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of August 3, 2012.
Class
Shares Outstanding
No Par Value
GLOSSARY OF KEY TERMS
AEC
AEH
AEM
AOCI
APS
Bcf
CFTC
FASB
Fitch
GRIP
GSRS
ISRS
Mcf
MMcf
Moody’s
NYMEX
PPA
PRP
RRC
RRM
S&P
SEC
WNA
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PART I. FINANCIAL INFORMATION
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except
share data)
Property, plant and equipment
Less accumulated depreciation and amortization
Net property, plant and equipment
Current assets
Cash and cash equivalents
Accounts receivable, net
Gas stored underground
Other current assets
Total current assets
Goodwill and intangible assets
Deferred charges and other assets
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2012 — 90,172,665 shares; September 30, 2011 — 90,296,482 shares
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss
Long-term debt
Total capitalization
Current liabilities
Accounts payable and accrued liabilities
Other current liabilities
Short-term debt
Current maturities of long-term debt
Total current liabilities
Deferred income taxes
Regulatory cost of removal obligation
Deferred credits and other liabilities
See accompanying notes to condensed consolidated financial statements.
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CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Operating revenues
Natural gas distribution segment
Regulated transmission and storage segment
Nonregulated segment
Intersegment eliminations
Purchased gas cost
Gross profit
Operating expenses
Operation and maintenance
Depreciation and amortization
Taxes, other than income
Asset impairments
Total operating expenses
Operating income
Miscellaneous expense
Interest charges
Income (loss) from continuing operations before income taxes
Income tax expense (benefit)
Income (loss) from continuing operations
Income from discontinued operations, net of tax ($566 and $590)
Net income (loss)
Basic earnings per share
Income (loss) per share from continuing operations
Income per share from discontinued operations
Net income (loss) per share — basic
Diluted earnings per share
Net income (loss) per share — diluted
Cash dividends per share
Weighted average shares outstanding:
Basic
Diluted
3
per share data)
Miscellaneous income (expense)
Income from continuing operations before income taxes
Income tax expense
Income from continuing operations
Income from discontinued operations, net of tax ($3,959 and $5,122)
Net income
Income per share from continuing operations
Net income per share — basic
Net income per share — diluted
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash Flows From Operating Activities
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization
Charged to other accounts
Other
Net assets / liabilities from risk management activities
Net change in operating assets and liabilities
Net cash provided by operating activities
Cash Flows From Investing Activities
Capital expenditures
Other, net
Net cash used in investing activities
Cash Flows From Financing Activities
Net decrease in short-term debt
Net proceeds from issuance of long-term debt
Settlement of Treasury lock agreements
Unwinding of Treasury lock agreements
Repayment of long-term debt
Cash dividends paid
Repurchase of common stock
Repurchase of equity awards
Issuance of common stock
Net cash used in financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
5
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2012
1. Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Our corporate headquarters and shared-services function are located in Dallas, Texas and our customer support centers are located in Amarillo and Waco, Texas.
Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which at June 30, 2012 covered service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. On August 1, 2012, we completed the divestiture of our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers. On August 8, 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, representing approximately 64,000 customers. Our regulated activities also include our regulated pipeline and storage operations, which include the transportation of natural gas to our distribution system and the management of our underground storage facilities. Our regulated businesses are subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate.
Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc., (AEH). AEH is wholly owned by the Company and headquartered in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties. AEH also seeks to maximize, through asset optimization activities, the economic value associated with storage and transportation capacity it owns or controls. Certain of these arrangements are with regulated affiliates of the Company, which have been approved by applicable state regulatory commissions.
We operate the Company through the following three segments:
the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
2. Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements
of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2012 are not indicative of our results of operations for the full 2012 fiscal year, which ends September 30, 2012.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We have evaluated subsequent events from the June 30, 2012 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). On July 27, 2012, we issued a notice of redemption of our Unsecured 5.125% Senior Notes on August 28, 2012. The redemption is discussed further in Note 6. On August 1, 2012, we completed the sale of our Missouri, Illinois and Iowa natural gas distribution assets. The sale is discussed in Note 5. On August 8, 2012 we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, which is discussed in Note 5.
Significant accounting policies
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011.
During the second quarter of fiscal 2012, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
During the nine months ended June 30, 2012, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard requires enhanced disclosure of offsetting arrangements for financial instruments and will become effective for annual periods beginning after January 1, 2013 and for interim periods within those annual periods. The second standard indefinitely defers the effective date for new presentation requirements related to reclassifications of items from accumulated other comprehensive income, which were scheduled to be effective for interim and annual periods beginning after December 15, 2011. The adoption of these standards should not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the nine months ended June 30, 2012.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require 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. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
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Significant regulatory assets and liabilities as of June 30, 2012 and September 30, 2011 included the following:
Regulatory assets:
Pension and postretirement benefit costs
Merger and integration costs, net
Deferred gas costs
Regulatory cost of removal asset
Environmental costs
Rate case costs
Deferred franchise fees
Regulatory liabilities:
The amounts above do not include regulatory assets and liabilities related to our divested Missouri, Illinois and Iowa service areas, which are classified as assets held for sale as of June 30, 2012 as discussed in Note 5.
During the prior fiscal year, the Railroad Commission of Texas’ Division of Public Safety issued a new rule requiring natural gas distribution companies to develop and implement a risk-based program for the renewal or replacement of distribution facilities, including steel service lines. The rule allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing) at which time investment and costs would be recovered through base rates. As of June 30, 2012, we had deferred $2.1 million associated with the requirements of this rule which are recorded in “Other” in the regulatory assets table above.
Effective January 1, 2012, the Texas Legislature amended its Gas Utility Regulatory Act (GURA) to permit natural gas utilities to defer into a regulatory asset or liability the difference between a gas utility’s actual pension and postretirement expense and the level of such expense recoverable in its existing rates. The deferred amount will become eligible for inclusion in the utility’s rates in its next rate proceeding. We elected to utilize this provision of GURA, effective January 1, 2012, and established a regulatory asset totaling $5.1 million, which is recorded in “Other” in the regulatory assets table above. Of this amount, $2.9 million represented a reduction to operation and maintenance expense during the second and third quarters of fiscal 2012.
Currently, our authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred
to be included in future rate filings in accordance with rulings received from various state regulatory commissions.
