FORM 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

  þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

or

 

  ¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission File Number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)

 

Texas and Virginia   75-1743247
(State or other jurisdiction of
incorporation or organization)
  (IRS employer
identification no.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 

75240

(Zip code)

(Address of principal executive offices)  

(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

   Accelerated Filer  ¨    Non-Accelerated Filer  ¨    Smaller Reporting Company  ¨

(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 April 26, 2013.

 

Class

  

Shares Outstanding

No Par Value

   90,549,038


GLOSSARY OF KEY TERMS

 

AEC

   Atmos Energy Corporation

AEH

   Atmos Energy Holdings, Inc.

AEM

   Atmos Energy Marketing, LLC

AOCI

   Accumulated other comprehensive income

APS

   Atmos Pipeline and Storage, LLC

Bcf

   Billion cubic feet

CFTC

   Commodity Futures Trading Commission

FASB

   Financial Accounting Standards Board

Fitch

   Fitch Ratings, Ltd.

GAAP

   Generally Accepted Accounting Principles

GRIP

   Gas Reliability Infrastructure Program

GSRS

   Gas System Reliability Surcharge

ISRS

   Infrastructure System Replacement Surcharge

Mcf

   Thousand cubic feet

MMcf

   Million cubic feet

Moody’s

   Moody’s Investors Services, Inc.

NYMEX

   New York Mercantile Exchange, Inc.

PPA

   Pension Protection Act of 2006

PRP

   Pipeline Replacement Program

RRC

   Railroad Commission of Texas

RRM

   Rate Review Mechanism

S&P

   Standard & Poor’s Corporation

SEC

   United States Securities and Exchange Commission

WNA

   Weather Normalization Adjustment

 

1


PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     March 31,
2013
    September 30,
2012
 
     (Unaudited)        
     (In thousands, except
share data)
 
ASSETS     

Property, plant and equipment

   $ 7,435,103     $ 7,134,470  

Less accumulated depreciation and amortization

     1,724,830       1,658,866  
  

 

 

   

 

 

 

Net property, plant and equipment

     5,710,273       5,475,604  

Current assets

    

Cash and cash equivalents

     65,547       64,239  

Accounts receivable, net

     485,601       234,526  

Gas stored underground

     197,356       256,415  

Other current assets

     253,916       272,782  
  

 

 

   

 

 

 

Total current assets

     1,002,420       827,962  

Goodwill and intangible assets

     740,825       740,847  

Deferred charges and other assets

     500,212       451,262  
  

 

 

   

 

 

 
   $ 7,953,730     $ 7,495,675  
  

 

 

   

 

 

 
CAPITALIZATION AND LIABILITIES     

Shareholders’ equity

    

Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2013 — 90,538,114 shares; September 30, 2012 — 90,239,900 shares

   $ 453     $ 451  

Additional paid-in capital

     1,753,024       1,745,467  

Retained earnings

     793,927       660,932  

Accumulated other comprehensive loss

     (3,934     (47,607
  

 

 

   

 

 

 

Shareholders’ equity

     2,543,470       2,359,243  

Long-term debt

     2,455,514       1,956,305  
  

 

 

   

 

 

 

Total capitalization

     4,998,984       4,315,548  

Current liabilities

    

Accounts payable and accrued liabilities

     316,411       215,229  

Other current liabilities

     377,357       489,665  

Short-term debt

     232,998       570,929  

Current maturities of long-term debt

           131  
  

 

 

   

 

 

 

Total current liabilities

     926,766       1,275,954  

Deferred income taxes

     1,168,140       1,015,083  

Regulatory cost of removal obligation

     366,854       381,164  

Pension and postretirement liabilities

     453,548       457,196  

Deferred credits and other liabilities

     39,438       50,730  
  

 

 

   

 

 

 
   $ 7,953,730     $ 7,495,675  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

2


ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     Three Months Ended
March 31
 
     2013     2012  
     (Unaudited)  
     (In thousands, except per
share data)
 

Operating revenues

    

Natural gas distribution segment

   $ 905,176     $ 871,067  

Regulated transmission and storage segment

     61,848       58,037  

Nonregulated segment

     428,948       370,763  

Intersegment eliminations

     (86,976     (74,358
  

 

 

   

 

 

 
     1,308,996       1,225,509  

Purchased gas cost

    

Natural gas distribution segment

     558,170       498,739  

Regulated transmission and storage segment

            

Nonregulated segment

     404,641       374,992  

Intersegment eliminations

     (86,566     (74,009
  

 

 

   

 

 

 
     876,245       799,722  
  

 

 

   

 

 

 

Gross profit

     432,751       425,787  

Operating expenses

    

Operation and maintenance

     111,086       109,300  

Depreciation and amortization

     57,180       59,420  

Taxes, other than income

     54,307       54,635  
  

 

 

   

 

 

 

Total operating expenses

     222,573       223,355  
  

 

 

   

 

 

 

Operating income

     210,178       202,432  

Miscellaneous income

     1,712       506  

Interest charges

     33,331       36,643  
  

 

 

   

 

 

 

Income from continuing operations before income taxes

     178,559       166,295  

Income tax expense

     66,219       64,211  
  

 

 

   

 

 

 

Income from continuing operations

     112,340       102,084  

Income from discontinued operations, net of tax ($2,258 and $4,031)

     4,085       7,027  
  

 

 

   

 

 

 

Net income

   $ 116,425     $ 109,111  
  

 

 

   

 

 

 

Basic earnings per share

    