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Comprehensive income
The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and nine-month periods ended June 30, 2012 and 2011:
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(523) and $(56) for the three months ended June 30, 2012 and 2011 and of $1,194 and $876 for the nine months ended June 30, 2012 and 2011
Amortization, unrealized gain (loss) and unwinding of treasury lock agreements, net of tax expense (benefit) of $(18,399) and $(4,629) for the three months ended June 30, 2012 and 2011 and $(9,995) and $7,950 for the nine months ended June 30, 2012 and 2011
Net unrealized gains (losses) on cash flow hedging transactions, net of tax expense (benefit) of $11,401 and $(182) for the three months ended June 30, 2012 and 2011 and $(2,595) and $9,008 for the nine months ended June 30, 2012 and 2011
Comprehensive income (loss)
Accumulated other comprehensive income (loss), net of tax, as of June 30, 2012 and September 30, 2011 consisted of the following unrealized gains (losses):
Accumulated other comprehensive income (loss):
Unrealized holding gains on investments
Treasury lock agreements
Cash flow hedges
3. Financial Instruments
We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically utilize financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the nine months ended June 30, 2012 there were no
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changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.
Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions.
Regulated Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2011-2012 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 25 percent, or 25.7 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges.
The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.
Nonregulated Commodity Risk Management Activities
The primary business in our nonregulated operations is to aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. We utilize proprietary and customer-owned transportation and storage assets to serve these customers, and will seek to maximize the value of this storage capacity through the arbitrage of pricing differences that occur over time by selling financial instruments at advantageous prices to lock in a gross profit margin to enhance our gross profit by maximizing the economic value associated with the storage and transportation capacity we own or control.
As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange traded options and swap contracts with counterparties. Future contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.
We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 53 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.
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Also, in our nonregulated operations, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges.
Interest Rate Risk Management Activities
We periodically manage interest rate risk by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings.
As of June 30, 2012, we had three Treasury lock agreements outstanding to fix the Treasury yield component of 30-year unsecured notes, which we plan to issue in January 2013.
In prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled Treasury locks extend through fiscal 2041.
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of June 30, 2012, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of June 30, 2012, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type
HedgeDesignation
Commodity contracts
Fair Value
Cash Flow
Not designated
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Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of June 30, 2012 and September 30, 2011. As required by authoritative accounting literature, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $5.7 million and $28.8 million of cash held on deposit in margin accounts as of June 30, 2012 and September 30, 2011 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.
Balance Sheet Location
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts
Noncurrent commodity contracts
Liability Financial Instruments
Total
Not Designated As Hedges:
Total Financial Instruments
Other current liabilities not designated as hedges in our natural gas distribution segment include $0.7 million related to risk management liabilities that were classified as assets held for sale at June 30, 2012.
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September 30, 2011
Other current liabilities not designated as hedges in our natural gas distribution segment include $1.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2011.
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended June 30, 2012 and 2011 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $19.0 million and $5.8 million. For the nine months ended June 30, 2012 and 2011 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $21.2 million and $23.3 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
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Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and nine months ended June 30, 2012 and 2011 is presented below.
Fair value adjustment for natural gas inventory designated as the hedged item
Total impact on revenue
The impact on revenue is comprised of the following:
Basis ineffectiveness
Timing ineffectiveness
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on revenue.
To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. During the nine months ended June 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market. We did not record a writedown for nonqualifying natural gas inventory for the nine months ended June 30, 2011.
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Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
Loss reclassified from AOCI for effective portion of commodity contracts
Loss arising from ineffective portion of commodity contracts
Total impact on gross profit
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
Total Impact from Cash Flow Hedges
15
Gain on unwinding of Treasury lock reclassified from AOCI into miscellaneous income
16
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2012 and 2011. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.
Increase (decrease) in fair value:
Forward commodity contracts
Recognition of (gains) losses in earnings due to settlements:
Total other comprehensive income (loss) from hedging, net of tax(1)
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with our treasury lock agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 2012. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock agreements as these instruments have not yet settled.
Next twelve months
Thereafter
Total(1)
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2012 and 2011 was an increase (decrease) in gross profit of $11.2 million and $(4.3) million. For the nine months ended June 30, 2012 and 2011 gross profit increased (decreased) $(3.8) million and $3.9 million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
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As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
4. Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three and nine months ended June 30, 2012, there were no changes in these methods.
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 9 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2011.
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Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and September 30, 2011. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
Assets:
Financial instruments
Nonregulated segment(1)
Total financial instruments
Hedged portion of gas stored underground
Available-for-sale securities
Money market funds
Registered investment companies
Bonds
Total available-for-sale securities
Total assets
Liabilities:
Total liabilities
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Certain of the nonregulated segment’s financial instruments were reclassified from Level 1 to Level 2 upon further evaluation.
Our Level 2 measurements consist of over-the-counter options and swaps which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of June 30, 2012, we had $5.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $1.8 million was used to offset current risk management liabilities under master netting arrangements and the remaining $3.9 million is classified as current risk management assets.
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2011 we had $28.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.4 million is classified as current risk management assets.
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Available-for-sale securities are comprised of the following:
As of June 30, 2012:
Domestic equity mutual funds
Foreign equity mutual funds
As of September 30, 2011:
At June 30, 2012 and September 30, 2011, our available-for-sale securities included $39.5 million and $38.3 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2012 we maintained investments in bonds that have contractual maturity dates ranging from July 2012 through July 2016.
These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.
We maintained an investment in one foreign equity mutual fund with a fair value of $2.7 million in an unrealized loss position of less than $0.1 million as of June 30, 2012. This fund has been in an unrealized loss position for less than twelve months. Because this fund is only used to fund the supplemental plans, we evaluate investment performance over a long-term horizon. Based upon our intent and ability to hold this investment, our ability to direct the source of the payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that this fund continues to receive good ratings from mutual fund rating companies, we do not consider this impairment to be other-than-temporary as of June 30, 2012.
We also maintained several bonds with a cumulative fair value of $3.8 million in an unrealized loss position of less than $0.1 million as of June 30, 2012. These bonds have been in an unrealized loss position for less than twelve months. Based upon our intent and ability to hold these investments, our ability to direct the source of payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that these bonds are investment grade, we do not consider this impairment to be other than temporary as of June 30, 2012.
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Other Fair Value Measures
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of June 30, 2012:
Carrying Amount
5. Discontinued Operations
On August 1, 2012, we completed the sale of substantially all of our natural gas distribution assets located in Missouri, Illinois and Iowa to Liberty Energy (Midstates) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $129 million. The sale was previously announced on May 12, 2011. In connection with the sale, we expect to recognize a net of tax gain of approximately $6 million, subject to post-closing adjustments.
As required under generally accepted accounting principles, the operating results of our Missouri, Illinois and Iowa operations have been aggregated and reported on the condensed consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.
The tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations. Additionally, assets and liabilities related to our Missouri, Illinois and Iowa operations are classified as “held for sale” in other current assets and liabilities in our condensed consolidated balance sheets at June 30, 2012 and September 30, 2011.
The following table presents statement of income data related to discontinued operations.
Other nonoperating expense
Income from discontinued operations before income taxes
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The following table presents balance sheet data related to assets held for sale.
Net plant, property & equipment
Assets held for sale
Regulatory cost of removal
Liabilities held for sale
On August 8, 2012, we entered into a definitive agreement to sell all of our natural gas distribution assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $141 million. The agreement contains terms and conditions customary for transactions of this type, including typical adjustments to the purchase price at closing, if applicable. The closing of the transaction is subject to the satisfaction of customary conditions including the receipt of applicable regulatory approvals, which we currently anticipate will occur in fiscal 2013.
The following table presents the assets and liabilities associated with our Georgia operations as of June 30, 2012. As required under generally accepted accounting principles, the operating results and the assets and liabilities of our Georgia operations are classified as continuing operations at June 30, 2012.
6. Debt
The nature and terms of our debt instruments are described in detail in Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes in the terms of our debt instruments during the nine months ended June 30, 2012.
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Long-term debt at June 30, 2012 and September 30, 2011 consisted of the following:
Unsecured 10% Notes, redeemed December 2011
Unsecured 5.125% Senior Notes, due January 2013
Unsecured 4.95% Senior Notes, due 2014
Unsecured 6.35% Senior Notes, due 2017
Unsecured 8.50% Senior Notes, due 2019
Unsecured 5.95% Senior Notes, due 2034
Unsecured 5.50% Senior Notes, due 2041
Medium term notes
Series A, 1995-1, 6.67%, due 2025
Unsecured 6.75% Debentures, due 2028
Rental property term note due in installments through 2013
Total long-term debt
Less:
Original issue discount on unsecured senior notes and debentures
Current maturities
Our unsecured 10% notes were paid on their maturity date on December 31, 2011 and were not replaced. As noted above, our Unsecured 5.125% Senior Notes were scheduled to mature in January 2013. On July 27, 2012 we issued a notice of early redemption of these notes on August 28, 2012. We intend to initially fund the redemption through the issuance of commercial paper. Shortly thereafter, we intend to enter into a short-term financing facility to repay the commercial paper borrowings utilized to redeem the notes. The short-term facility is expected to be repaid with the proceeds received from the issuance of new unsecured notes anticipated to occur in January 2013. In connection with the redemption, we will pay a make-whole premium in accordance with the terms of the indenture and the Senior Notes and accrued interest at the time of redemption. In accordance with regulatory requirements, the premium will be deferred and will be recognized over the life of the new unsecured notes expected to be issued in January 2013.
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a combination of a $750 million commercial paper program collateralized by our $750 million unsecured credit facility and four committed revolving credit facilities with third-party lenders. As a result, we have approximately $985 million of working capital funding. Additionally, our $750 million unsecured credit facility has an accordion feature which, if utilized, would increase borrowing capacity to $1.0 billion. At June 30, 2012 and September 30, 2011, there was $213.5 million and $206.4 million outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.
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Regulated Operations
We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $785 million of working capital funding, including a five-year $750 million unsecured facility, a $25 million unsecured facility and a $10 million revolving credit facility, which is used primarily to issue letters of credit. On July 25, 2012, we increased the borrowing capacity of our $10 million revolving credit facility to $14 million. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $2.5 million at June 30, 2012. Our $25 million unsecured facility was renewed effective April 1, 2012. This facility bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin.
In addition to these third-party facilities, our regulated operations had a $350 million intercompany revolving credit facility with AEH. This facility was replaced on January 1, 2012 with a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2012.
Nonregulated Operations
Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, has a three-year $200 million committed revolving credit facility, expiring in December 2013, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility is primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH. Due to outstanding letters of credit and various covenants, including covenants based on working capital, the amount available to AEM under this credit facility was $94.6 million at June 30, 2012.
To supplement borrowings under this facility, AEH had a $350 million intercompany demand credit facility with AEC. This facility was replaced on January 1, 2012 with a $500 million intercompany facility with AEC, which bears interest at a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2012.
Shelf Registration
We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. At June 30, 2012, $900 million remains available for issuance. With the closing of the sale of our Missouri, Illinois and Iowa operations on August 1, 2012, there are no longer any restrictions on our ability to issue either debt or equity under the shelf until it expires in March 2013.
Debt Covenants
The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2012, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 53 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
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AEM is required by the financial covenants in its facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At June 30, 2012, AEM’s ratio of total liabilities to tangible net worth, as defined, was 0.77 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at June 30, 2012, AEM’s net working capital was $122.0 million and its tangible net worth was $152.3 million.
In addition to these financial covenants, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.
Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.
Further, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate.
Finally, AEM’s credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2. We have no other triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.
We were in compliance with all of our debt covenants as of June 30, 2012. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
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7. Earnings Per Share
Since we have non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents (referred to as participating securities), we are required to use the two-class method of computing earnings per share. The Company’s restricted stock units, for which vesting is predicated solely on the passage of time granted under our 1998 Long-Term Incentive Plan, are considered to be participating securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three and nine months ended June 30, 2012 and 2011 are calculated as follows:
Basic Earnings Per Share from continuing operations
Less: Income (loss) from continuing operations allocated to participating securities
Income (loss) from continuing operations available to common shareholders
Basic weighted average shares outstanding
Income (loss) from continuing operations per share — Basic
Basic Earnings Per Share from discontinued operations
Income from discontinued operations
Less: Income from discontinued operations allocated to participating securities
Income from discontinued operations available to common shareholders
Income from discontinued operations per share — Basic
Net income (loss) per share — Basic
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Diluted Earnings Per Share from continuing operations
Effect of dilutive stock options and other shares
Additional dilutive stock options and other shares
Diluted weighted average shares outstanding
Income (loss) from continuing operations per share — Diluted
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations per share — Diluted
Net income (loss) per share — Diluted
There were approximately 288,000 stock options and other shares excluded from the computation of diluted earnings per share for the three months ended June 30, 2011 as their inclusion in the computation would be anti-dilutive.
There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2012 and 2011 as their exercise price was less than the average market price of the common stock during those periods.
Share Repurchase Program
On September 28, 2011, the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. However, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the Company deems appropriate. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. As of June 30, 2012, a total of 387,991 shares had been repurchased for an aggregate value of $12.5 million.
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8. Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended June 30, 2012 and 2011 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
Components of net periodic pension cost:
Service cost
Interest cost
Expected return on assets
Amortization of transition asset
Amortization of prior service cost
Amortization of actuarial loss
Net periodic pension cost
Curtailment gain
The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2012 and 2011 are as follows:
Discount rate
Rate of compensation increase
Expected return on plan assets
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the
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Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2012. Based upon this valuation, we contributed $23.0 million to our defined benefit pension plans during the second fiscal quarter to achieve a desirable PPA funding threshold. The need for this funding reflects the increased pension benefit obligation due to a decrease in the discount rate compared to the prior year as well as a decline in the fair value of plan assets. During the first nine months of fiscal 2012, we contributed $40.3 million to our defined benefit plans and we anticipate contributing approximately $6 million during the remainder of the fiscal year.