Income per share from continuing operations

   $ 1.24     $ 1.12  

Income per share from discontinued operations

     0.04       0.08  
  

 

 

   

 

 

 

Net income per share — basic

   $ 1.28     $ 1.20  
  

 

 

   

 

 

 

Diluted earnings per share

    

Income per share from continuing operations

   $ 1.23     $ 1.12  

Income per share from discontinued operations

     0.04       0.08  
  

 

 

   

 

 

 

Net income per share — diluted

   $ 1.27     $ 1.20  
  

 

 

   

 

 

 

Cash dividends per share

   $ 0.350     $ 0.345  
  

 

 

   

 

 

 

Weighted average shares outstanding:

    

Basic

     90,530       90,020  
  

 

 

   

 

 

 

Diluted

     91,492       90,322  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

3


ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     Six Months Ended
March 31
 
     2013     2012  
     (Unaudited)  
     (In thousands, except per
share data)
 

Operating revenues

    

Natural gas distribution segment

   $ 1,571,963     $ 1,547,180  

Regulated transmission and storage segment

     122,529       114,796  

Nonregulated segment

     828,842       814,939  

Intersegment eliminations

     (180,183     (167,412
  

 

 

   

 

 

 
     2,343,151       2,309,503  

Purchased gas cost

    

Natural gas distribution segment

     945,326       891,257  

Regulated transmission and storage segment

            

Nonregulated segment

     782,076       803,763  

Intersegment eliminations

     (179,364     (166,696
  

 

 

   

 

 

 
     1,548,038       1,528,324  
  

 

 

   

 

 

 

Gross profit

     795,113       781,179  

Operating expenses

    

Operation and maintenance

     217,613       223,944  

Depreciation and amortization

     116,759       117,786  

Taxes, other than income

     95,641       97,546  
  

 

 

   

 

 

 

Total operating expenses

     430,013       439,276  
  

 

 

   

 

 

 

Operating income

     365,100       341,903  

Miscellaneous income (expense)

     2,410       (1,510

Interest charges

     63,853       72,369  
  

 

 

   

 

 

 

Income from continuing operations before income taxes

     303,657       268,024  

Income tax expense

     113,969       103,556  
  

 

 

   

 

 

 

Income from continuing operations

     189,688       164,468  

Income from discontinued operations, net of tax ($3,986 and $7,547)

     7,202       13,150  
  

 

 

   

 

 

 

Net income

   $ 196,890     $ 177,618  
  

 

 

   

 

 

 

Basic earnings per share

    

Income per share from continuing operations

   $ 2.09     $ 1.81  

Income per share from discontinued operations

     0.08       0.14  
  

 

 

   

 

 

 

Net income per share — basic

   $ 2.17     $ 1.95  
  

 

 

   

 

 

 

Diluted earnings per share

    

Income per share from continuing operations

   $ 2.07     $ 1.80  

Income per share from discontinued operations

     0.08       0.14  
  

 

 

   

 

 

 

Net income per share — diluted

   $ 2.15     $ 1.94  
  

 

 

   

 

 

 

Cash dividends per share

   $ 0.700     $ 0.690  
  

 

 

   

 

 

 

Weighted average shares outstanding:

    

Basic

     90,445       90,137  
  

 

 

   

 

 

 

Diluted

     91,406       90,440  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

4


ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     Three Months Ended
March 31
    Six Months Ended
March 31
 
     2013     2012     2013     2012  
    

(Unaudited)

(In thousands)

 

Net income

   $ 116,425     $ 109,111     $ 196,890     $ 177,618  

Other comprehensive income (loss), net of tax

        

Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(110), $1,203, $(330) and $1,717

     (200     2,046       (573     2,947  

Cash flow hedges:

        

Amortization and unrealized gain on interest rate agreements, net of tax of $13,513, $9,042, $20,562 and $8,404

     23,509       15,396       35,773       14,309  

Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $5,650, $(3,399), $5,417 and $(13,996)

     8,838       (5,315     8,473       (21,890
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss)

     32,147       12,127       43,673       (4,634
  

 

 

   

 

 

   

 

 

   

 

 

 

Total comprehensive income

   $ 148,572     $ 121,238     $ 240,563     $ 172,984  
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

5


ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Six Months Ended
March 31
 
     2013     2012  
     (Unaudited)  
     (In thousands)  

Cash Flows From Operating Activities

    

Net income

   $ 196,890     $ 177,618  

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization:

    

Charged to depreciation and amortization

     118,608       122,532  

Charged to other accounts

     265       203  

Deferred income taxes

     106,891       102,052  

Other

     5,519       9,874  

Net assets / liabilities from risk management activities

     (14,709     15,690  

Net change in operating assets and liabilities

     (37,123     (67,246
  

 

 

   

 

 

 

Net cash provided by operating activities

     376,341       360,723  

Cash Flows From Investing Activities

    

Capital expenditures

     (389,117     (311,123

Other, net

     (3,700     (3,878
  

 

 

   

 

 

 

Net cash used in investing activities

     (392,817     (315,001

Cash Flows From Financing Activities

    

Net decrease in short-term debt

     (342,141     (48,945

Net proceeds from issuance of long-term debt

     493,793        

Settlement of Treasury lock agreements

     (66,626      

Repayment of long-term debt

     (131     (2,369

Cash dividends paid

     (64,008     (62,907

Repurchase of common stock

           (12,535

Repurchase of equity awards

     (3,124     (3,509

Issuance of common stock

     21       164  
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     17,784       (130,101
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     1,308       (84,379

Cash and cash equivalents at beginning of period

     64,239       131,419  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 65,547     $ 47,040  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

6


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2013

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. For the fiscal year ended September 30, 2012, our regulated businesses comprised over 95 percent of our consolidated net income.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which at March 31, 2013, covered service areas located in nine states. In addition, we transport natural gas for others through our distribution system. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers. Our regulated businesses 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 based 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.