We contributed $15.4 million to our other post-retirement benefit plans during the nine months ended June 30, 2012. We expect to contribute a total of approximately $5 million to $10 million to these plans during the remainder of the fiscal year.
9. Commitments and Contingencies
Litigation and Environmental Matters
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2012.
Since April 2009, Atmos Energy and two subsidiaries of AEH, AEM and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky, Billy Joe Honeycutt et al. vs. Atmos Energy Corporation, et al., which is related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.
Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was
filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.
During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.
A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals, appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments are scheduled in the case in late August 2012.
In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate
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process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss.
We have accrued what we believe is an adequate amount for the anticipated resolution of this matter; however, the amount accrued is less than the amount of the verdict. The Company does not have insurance coverage that could mitigate any losses that may arise from the resolution of this matter. However, we continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
We are a party to other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2012, AEH was committed to purchase 79.2 Bcf within one year, 17.7 Bcf within one to three years and 0.1 Bcf after three years under indexed contracts. AEH is committed to purchase 2.7 Bcf within one year and 0.4 Bcf within one to three years under fixed price contracts with prices ranging from $2.50 to $6.36 per Mcf. Purchases under these contracts totaled $176.6 million and $356.8 million for the three months ended June 30, 2012 and 2011 and $753.0 million and $1,130.0 million for the nine months ended June 30, 2012 and 2011.
Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of June 30, 2012 are as follows (in thousands):
2012
2013
2014
2015
2016
Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2012.
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Regulatory Matters
As previously described in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, in December 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines.
The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission’s findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company paid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company’s financial position, results of operations or cash flows and none of the payments were charged to any of the Company’s customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.
As discussed in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, in 2010, our Mid-Tex Division agreed to install 100,000 steel service line replacements by September 30, 2012. As of June 30, 2012, we had replaced 88,312 lines and are on schedule
for completion in September 2012. Under the terms of the agreement, special rate recovery of the associated return, depreciation and taxes is approved for lines replaced between October 1, 2010 and September 30, 2012. Since October 1, 2010, we have spent $100.5 million on steel service line replacements.
In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodity Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the SEC and CFTC have issued a number of rules and regulations, we expect additional rules and regulations to be issued, which should provide additional clarity regarding the extent of the impact of this legislation on the Company. The costs of participating in financial markets for hedging certain risks inherent in our business may be increased as a result of the new legislation and related rules and regulations. Additional reporting and disclosure obligations have been imposed upon the Company, the full extent of which will not be known until the SEC and the CFTC have completed their ongoing rulemaking process.
As of June 30, 2012, rate cases were in progress in our Mid-Tex, West Texas, Kansas and Tennessee service areas, an annual rate filing mechanism was in progress in our Louisiana service area and one infrastructure program filing was in progress in our Georgia service area. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
10. Concentration of Credit Risk
Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the nine months ended June 30, 2012, there were no material changes in our concentration of credit risk.
11. Segment Information
As discussed in Note 1 above, we operate the Company through the following three segments:
The natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
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The regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. We evaluate performance based on net income or loss of the respective operating units.
Income statements for the three and nine month periods ended June 30, 2012 and 2011 by segment are presented in the following tables:
Operating revenues from external parties
Intersegment revenues
Income from discontinued operations, net of tax
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Operating income (loss)
34
35
Miscellaneous income
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Balance sheet information at June 30, 2012 and September 30, 2011 by segment is presented to reflect our business structure as of June 30, 2012 in the following tables.
ASSETS
Property, plant and equipment, net
Investment in subsidiaries
Assets from risk management activities
Intercompany receivables
Intangible assets
Goodwill
Noncurrent assets from risk management activities
CAPITALIZATION AND LIABILITIES
Liabilities from risk management activities
Intercompany payables
Noncurrent liabilities from risk management activities
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of June 30, 2012, the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2012 and 2011, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2012 and 2011. These financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2011, 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 22, 2011, 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, 2011, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ ERNST & YOUNG LLP
Dallas, Texas
August 9, 2012
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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, 2011.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events, and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which at June 30, 2012 covered service areas located in 12 states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. On August 1, 2012, we completed the divestiture of our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers. On August 8, 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, representing approximately 64,000 customers.
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions
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and to third parties. Through our asset optimization activities, we also seek to maximize the economic value associated with the storage and transportation capacity we own or control.
As discussed in Note 11, we operate the Company through the following three segments:
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011 and include the following:
Regulation
Revenue Recognition
Allowance for Doubtful Accounts
Financial Instruments and Hedging Activities
Impairment Assessments
Pension and Other Postretirement Plans
Fair Value Measurements
Our critical accounting policies are reviewed periodically by the Audit Committee. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2012.
RESULTS OF OPERATIONS
Atmos Energy Corporation is involved in the distribution, marketing and transportation of natural gas. Accordingly, our results of operations are impacted by the demand for natural gas, particularly during the winter heating season, and the volatility of the natural gas markets. This generally results in higher operating revenues
and net income during the period from October through March of each fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal year. Additionally, the seasonality of our business impacts our working capital differently at various times during the year. Typically, our accounts receivable, accounts payable and short-term debt balances peak by the end of January and then start to decline, as customers begin to pay their winter heating bills. Gas stored underground, particularly in our natural gas distribution segment, normally peaks in November and declines as we utilize storage gas to serve our customers.
The seasonality of our business usually results in a loss in our fiscal third quarter. However, we reported net income of $31.1 million, or $0.34 per diluted share for the three months ended June 30, 2012, compared with a
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net loss of $0.6 million or $0.01 per diluted share in the prior year. Excluding the impact of unrealized margins and one-time items that occurred in the prior-year quarter, diluted earnings per share increased $0.27 compared to the prior-year quarter. The quarter-over-quarter improvement reflects higher gross profit in our regulated transmission and storage segment due to increases approved under the Gas Reliability Infrastructure Program and in our nonregulated segment due to increased asset optimization, combined with lower consolidated operation and maintenance expense, which more than offset lower natural gas distribution margins. We reported net income from discontinued operations associated with the sale of our Missouri, Illinois and Iowa service areas of $1.0 million and $0.9 million, or $0.01 per diluted share, for the three months ended June 30, 2012 and 2011.
During the nine months ended June 30, 2012, we earned $208.8 million or $2.28 per diluted share. Results for the prior-year period were influenced by the net positive impact of several one-time items totaling $6.5 million, or $0.07 per diluted share. Excluding the impact of these one-time items and unrealized margins in our nonregulated operations, we earned $201.7 million, or $2.20 per diluted share for the nine months ended June 30, 2012, compared to $200.6 million, or $2.20 in the prior-year period. Included in the current period amount is net income from discontinued operations of $6.9 million, or $0.07 per diluted share associated with the sale of our Missouri, Illinois and Iowa service areas, a decrease of $0.9 million or $0.02 per diluted share compared with the prior-year period.
Our year-to-date results were unfavorably impacted by substantially warmer winter weather and an abundance of natural gas supply. The impact of these conditions was most significantly realized in our nonregulated operations, which experienced a $12.4 million nine-month period-over-period decrease in net income, excluding the impact of one-time items and unrealized margins. However, increased earnings in our regulated transmission and storage segment, primarily as a result of an improved rate design implemented in the third quarter of the prior fiscal year, more than offset the decline experienced in our nonregulated segment. Results in our natural gas distribution segment, excluding the impact of one-time items were flat compared to the prior year, despite a nine percent decrease in throughput largely attributable to warmer than normal weather.
During the current fiscal year, we have taken several steps to increase earnings in our regulated operations. In our natural gas distribution segment, we have six rate proceedings in progress requesting a total of $75.6 million in additional annual operating income and, in April 2012, we completed an annual rate filing for Atmos Pipeline-Texas (APT) that should increase annual operating income by $14.7 million. Further, we announced two significant pipeline expansion projects whereby APT will spend approximately $160 million over the next two fiscal years to increase its ability to secure new long-term gas supply on a firm and reliable basis and to enhance the reliability of APT’s service to our Mid-Tex Division in certain critical locations.
During the second fiscal quarter, we completed the annual evaluation of the funded status of our qualified defined benefit plans as of January 1, 2012 as required by the Pension Protection Act of 2006 (PPA). As a result of lower asset returns and a year-over-year 92 basis point decline in the discount rate used to value our pension liabilities, we were required to contribute $23.0 million into the plans. For the nine months ended June 30, 2012, we contributed $40.3 million into these plans and expect to contribute approximately $6 million for the remainder of the fiscal year. Additionally, we contributed $15.4 million into our postretirement medical plans during the nine months ended June 30, 2012 and expect to contribute between $5 million and $10 million for the remainder of the fiscal year. We believe our cash flows from operations are sufficient to fund these contributions.
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Consolidated Results
The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2012 and 2011:
Diluted net income (loss) per share from continuing operations
Diluted net income per share from discontinued operations
Diluted net income (loss) per share
Our consolidated net income (loss) during the three and nine month periods ended June 30, 2012 and 2011 was earned in each of our business segments as follows:
Natural gas distribution segment from continuing operations
Net income (loss) from continuing operations
Net income from discontinued operations
Net income from continuing operations
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Regulated operations contributed 59 percent and 95 percent to our consolidated net income for the three and nine month periods ended June 30, 2012. The following tables segregate our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:
Regulated operations
Nonregulated operations
Diluted EPS from continuing regulated operations
Diluted EPS from nonregulated operations
Diluted EPS from continuing operations
Diluted EPS from discontinued operations
Consolidated diluted EPS
Natural Gas Distribution Segment
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
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Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for over 90 percent of our residential and commercial meters in the following states for the following time periods:
Georgia, Kansas, West Texas
Kentucky, Mississippi, Tennessee, Mid-Tex
Louisiana
Virginia
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas includes franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources. Conversely, lower gas costs reduce our collection risk and reduce the need to utilize short-term borrowings to fund our working capital needs.
As discussed above, on August 1, 2012, we completed the sale of substantially all of our natural gas distribution operations in Missouri, Illinois and Iowa. The results of these operations have been separately reported in the following tables as discontinued operations and exclude general corporate overhead and interest expense that would normally be allocated to these operations.
On August 8, 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia. The results of these operations are classified as continuing operations at June 30, 2012.
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Three Months Ended June 30, 2012 compared with Three Months Ended June 30, 2011
Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2012 and 2011 are presented below.
Loss from continuing operations before income taxes
Income tax benefit
Loss from continuing operations
Net loss
Consolidated natural gas distribution sales volumes from continuing operations — MMcf
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
Consolidated natural gas distribution throughput from continuing operations — MMcf
Consolidated natural gas distribution throughput from discontinued operations — MMcf
Total consolidated natural gas distribution throughput — MMcf
Consolidated natural gas distribution average transportation revenue per Mcf
Consolidated natural gas distribution average cost of gas per Mcf sold
The $0.5 million increase in natural gas distribution gross profit was primarily due to a $4.5 million net increase in rate adjustments, primarily in our Mid-Tex, Kentucky, Louisiana and Mississippi service areas.
These increases were partially offset by a $3.3 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.
Results for the third fiscal quarter were also unfavorably impacted by a five percent decrease in total consolidated throughput compared to the prior year. However, the impact to gross profit was mitigated by favorable rate designs that substantially lessened the impact of warm weather in most of our natural gas distribution service areas.
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income decreased $6.7 million primarily due to the following:
$5.3 million decrease in taxes, other than income.
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$1.4 million decrease in legal costs.
$1.4 million decrease due to the establishment of regulatory assets for pension and postretirement costs.
These decreases were partially offset by a $1.9 million increase in depreciation and amortization associated with an increase in our net plant as a result of our capital investments in the prior year.
The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended June 30, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
Mid-Tex
Kentucky/Mid-States
West Texas
Mississippi
Colorado-Kansas
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Nine Months Ended June 30, 2012 compared with Nine Months Ended June 30, 2011
Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2012 and 2011 are presented below.
Total consolidated natural gas distributionthroughput — MMcf
Consolidated natural gas distribution average cost of gasper Mcf sold
The $2.4 million increase in natural gas distribution gross profit was primarily due to a $15.5 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Mississippi, Kentucky and West Texas service areas.
These increases were partially offset by the following:
$8.9 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.
$3.1 million decrease due to a nine percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather in the current period compared to the same period last year in most of our service areas.
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $5.1 million primarily due to the following:
$8.1 million increase in depreciation and amortization associated with an increase in our net plant as a result of our capital investments in the prior year.
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$5.9 million net increase in legal and other administrative costs.
$1.7 million increase in software maintenance costs.
$5.5 million decrease in operating expenses due to increased capital spending and warmer weather allowing us time to complete more capital work than in the prior year.
$2.9 million decrease associated with the aforementioned regulatory asset.
Net income for this segment for the prior-year period was favorably impacted by a $21.8 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks ($13.3 million, net of tax) and a $5.0 million income tax benefit related to the administrative settlement of various income tax positions.
The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the nine months ended June 30, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
Recent Ratemaking Developments
Significant ratemaking developments that occurred during the nine months ended June 30, 2012 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling.