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, 2012. 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, 2012. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, 2013 are not indicative of our results of operations for the full 2013 fiscal year, which ends September 30, 2013.

We have evaluated subsequent events from the March 31, 2013 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). On April 1, 2013, we completed the sale of our Georgia natural gas distribution assets. Except as discussed in Note 6, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

 

7


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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, 2012.

During the second quarter of fiscal 2013, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

Due to the April 1, 2013 sale of our Georgia distribution operations, at March 31, 2013, the financial results for this service area are shown in discontinued operations. Accordingly, certain prior-year amounts have been reclassified to conform with the current-year presentation.

During the six months ended March 31, 2013, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard clarifies the enhanced disclosure of offsetting arrangements for financial instruments that will become effective for us for annual and interim periods beginning on October 1, 2013. The second standard, which became effective during our second fiscal quarter, requires the presentation of amounts reclassified out of accumulated other comprehensive income by component as well as significant amounts reclassified out of accumulated other comprehensive income by the respective line item in the statement of net income. We have presented the disclosures relating to reclassifications out of accumulated other comprehensive income in Note 4. 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 six months ended March 31, 2013.

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.

 

8


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Significant regulatory assets and liabilities as of March 31, 2013 and September 30, 2012 included the following:

 

     March 31,
2013
     September 30,
2012
 
     (In thousands)  

Regulatory assets:

     

Pension and postretirement benefit costs(1)

     $289,003      $ 296,160  

Merger and integration costs, net

     5,502        5,754  

Deferred gas costs

     525        31,359  

Regulatory cost of removal asset

     10,183        10,500  

Rate case costs

     6,256        4,661  

Deferred franchise fees

     265        2,714  

Texas Rule 8.209(2)

     14,912        5,370  

APT annual adjustment mechanism

     4,965        4,539  

Other

     5,716        7,262  
  

 

 

    

 

 

 
   $ 337,327      $ 368,319  
  

 

 

    

 

 

 

Regulatory liabilities:

     

Deferred gas costs

   $ 43,112      $ 23,072  

Deferred franchise fees

     2,943         

Regulatory cost of removal obligation

     433,617        459,688  

Other

     5,429        5,637  
  

 

 

    

 

 

 
   $ 485,101      $ 488,397  
  

 

 

    

 

 

 

 

  (1) 

Includes $13.5 million and $7.6 million of pension and postretirement expense deferred in our Texas service areas pursuant to the Texas Gas Utility Regulatory Act.

 

  (2) 

Texas Rule 8.209 is a Railroad Commission rule that 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.

The amounts above do not include regulatory assets and liabilities related to our Georgia operations, which are classified as assets held for sale as discussed in Note 6.

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years.

3.    Financial Instruments

We use financial instruments to mitigate commodity price risk and 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, 2012. During the six months ended March 31, 2013 there were no 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.

 

9


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 22.8 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

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

Our nonregulated operations aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. To provide these services, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request. 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 to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

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 obligation, to buy or sell the commodity at a fixed price. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.

We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our 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 57 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in asset optimization activities in our nonregulated segment.

 

10


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Our nonregulated operations also 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 for accounting purposes.

Interest Rate Risk Management Activities

We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used Treasury locks to mitigate interest rate risk; however, beginning in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.

In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million out of a total $500 million of senior notes that were issued on January 11, 2013. This offering is discussed in Note 7. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with a payment of $66.6 million to the counterparties due to a decrease in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.6 million unrealized loss was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes.

In the fourth quarter of fiscal 2012, we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility that terminated on December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps are being recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest expense.

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. As of March 31, 2013, the remaining amortization periods for the settled Treasury locks extend through fiscal 2043.

 

11


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 March 31, 2013, 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 March 31, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:

 

Contract Type

  

Hedge Designation

   Natural Gas
Distribution
     Nonregulated  
          Quantity (MMcf)  

Commodity contracts

  

Fair Value

            (22,490
  

Cash Flow

            23,768  
  

Not designated

     5,890        55,387  
     

 

 

    

 

 

 
        5,890        56,665  
     

 

 

    

 

 

 

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 March 31, 2013 and September 30, 2012. 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 $12.0 million and $23.7 million of cash held on deposit in margin accounts as of March 31, 2013 and September 30, 2012 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 5.

 

   

Balance Sheet Location

  Natural Gas
Distribution
    Nonregulated     Total  
              (In thousands)        

March 31, 2013

       

Designated As Hedges:

       

Asset Financial Instruments

       

Current commodity contracts

  Other current assets   $      $ 10,447     $ 10,447  

Noncurrent commodity contracts

  Deferred charges and other assets     36,546       777       37,323  

Liability Financial Instruments

       

Current commodity contracts

  Other current liabilities            (17,622     (17,622

Noncurrent commodity contracts

  Deferred credits and other liabilities            (2,229     (2,229
   

 

 

   

 

 

   

 

 

 

Total

      36,546       (8,627     27,919  

Not Designated As Hedges:

       

Asset Financial Instruments

       

Current commodity contracts

  Other current assets(1)     3,603       76,426       80,029  

Noncurrent commodity contracts

  Deferred charges and other assets     36       52,274       52,310  

Liability Financial Instruments

       

Current commodity contracts

  Other current liabilities     (59     (77,518     (77,577

Noncurrent commodity contracts

  Deferred credits and other liabilities            (46,574     (46,574
   

 

 

   

 

 

   

 

 

 

Total

      3,580       4,608       8,188  
   

 

 

   

 

 

   

 

 

 

Total Financial Instruments

    $ 40,126     $ (4,019   $ 36,107  
   

 

 

   

 

 

   

 

 

 

 

  (1) 

Other current assets not designated as hedges in our natural gas distribution segment include $0.2 million related to risk management assets that were classified as assets held for sale at March 31, 2013.