Annual net operating income increases totaling $9.9 million resulting from ratemaking activity became effective in the nine months ended June 30, 2012 as summarized below:
Rate Action
Rate case filings
Infrastructure programs
Annual rate filing mechanisms
Other rate activity
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Additionally, the following ratemaking efforts were in progress during the third quarter of fiscal 2012 but had not been completed as of June 30, 2012.
Division
Atmos Energy and Commission Staff reached a settlement for an increase in operating income of $3.8 million. A hearing on the settlement was conducted on July 18, 2012 and a final order is due before the end of the fiscal year.
The Louisiana Commission Staff recommended an operating income increase of $2.3 million effective July 1, 2012, which the Commission accepted.
The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.
Rate Case Filings
A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes the rate case that was completed during the nine months ended June 30, 2012.
2012 Rate Case Filings:
West Texas — Environs
Total 2012 Rate Case Filings
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Infrastructure Programs
Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow natural gas distribution companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. As of June 30, 2012, we had infrastructure programs in Texas, Georgia, Missouri and Kentucky. The following table summarizes our infrastructure program filings with effective dates occurring during the nine months ended June 30, 2012.
2012 Infrastructure Programs:
Mid-Tex Unincorporated (Environs)(1)
Kentucky/Mid-States — Georgia
Kentucky/Mid-States — Kentucky
Total 2012 Infrastructure Programs
Incremental net utility plant investment represents the system-wide incremental investment for the Mid-Tex Division. The increase in annual operating income is for the unincorporated areas of the Mid-Tex Division only.
Annual Rate Filing Mechanisms
As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and the Georgia service area in our Kentucky/Mid-States Division. The Company is requesting new annual rate filing mechanisms as part of our ongoing rate cases in our Mid-Tex and West Texas divisions to replace the annual mechanisms that expired for significant portions of these service areas in 2011. These mechanisms are referred to as rate review mechanisms in our Mid-Tex and West Texas divisions, stable rate filings in the Mississippi Division and a rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms for the nine months ended June 30, 2012.
2012 Filings:
Total 2012 Filings
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Other Ratemaking Activity
The following table summarizes other ratemaking activity during the nine months ended June 30, 2012:
2012 Other Rate Activity:
Total 2012 Other Rate Activity
The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas area’s base rates.
Regulated Transmission and Storage Segment
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline–Texas Division. The Atmos Pipeline–Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking and lending arrangements and sales of inventory on hand.
Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline–Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline–Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2012 and 2011 are presented below.
Mid-Tex transportation
Third-party transportation
Storage and park and lend services
Income before income taxes
Gross pipeline transportation volumes — MMcf
Consolidated pipeline transportation volumes — MMcf
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The $13.5 million increase in regulated transmission and storage gross profit compared to the prior-year quarter was primarily a result of the GRIP filings approved by the RRC during fiscal 2011 and 2012. During fiscal 2011, the Commission approved the Atmos Pipeline — Texas GRIP filing with an annual operating income increase of $12.6 million that went into effect in the fiscal fourth quarter. On April 10, 2012, the RRC approved the Atmos Pipeline — Texas GRIP filing with an annual operating income increase of $14.7 million that went into effect with bills rendered on and after April 10, 2012.
The GRIP filings approved in fiscal 2011 and 2012 increased quarter-over-quarter gross profit by $9.1 million. In addition, excess retention gas sales increased gross profit by $1.6 million.
Operating expenses decreased $1.2 million primarily due to a $2.6 million decrease in outside services and materials and supplies as a result of increased capital spending in the current-year quarter, partially offset by a $1.0 million increase in depreciation expense, resulting from the rate case and a higher investment in plant.
Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2012 and 2011 are presented below.
The $24.3 million increase in regulated transmission and storage gross profit compared to the prior-year period was primarily a result of the previously discussed rate design changes approved in the rate case in the prior year. Therefore, despite an eight percent decrease in throughput to our Mid-Tex Division, we experienced a 30 percent increase in gross profit from Mid-Tex transportation.
For the year-to-date period, the enhanced rate design resulted in a $32.4 million increase in gross profit compared to the prior-year period. This increase was partially offset by the following:
$4.4 million decrease in third-party transportation fees. Throughput associated with third-party transportation increased nine percent due to the execution of new delivery contracts with local producers in the Barnett Shale region. However, these increases were more than offset by lower transportation rates.
$2.5 million decrease associated with lower throughput to our Mid-Tex Division.
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Operating expenses increased $4.6 million primarily due to a $4.9 million increase in depreciation expense, resulting from the rate case and a higher investment in net plant.
Net income for this segment for the prior-year period was favorably impacted by a $6.0 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks ($3.9 million, net of tax).
Nonregulated Segment
Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.
AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. This business is significantly influenced by competitive factors in the industry, general economic conditions and other factors that could affect the demand for natural gas. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of gas used to serve those customers. Further, delivered gas margins can be affected by the price of natural gas in the different locations where we buy and sell gas.
AEH also earns storage and transportation margins from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods. The majority of these margins are generated through demand fees established under contracts with certain of our natural gas distribution divisions that are renewed periodically and subject to regulatory oversight.
AEH utilizes customer-owned or contracted storage capacity to serve its customers. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments in an effort to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Margins earned from these activities and the related storage demand fees are reported as asset optimization margins. Certain of these arrangements are with regulated affiliates, which have been approved by applicable state regulatory commissions. These margins are influenced by natural gas market conditions including, but not limited to, the price of natural gas, demand for natural gas, the level of domestic natural gas inventory levels and the level of volatility between current (spot) and future natural gas prices. These margins are also impacted by our ability to minimize the demand fees paid to contract for storage capacity.
Higher natural gas prices may adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Higher gas prices may also cause customers to conserve or use alternative energy sources. Lower natural gas prices generally reduce these risks.
The level of volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility influences the spreads between the current (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads and basis differentials from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Conversely, a lack of price volatility reduces opportunities to create value from arbitrage spreads and basis differentials.
Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment will include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will generally record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.
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Financial and operational highlights for our nonregulated segment for the three months ended June 30, 2012 and 2011 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers, margins earned from storage and transportation services and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.
Realized margins
Gas delivery and related services
Storage and transportation services
Asset optimization(1)
Total realized margins
Unrealized margins
Operating expenses, excluding asset impairments
Income (loss) before income taxes
Gross nonregulated delivered gas sales volumes — MMcf
Consolidated nonregulated delivered gas sales volumes — MMcf
Net physical position (Bcf)
Net of storage fees of $4.2 million and $3.8 million.