 

12


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

   

Balance Sheet Location

  Natural Gas
Distribution
    Nonregulated     Total  
              (In thousands)        

September 30, 2012

       

Designated As Hedges:

       

Asset Financial Instruments

       

Current commodity contracts

  Other current assets   $     $ 19,301     $ 19,301  

Noncurrent commodity contracts

  Deferred charges and other assets            1,923       1,923  

Liability Financial Instruments

       

Current commodity contracts

  Other current liabilities     (85,040     (23,787     (108,827

Noncurrent commodity contracts

  Deferred credits and other liabilities            (4,999     (4,999
   

 

 

   

 

 

   

 

 

 

Total

      (85,040     (7,562     (92,602

Not Designated As Hedges:

       

Asset Financial Instruments

       

Current commodity contracts

  Other current assets(1)     7,082       98,393       105,475  

Noncurrent commodity contracts

  Deferred charges and other assets     2,283       60,932       63,215  

Liability Financial Instruments

       

Current commodity contracts

  Other current liabilities(2)     (585     (99,824     (100,409

Noncurrent commodity contracts

  Deferred credits and other liabilities            (67,062     (67,062
   

 

 

   

 

 

   

 

 

 

Total

      8,780       (7,561     1,219  
   

 

 

   

 

 

   

 

 

 

Total Financial Instruments

    $ (76,260   $ (15,123   $ (91,383
   

 

 

   

 

 

   

 

 

 

 

  (1)

Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.

 

  (2) 

Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as liabilities held for sale at September 30, 2012.

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 March 31, 2013 and 2012 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $1.7 million and $(6.2) million. For the six months ended March 31, 2013 and 2012 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $17.8 million and $2.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

 

13


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 six months ended March 31, 2013 and 2012 is presented below.

 

     Three Months Ended
March 31
 
         2013             2012      
     (In thousands)  

Commodity contracts

   $ (17,846   $ 29,090  

Fair value adjustment for natural gas inventory designated as the hedged item

     19,586       (35,087
  

 

 

   

 

 

 

Total (increase) decrease in purchased gas cost

   $ 1,740     $ (5,997
  

 

 

   

 

 

 

The (increase) decrease in purchased gas cost is comprised of the following:

    

Basis ineffectiveness

   $ 1,458     $ (739

Timing ineffectiveness

     282       (5,258
  

 

 

   

 

 

 
   $ 1,740     $ (5,997
  

 

 

   

 

 

 

 

     Six Months Ended
March 31
 
         2013             2012      
     (In thousands)  

Commodity contracts

   $ (10,532   $ 53,153  

Fair value adjustment for natural gas inventory designated as the hedged item

     28,405       (50,335
  

 

 

   

 

 

 

Total decrease in purchased gas cost

   $ 17,873     $ 2,818  
  

 

 

   

 

 

 

The decrease in purchased gas cost is comprised of the following:

    

Basis ineffectiveness

   $ 1,218     $ 102  

Timing ineffectiveness

     16,655       2,716  
  

 

 

   

 

 

 
   $ 17,873     $ 2,818  
  

 

 

   

 

 

 

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 purchased gas cost.

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. We did not record a writedown for nonqualifying natural gas inventory for the six months ended March 31, 2013. During the six months ended March 31, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market.

 

14


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2013 and 2012 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.

 

     Three Months Ended March 31, 2013  
     Natural
Gas
Distribution
    Nonregulated     Consolidated  
     (In thousands)  

Loss reclassified from AOCI for effective portion of commodity contracts

   $     $ (5,199   $ (5,199

Loss arising from ineffective portion of commodity contracts

           (83     (83
  

 

 

   

 

 

   

 

 

 

Total impact on purchased gas costs

           (5,282     (5,282

Loss on settled interest rate agreements reclassified from AOCI into interest expense

     (873           (873
  

 

 

   

 

 

   

 

 

 

Total Impact from Cash Flow Hedges

   $ (873   $ (5,282   $ (6,155
  

 

 

   

 

 

   

 

 

 

 

     Three Months Ended March 31, 2012  
     Natural
Gas
Distribution
    Nonregulated     Consolidated  
     (In thousands)  

Loss reclassified from AOCI for effective portion of commodity contracts

   $     $ (21,181   $ (21,181

Loss arising from ineffective portion of commodity contracts

           (238     (238
  

 

 

   

 

 

   

 

 

 

Total impact on purchased gas costs

           (21,419     (21,419

Loss on settled interest rate agreements reclassified from AOCI into interest expense

     (502           (502
  

 

 

   

 

 

   

 

 

 

Total Impact from Cash Flow Hedges

   $ (502   $ (21,419   $ (21,921
  

 

 

   

 

 

   

 

 

 

 

     Six Months Ended March 31, 2013  
     Natural
Gas
Distribution
    Nonregulated     Consolidated  
     (In thousands)  

Loss reclassified from AOCI for effective portion of commodity contracts

   $     $ (10,359   $ (10,359

Loss arising from ineffective portion of commodity contracts

           (102     (102
  

 

 

   

 

 

   

 

 

 

Total impact on purchased gas costs

           (10,461     (10,461

Loss on settled interest rate agreements reclassified from AOCI into interest expense

     (1,375           (1,375
  

 

 

   

 

 

   

 

 

 

Total Impact from Cash Flow Hedges

   $ (1,375   $ (10,461   $ (11,836
  

 

 

   

 

 

   

 

 

 

 

15


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Six Months Ended March 31, 2012  
     Natural Gas
Distribution
    Nonregulated     Consolidated  
     (In thousands)  

Loss reclassified from AOCI for effective portion of commodity contracts

   $     $ (32,823   $ (32,823

Loss arising from ineffective portion of commodity contracts

           (668     (668
  

 

 

   

 

 

   

 

 

 

Total impact on purchased gas costs

           (33,491     (33,491

Loss on settled interest rate agreements reclassified from AOCI into interest expense

     (1,004           (1,004
  

 

 

   

 

 

   

 

 

 

Total Impact from Cash Flow Hedges

   $ (1,004   $ (33,491   $ (34,495
  

 

 

   

 

 

   

 

 

 

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 six months ended March 31, 2013 and 2012. 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.

 

     Three Months Ended
March 31
    Six Months Ended
March 31
 
     2013      2012     2013      2012  
     (In thousands)  

Increase (decrease) in fair value:

          

Interest rate agreements

   $ 22,955      $ 15,079     $ 34,900      $ 13,676  

Forward commodity contracts

     5,666        (18,234     2,153        (41,912

Recognition of losses in earnings due to settlements:

          

Interest rate agreements

     554        317       873        633  

Forward commodity contracts

     3,172        12,919       6,320        20,022  
  

 

 

    

 

 

   

 

 

    

 

 

 

Total other comprehensive income (loss) from hedging, net of tax(1)

   $ 32,347      $ 10,081     $ 44,246      $ (7,581
  

 

 

    

 

 

   

 

 

    

 

 

 

 

  (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 March 31, 2013. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.

 

     Interest Rate
Agreements
    Commodity
Contracts
    Total  
     (In thousands)  

Next twelve months

   $ (2,686   $ 317     $ (2,369

Thereafter

     (29,021     (839     (29,860
  

 

 

   

 

 

   

 

 

 

Total(1)

   $ (31,707   $ (522   $ (32,229
  

 

 

   

 

 

   

 

 

 

 

  (1) 

Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

 

16


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 March 31, 2013 and 2012 was an increase (decrease) in gross profit of $6.8 million and $(12.8) million. For the six months ended March 31, 2013 and 2012 gross profit increased (decreased) $6.7 million and $(15.0) 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.

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.    Accumulated Other Comprehensive Income

We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following table provides the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.

 

     Available-
for-Sale
Securities
    Interest
Rate
Agreement
Cash Flow
Hedges
    Commodity
Contracts
Cash Flow
Hedges
    Total  
     (In thousands)  

September 30, 2012

   $ 5,661     $ (44,273   $ (8,995   $ (47,607

Other comprehensive income before reclassifications

     1,135       34,900       2,153       38,188  

Amounts reclassified from accumulated other comprehensive income

     (1,708     873       6,320       5,485  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net current-period other comprehensive income

     (573     35,773       8,473       43,673  
  

 

 

   

 

 

   

 

 

   

 

 

 

March 31, 2013

   $ 5,088     $ (8,500   $ (522   $ (3,934
  

 

 

   

 

 

   

 

 

   

 

 

 

 

17


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The following tables detail reclassifications out of AOCI for the three and six months ended March 31, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.

 

     Three Months ended March 31, 2013

Accumulated Other Comprehensive
Income Components

   Amount Reclassified from
Accumulated Other
      Comprehensive Income      
    Affected Line Item in the
Statement of Income
     (In thousands)      

Available-for-sale securities

   $ 2,689     Operation and maintenance expense
  

 

 

   
     2,689     Total before tax
     (981   Tax expense
  

 

 

   
   $ 1,708     Net of tax
  

 

 

   

Cash flow hedges

    

Interest rate agreements

   $ (873   Interest charges

Commodity contracts

     (5,201   Purchased gas cost
  

 

 

   
     (6,074   Total before tax
     2,348     Tax benefit
  

 

 

   
   $ (3,726   Net of tax
  

 

 

   

Total reclassifications

   $ (2,018   Net of tax
  

 

 

   

 

     Six Months ended March 31, 2013

Accumulated Other Comprehensive
Income Components

   Amount Reclassified from
Accumulated Other
      Comprehensive Income      
    Affected Line Item in  the
Statement of Income
     (In thousands)      

Available-for-sale securities

   $ 2,689     Operation and maintenance expense
  

 

 

   
     2,689     Total before tax
     (981   Tax expense
  

 

 

   
   $ 1,708     Net of tax
  

 

 

   

Cash flow hedges

    

Interest rate agreements

   $ (1,375   Interest charges

Commodity contracts

     (10,361   Purchased gas cost
  

 

 

   
     (11,736   Total before tax
     4,543     Tax benefit
  

 

 

   
   $ (7,193   Net of tax
  

 

 

   

Total reclassifications

   $ (5,485   Net of tax
  

 

 

   

5.    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

 

18


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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, 2012. During the three and six months ended March 31, 2013, 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, 2012.