Results for our nonregulated operations during the third fiscal quarter continue to be adversely influenced by unfavorable natural gas market conditions. Historically high natural gas storage levels caused by strong domestic natural gas production caused natural gas prices to remain relatively low during our fiscal third quarter. Additionally, we continue to experience compressed spot to forward spread values and basis differentials.
We anticipate these natural gas market conditions will continue for the foreseeable future. As a result, we anticipate that basis differentials will remain compressed and spot-to-forward price volatility will remain relatively low. Accordingly, although we anticipate continuing to profit on a fiscal-year basis from our nonregulated activities, we anticipate per-unit margins from our delivered gas activities and margins earned from our asset optimization activities will be lower than in previous years for the foreseeable future.
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Realized margins for gas delivery, storage and transportation services and other services were $13.7 million during the three months ended June 30, 2012 compared with $16.9 million for the prior-year quarter. The decrease primarily reflects a 10 percent decrease in consolidated sales volumes due to lower demand from industrial customers and lower deliveries to power generation customers due to milder weather compared to the prior-year quarter.
Asset optimization margins increased $18.2 million from the prior-year quarter primarily due to realized gains earned from AEM’s trading strategy executed earlier in the fiscal year. During the first six months of fiscal 2012, AEM took advantage of falling natural gas prices by injecting gas into storage and rolling financial positions scheduled to settle during the third and fourth fiscal quarters of fiscal 2012. These gains were partially offset by increased storage fees associated with increased park and loan activity.
The $2.9 million increase in unrealized margins primarily reflects the impact of falling prices on our physical inventory as this hedged inventory is marked to market.
In the prior-year quarter we recorded an $11.0 million asset impairment charge related to our investment in certain natural gas gathering assets.
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Financial and operational highlights for our nonregulated segment for the nine months ended June 30, 2012 and 2011 are presented below.
Consolidated nonregulated delivered gas salesvolumes — MMcf
Net of storage fees of $13.7 million and $10.7 million.
Realized margins for gas delivery, storage and transportation services and other services were $47.8 million during the nine months ended June 30, 2012 compared with $61.7 million for the prior-year period. The decrease reflects the following:
A seven percent decrease in consolidated sales volumes. The decrease was largely attributable to warmer weather, which reduced sales to utility, municipal and other weather-sensitive customers.
A decrease in gas delivery per-unit margins from $0.14/Mcf in the prior-year period to $0.11/Mcf in the current-year period primarily due to lower basis differentials resulting from increased natural gas supply and increased transportation costs. The decrease in basis differentials was partially offset by increased fees earned from certain transportation arrangements and the receipt of a one-time refund of transportation demand fees from one of our transporters.
Asset optimization margins decreased $16.7 million from the prior-year period. The period-over-period decrease primarily reflects AEH’s decision during the first six months of fiscal 2012 to take advantage of falling
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natural gas prices by purchasing and injecting gas into storage and rolling financial positions scheduled to settle during the third and fourth quarter of fiscal 2012. As a result of this decision and falling prices, we realized significantly higher losses on the settlement of financial instruments used to hedge our natural gas purchases during the first two quarters of fiscal 2012.
Additionally, AEH experienced increased storage fees associated with increased park and loan activity. Finally, AEH incurred a $1.7 million charge in the first fiscal quarter to write down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.
Unrealized margins increased $14.6 million in the current period compared to the prior-year period primarily due to the timing of year-over-year realized margins.
Operating expenses, excluding asset impairments decreased $5.7 million primarily due to lower employee-related expenses. Asset impairments include the aforementioned pre-tax impairment charge recorded in the prior-year period related to the write-off of certain natural gas gathering assets as well as an asset impairment charge of $19.3 million recorded in March 2011 related to our investment in our Fort Necessity storage project.
Liquidity and Capital Resources
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require.
As discussed in Note 6, our Unsecured 5.125% Senior Notes were scheduled to mature in January 2013. On July 27, 2012 we issued a notice of early redemption of these notes on August 28, 2012. We intend to initially fund the redemption through the issuance of commercial paper. Shortly thereafter, we intend to enter into a short-term financing facility to repay the commercial paper borrowings utilized to redeem the notes. The short-term facility is expected to be repaid with the proceeds received from the issuance of new unsecured notes anticipated to occur in January 2013. In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuances of these senior notes. We designated all of these Treasury locks as cash flow hedges.
We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2012.
Cash Flows
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
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Cash flows from operating, investing and financing activities for the nine months ended June 30, 2012 and 2011 are presented below.
Total cash provided by (used in)
Operating activities
Investing activities
Financing activities
Change in cash and cash equivalents
Cash flows from operating activities
Period-over-period changes in our operating cash flows are primarily attributable to changes in net income and working capital changes, particularly within our natural gas distribution segment resulting from the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
For the nine months ended June 30, 2012, we generated operating cash flow of $518.8 million from operating activities compared with $519.6 million for the nine months ended June 30, 2011. The $0.8 million decrease in operating cash flows primarily reflects the $46.6 million increase in contributions made to our pension and postretirement plans during the first nine months of fiscal 2012, offset by changes in working capital.
Cash flows from investing activities
In recent years, a substantial portion of our cash resources has been used to fund growth projects, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, rate designs in our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline–Texas Division provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
Capital expenditures for fiscal 2012 are currently expected to range from $690 million to $710 million. For the nine months ended June 30, 2012, capital expenditures were $497.4 million compared with $390.3 million for the nine months ended June 30, 2011. The $107.1 million increase in capital expenditures primarily reflects spending for the steel service line replacement program in the Mid-Tex Division and other infrastructure replacement projects in our Mid-Tex, West Texas and Kentucky service areas, the development of new customer billing and information systems for our natural gas distribution segment and increased capital spending to increase the capacity on our Atmos Pipeline – Texas system.
Cash flows from financing activities
For the nine months ended June 30, 2012, our financing activities used $120.9 million of cash compared with $140.4 million of cash used in the prior-year period, primarily due to lower cash outflows associated with our short-term and long-term debt instruments, as follows:
$125.4 million for short-term debt repayments. In the current-year period, $6.7 million of short-term debt was repaid, compared with $132.1 million in the prior-year period.
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$357.7 million for scheduled long-term debt repayments. In the current-year period, $2.4 million of long-term debt was repaid, compared with $360.1 million in the prior-year period.
The lower repayment activity was partially offset by:
$394.6 million and $20.1 million less cash received related to the issuance of long-term debt and the related settlement of Treasury locks in the prior year.
$27.8 million less cash received related to the unwinding of two Treasury locks in the prior year.
$12.5 million additional cash used to repurchase common stock as part of our share buyback program.
$7.3 million less cash received from proceeds related to the issuance of common stock.
The following table summarizes our share issuances for the nine months ended June 30, 2012 and 2011.