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 March 31, 2013 and September 30, 2012. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

 

     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)(1)
     Significant
Other
Unobservable
Inputs

(Level 3)
     Netting and
Cash
Collateral(2)
    March 31,
2013
 
     (In thousands)  

Assets:

             

Financial instruments

             

Natural gas distribution segment

   $      $ 40,185      $       —       $     $ 40,185  

Nonregulated segment

     489        139,435               (131,972     7,952  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total financial instruments

     489        179,620               (131,972     48,137  

Hedged portion of gas stored underground

     89,342                            89,342  

Available-for-sale securities

             

Money market funds

            11,761                     11,761  

Registered investment companies

     31,092                            31,092  

Bonds

            23,617                     23,617  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total available-for-sale securities

     31,092        35,378                     66,470  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 120,923      $ 214,998      $       $ (131,972   $ 203,949  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Liabilities:

             

Financial instruments

             

Natural gas distribution segment

   $      $ 59      $       $     $ 59  

Nonregulated segment

     969        142,974               (143,943      
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities

   $ 969      $ 143,033      $       $ (143,943   $ 59  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

19


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Quoted
Prices in
Active
Markets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)(1)
     Significant
Other
Unobservable
Inputs

(Level 3)
     Netting and
Cash
Collateral(3)
    September 30,
2012
 
     (In thousands)  

Assets:

             

Financial instruments

             

Natural gas distribution segment

   $      $ 9,365      $       —       $     $ 9,365  

Nonregulated segment

     714        179,835               (162,776     17,773  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total financial instruments

     714        189,200               (162,776     27,138  

Hedged portion of gas stored underground

     67,192                            67,192  

Available-for-sale securities

             

Money market funds

            1,634                     1,634  

Registered investment companies

     40,212                            40,212  

Bonds

            22,552                     22,552  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total available-for-sale securities

     40,212        24,186                     64,398  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 108,118      $ 213,386      $       $ (162,776   $ 158,728  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Liabilities:

             

Financial instruments

             

Natural gas distribution segment

   $      $ 85,625      $       $     $ 85,625  

Nonregulated segment

     4,563        191,109               (186,451     9,221  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities

   $ 4,563      $ 276,734      $       $ (186,451   $ 94,846  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

  (1) 

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.

 

  (2) 

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 March 31, 2013, we had $12.0 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $8.3 million was used to offset current risk management liabilities under master netting arrangements and the remaining $3.7 million is classified as current risk management assets.

 

  (3) 

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, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.

 

20


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Available-for-sale securities are comprised of the following:

 

     Amortized
Cost
     Gross
Unrealized
Gain
     Gross
Unrealized
Loss
    Fair
Value
 
     (In thousands)  

As of March 31, 2013:

          

Domestic equity mutual funds

   $ 17,998      $ 6,656      $      $ 24,654  

Foreign equity mutual funds

     5,168        1,270              6,438  

Bonds

     23,388        230        (1     23,617  

Money market funds

     11,761                     11,761  
  

 

 

    

 

 

    

 

 

   

 

 

 
   $ 58,315      $ 8,156      $ (1   $ 66,470  
  

 

 

    

 

 

    

 

 

   

 

 

 

As of September 30, 2012:

          

Domestic equity mutual funds

   $ 25,779      $ 8,183      $      $ 33,962  

Foreign equity mutual funds

     5,568        682              6,250  

Bonds

     22,358        196        (2     22,552  

Money market funds

     1,634                     1,634  
  

 

 

    

 

 

    

 

 

   

 

 

 
   $ 55,339      $ 9,061      $ (2   $ 64,398  
  

 

 

    

 

 

    

 

 

   

 

 

 

At March 31, 2013 and September 30, 2012, our available-for-sale securities included $42.9 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At March 31, 2013, we maintained investments in bonds that have contractual maturity dates ranging from May 2013 through June 2017. During the six months ended March 31, 2013, we recognized a gain of $2.7 million on the sale of certain assets in the rabbi trusts.

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.

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, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of March 31, 2013:

 

     March 31,
2013
 
     (In thousands)  

Carrying Amount

   $ 2,460,000  

Fair Value

   $ 2,876,673  

6.    Discontinued Operations

On April 1, 2013, we completed the sale of substantially all of our natural gas distribution assets and certain related nonregulated assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $155 million, subject to post-closing adjustments. The

 

21


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

sale was previously announced on August 8, 2012. 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 Georgia operations have been aggregated and reported on the condensed consolidated statements of income as income from discontinued operations, net of income tax. For the three and six months ended March 31, 2013, net income for discontinued operations includes the operating results of our Georgia operations. For the three and six months ended March 31, 2012, net income from discontinued operations includes the operating results of our Georgia operations and the operating results of our Missouri, Illinois and Iowa operations that were sold on August 1, 2012. 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 Georgia operations are classified as “held for sale” in other current assets and liabilities in our condensed consolidated balance sheets at March 31, 2013 and September 30, 2012. Prior period revenues and expenses associated with these assets have been reclassified into discontinued operations. This reclassification had no impact on previously reported net income.

The following table presents statement of income data related to discontinued operations.