Shares issued:
1998 Long-Term Incentive Plan
Outside Directors Stock-for-Fee Plan
Total shares issued
The year-over-year decrease in the number of shares issued primarily reflects the significant number of stock options exercised in the prior year. During the current-year period, we cancelled and retired 152,427 shares attributable to federal withholdings on equity awards and repurchased and retired 387,991 shares through our 2011 share repurchase program described in Note 7.
As of September 30, 2011, we were authorized to grant awards for up to a maximum of 6.5 million shares of common stock under our 1998 Long-Term Incentive Plan (LTIP). In February 2011, shareholders voted to increase the number of authorized LTIP shares by 2.2 million shares. On October 19, 2011, we received all required state regulatory approvals to increase the maximum number of authorized LTIP shares to 8.7 million shares, subject to certain adjustment provisions. On October 28, 2011, we filed with the SEC a registration statement on Form S-8 to register an additional 2.2 million shares; we also listed such shares with the New York Stock Exchange.
Credit Facilities
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements. However, our short-term borrowings typically reach their highest levels in the winter months.
We finance our short-term borrowing requirements through a combination of a $750.0 million commercial paper program under our $750 million unsecured five-year credit facility and four committed revolving credit facilities with third-party lenders that provided approximately $1.0 billion of working capital funding. As of June 30, 2012, the amount available to us under our credit facilities, net of outstanding letters of credit, was $658.6 million.
We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we were able to
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issue a total of $950 million in debt securities and $350 million in equity securities. At June 30, 2012, $900 million was available for issuance. With the closing of the sale of our Missouri, Illinois and Iowa operations on August 1, 2012, there are no longer any restrictions on our ability to issue either debt or equity under the shelf until it expires in March 2013.
Credit Ratings
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). As of June 30, 2012, all three ratings agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:
Unsecured senior long-term debt
Commercial paper
A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB- for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
We were in compliance with all of our debt covenants as of June 30, 2012. Our debt covenants are described in greater detail in Note 6 to the unaudited condensed consolidated financial statements.
Capitalization
The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2012, September 30, 2011 and June 30, 2011:
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Total debt as a percentage of total capitalization, including short-term debt, was 50.7 percent at June 30, 2012, 51.7 percent at September 30, 2011 and 48.6 percent at June 30, 2011. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.
Contractual Obligations and Commercial Commitments
Significant commercial commitments are described in Note 9 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2012.
Risk Management Activities
We conduct risk management activities through our natural gas distribution and nonregulated segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.
In our nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.
The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and nine months ended June 30, 2012 and 2011:
Fair value of contracts at beginning of period
Contracts realized/settled
Fair value of new contracts
Other changes in value
Fair value of contracts at end of period
The fair value of our natural gas distribution segment’s financial instruments at June 30, 2012 is presented below by time period and fair value source:
Source of Fair Value
Prices actively quoted
Prices based on models and other valuation methods
Total Fair Value
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The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and nine months ended June 30, 2012 and 2011:
Netting of cash collateral
Cash collateral and fair value of contracts at period end
The fair value of our nonregulated segment’s financial instruments at June 30, 2012 is presented below by time period and fair value source:
Pension and Postretirement Benefits Obligations
For the nine months ended June 30, 2012 and 2011, our total net periodic pension and other benefits costs were $51.9 million and $42.7 million. A substantial portion of those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
Our fiscal 2012 costs were determined using a September 30, 2011 measurement date. As of September 30, 2011, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2010, the measurement date for our fiscal 2011 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2012 pension and benefit costs to 5.05 percent. We reduced the expected return on our pension plan assets to 7.75 percent, based on historical experience and the current market projection of the target asset allocation. Accordingly, our fiscal 2012 pension and postretirement medical costs for the nine months ended June 30, 2012 were higher than the prior-year period.
The amounts we fund our defined benefit plans with are determined in accordance with the PPA and are influenced by the discount rate and funded position of the plans when the funding requirements are determined on January 1 of each year. We completed our valuation for fiscal 2012 during the second fiscal quarter and as a result of lower asset returns and a year-over-year 92 basis point decline in the discount rate used to value our qualified pension liabilities, we were required to contribute $23.0 million to the plans. During the nine months ended June 30, 2012, we contributed $40.3 million to our defined benefit plans and we anticipate contributing approximately $6 million during the remainder of the fiscal year. Additionally, we contributed $15.4 million to our postretirement medical plans during the nine months ended June 30, 2012 and anticipate contributing between $5 million and $10 million to these plans during the remainder of the fiscal year. We believe our cash flows from operations are sufficient to fund these contributions.
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The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plan are subject to change, depending upon the actuarial value of plan assets and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts will be determined by actual investment returns, changes in interest rates, values of assets in the plan and changes in the demographic composition of the participants in the plan.
OPERATING STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage and nonregulated segments for the three and nine month periods ended June 30, 2012 and 2011.
Natural Gas Distribution Sales and Statistical Data — Continuing Operations
METERS IN SERVICE, end of period
Residential
Commercial
Industrial
Public authority and other
Total meters
INVENTORY STORAGE BALANCE — Bcf
SALES VOLUMES — MMcf (2)
Gas sales volumes
Total gas sales volumes
Transportation volumes
Total throughput
OPERATING REVENUES (000’s)(2)
Gas sales revenues
Total gas sales revenues
Transportation revenues
Other gas revenues
Total operating revenues
Average transportation revenue per Mcf(1)
Average cost of gas per Mcf sold(1)
See footnote following these tables.
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Natural Gas Distribution Sales and Statistical Data — Discontinued Operations
Meters in service, end of period
Inventory storage balance — Bcf
Sales volumes — MMcf
Operating revenues (000’s)
Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data
CUSTOMERS, end of period
Municipal
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf
REGULATED TRANSMISSION AND
STORAGE VOLUMES — MMcf (2)
NONREGULATED DELIVERED GAS SALES
VOLUMES —MMcf(2)
OPERATING REVENUES (000’s) (2)
Regulated transmission and storage
Nonregulated
Notes to preceding tables:
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.
Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the nine months ended June 30, 2012, there were no material changes in our quantitative and qualitative disclosures about market risk.
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Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2012 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of the fiscal year ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
During the nine months ended June 30, 2012, except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 13 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
On September 28, 2011, the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. Although the program is authorized for a five-year period, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the Company deems appropriate. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. We did not repurchase any shares during the third quarter of fiscal 2012. At June 30, 2012, there were 4,612,009 shares of repurchase authority remaining under the program.
A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
(Registrant)
By:
/s/ FRED E. MEISENHEIMER
Fred E. Meisenheimer
Senior Vice President and Chief
Financial Officer
(Duly authorized signatory)
Date: August 9, 2012
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EXHIBITS INDEX
Item 6
ExhibitNumber
Description
Page Number orIncorporation byReference to
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