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     
     2013      2012      2013      2012  
     (In thousands)  

Operating revenues

   $ 21,678      $ 44,315      $ 37,962      $ 84,945  

Purchased gas cost

     12,497        26,493        21,464        51,133  
  

 

 

    

 

 

    

 

 

    

 

 

 

Gross profit

     9,181        17,822        16,498        33,812  

Operating expenses

     3,038        6,819        5,858        13,547  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating income

     6,143        11,003        10,640        20,265  

Other nonoperating income

     200        55        548        432  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from discontinued operations before income taxes

     6,343        11,058        11,188        20,697  

Income tax expense

     2,258        4,031        3,986        7,547  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income from discontinued operations

   $ 4,085      $ 7,027      $ 7,202      $ 13,150  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

22


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The following table presents balance sheet data related to assets held for sale.

 

     March  31,
2013
     September  30,
2012
 
     
     (In thousands)  

Net plant, property & equipment

   $ 144,962      $ 142,865  

Gas stored underground

     302        4,688  

Other current assets

     9,961        6,931  

Deferred charges and other assets

     207        87  
  

 

 

    

 

 

 

Assets held for sale

   $ 155,432      $ 154,571  
  

 

 

    

 

 

 

Accounts payable and accrued liabilities

   $ 2,600      $ 2,114  

Other current liabilities

     5,307        3,776  

Regulatory cost of removal

     83        3,257  

Deferred credits and other liabilities

     216        2,426  
  

 

 

    

 

 

 

Liabilities held for sale

   $ 8,206      $ 11,573  
  

 

 

    

 

 

 

7.    Debt

The nature and terms of our debt instruments and credit facilities 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, 2012. Except as noted below, there were no material changes in the terms of our debt instruments during the six months ended March 31, 2013.

Long-term debt

Long-term debt at March 31, 2013 and September 30, 2012 consisted of the following:

 

     March 31,
2013
     September 30,
2012
 
     (In thousands)  

Unsecured 4.95% Senior Notes, due October 2014

   $ 500,000      $ 500,000  

Unsecured 6.35% Senior Notes, due 2017

     250,000        250,000  

Unsecured 8.50% Senior Notes, due 2019

     450,000        450,000  

Unsecured 5.95% Senior Notes, due 2034

     200,000        200,000  

Unsecured 5.50% Senior Notes, due 2041

     400,000        400,000  

Unsecured 4.15% Senior Notes, due 2043

     500,000         

Medium term notes

     

Series A, 1995-1, 6.67%, due 2025

     10,000        10,000  

Unsecured 6.75% Debentures, due 2028

     150,000        150,000  

Rental property term note due in installments through 2013

            131  
  

 

 

    

 

 

 

Total long-term debt

     2,460,000        1,960,131  

Less:

     

Original issue discount on unsecured senior notes and debentures

     4,486        3,695  

Current maturities

            131  
  

 

 

    

 

 

 
   $ 2,455,514      $ 1,956,305  
  

 

 

    

 

 

 

 

23


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Our $250 million Unsecured 5.125% Senior Notes were originally scheduled to mature in January 2013. On August 28, 2012 we redeemed these notes with proceeds received through the issuance of commercial paper. On September 27, 2012, we entered into a $260 million short-term financing facility that was scheduled to mature on February 1, 2013 to repay the commercial paper borrowings utilized to redeem the Unsecured 5.125% Senior Notes. The short-term facility was repaid with the proceeds received through the issuance of 30-year unsecured senior notes on January 11, 2013, as discussed below.

We issued $500 million Unsecured 4.15% Senior Notes on January 11, 2013. The effective interest rate of these notes is 4.64 percent, after giving effect to offering costs and the settlement of the associated Treasury locks discussed in Note 3. Of the net proceeds of approximately $494 million, $260 million was used to repay our short-term financing facility. The remaining $234 million of net proceeds was used to partially repay our commercial paper borrowings and for general corporate purposes.

Short-term debt

Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. 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 currently finance our short-term borrowing requirements through a combination of a $750 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. On December 7, 2012, we amended the terms of our former $750 million unsecured credit facility to increase the borrowing capacity to $950 million, with an accordion feature, which, if utilized, would increase the borrowing capacity to $1.2 billion. The amendment also permits us to obtain same-day funding on base rate loans. There were no other material changes to the credit facility. These facilities provide approximately $1.0 billion of working capital funding. At March 31, 2013 and September 30, 2012, a total of $233.0 million and $310.9 million was outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.

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 $989 million of working capital funding, including a five-year $950 million unsecured facility, a $25 million unsecured facility and a $14 million unsecured revolving credit facility, which is used primarily to issue letters of credit. The $25 million facility was renewed on April 1, 2013. Due to outstanding letters of credit, the total amount available to us under our $14 million revolving credit facility was $8.2 million at March 31, 2013.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which 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, 2013.

Nonregulated Operations

Prior to December 5, 2012, Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, had a three-year $200 million committed revolving credit facility, expiring in December 2014, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The

 

24


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

credit facility was 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 was collateralized by substantially all of the assets of AEM and was guaranteed by AEH. AEM terminated the committed revolving credit facility on December 5, 2012, primarily in order to reduce external credit expense. AEM incurred no penalties in connection with the termination. This facility was replaced with two $25 million, 364-day bilateral credit facilities, one of which is a committed facility. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $36.9 million at March 31, 2013.

AEH has a $500 million intercompany demand credit facility with AEC. This facility 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 borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013.

Shelf Registration

On March 28, 2013, we filed a registration statement with the SEC to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaces our registration statement that expired on March 31, 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 March 31, 2013, 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.

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.

We were in compliance with all of our debt covenants as of March 31, 2013. 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.

 

25


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

8.    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 non-vested 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 six months ended March 31, 2013 and 2012 are calculated as follows:

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  
     (In thousands, except per share amounts)  

Basic Earnings Per Share from continuing operations

           

Income from continuing operations

   $ 112,340      $ 102,084      $ 189,688      $ 164,468  

Less: Income from continuing operations allocated to participating securities

     304        1,069        634        1,719  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from continuing operations available to common shareholders

   $ 112,036      $ 101,015      $ 189,054      $ 162,749  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic weighted average shares outstanding

     90,530        90,020        90,445        90,137  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from continuing operations per share — Basic

   $ 1.24      $ 1.12      $ 2.09      $ 1.81  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic Earnings Per Share from discontinued operations

           

Income from discontinued operations

   $ 4,085      $ 7,027      $ 7,202      $ 13,150  

Less: Income from discontinued operations allocated to participating securities

     11        74        24        137  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from discontinued operations available to common shareholders

   $ 4,074      $ 6,953      $ 7,178      $ 13,013  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic weighted average shares outstanding

     90,530        90,020        90,445        90,137  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from discontinued operations per share — Basic

   $ 0.04      $ 0.08      $ 0.08      $ 0.14  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income per share — Basic

   $ 1.28      $ 1.20      $ 2.17      $ 1.95  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

26


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  
     (In thousands, except per share amounts)  

Diluted Earnings Per Share from continuing operations

           

Income from continuing operations available to common shareholders

   $ 112,036      $ 101,015      $ 189,054      $ 162,749  

Effect of dilutive stock options and other shares

     2        3        5        4  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from continuing operations available to common shareholders

   $ 112,038      $ 101,018      $ 189,059      $ 162,753  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic weighted average shares outstanding

     90,530        90,020        90,445        90,137  

Additional dilutive stock options and other shares

     962        302        961        303  
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted weighted average shares outstanding

     91,492        90,322        91,406        90,440  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from continuing operations per share — Diluted

   $ 1.23      $ 1.12      $ 2.07      $ 1.80  
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted Earnings Per Share from discontinued operations

           

Income from discontinued operations available to common shareholders

   $ 4,074      $ 6,953      $ 7,178      $ 13,013  

Effect of dilutive stock options and other shares

                           
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from discontinued operations available to common shareholders

   $ 4,074      $ 6,953      $ 7,178      $ 13,013  
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic weighted average shares outstanding

     90,530        90,020        90,445        90,137  

Additional dilutive stock options and other shares

     962        302        961        303  
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted weighted average shares outstanding

     91,492        90,322        91,406        90,440  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income from discontinued operations per share — Diluted

   $ 0.04      $ 0.08      $ 0.08      $ 0.14  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income per share — Diluted

   $ 1.27      $ 1.20      $ 2.15      $ 1.94  
  

 

 

    

 

 

    

 

 

    

 

 

 

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2013 and 2012 as their exercise price was less than the average market price of the common stock during those periods.

Share Repurchase Program

We did not repurchase any shares during the six months ended March 31, 2013 as part of our 2011 share repurchase program. For the six months ended March 31, 2012, we repurchased and retired 387,991 shares for an aggregate value of $12.5 million as part of the program.

 

27


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

9.     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 six months ended March 31, 2013 and 2012 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.

 

     Three Months Ended March 31  
     Pension Benefits     Other Benefits  
     2013     2012     2013     2012  
     (In thousands)  

Components of net periodic pension cost:

        

Service cost

   $ 5,203     $ 4,298     $ 4,700     $ 4,088  

Interest cost

     6,023       6,678       3,241       3,466  

Expected return on assets

     (5,738     (5,369     (997     (652

Amortization of transition asset

                 270       378  

Amortization of prior service cost

     (36     (36     (363     (363

Amortization of actuarial loss

     5,562       4,143       1,049       662  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic pension cost

   $ 11,014     $ 9,714     $ 7,900     $ 7,579  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

     Six Months Ended March 31  
     Pension Benefits     Other Benefits  
     2013     2012     2013     2012  
     (In thousands)  

Components of net periodic pension cost:

        

Service cost

   $ 10,405     $ 8,596     $ 9,400     $ 8,176  

Interest cost

     12,048       13,355       6,482       6,931  

Expected return on assets

     (11,477     (10,737     (1,994     (1,304

Amortization of transition asset

                 540       756  

Amortization of prior service cost

     (71     (71     (725     (725

Amortization of actuarial loss

     11,123       8,285       2,098       1,324  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic pension cost

   $ 22,028     $ 19,428     $ 15,801     $ 15,158  
  

 

 

   

 

 

   

 

 

   

 

 

 

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2013 and 2012 are as follows:

 

     Pension Benefits     Other Benefits  
     2013     2012     2013     2012  

Discount rate

     4.04     5.05     4.04     5.05

Rate of compensation increase

     3.50     3.50     N/A        N/A   

Expected return on plan assets

     7.75     7.75     4.70     4.70

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

 

28


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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, 2013. During the first six months of fiscal 2013, we contributed $13.4 million to our defined benefit plans and we anticipate contributing approximately $23 million during the remainder of the fiscal year.

We contributed $13.2 million to our other post-retirement benefit plans during the six months ended March 31, 2013. We expect to contribute a total of approximately $10 million to $15 million to these plans during the remainder of the fiscal year.

10.    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, 2012, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the six months ended March 31, 2013.

Since September 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (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 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 of Appeals on March 19, 2012. Oral arguments were held in the case on August 27, 2012.

In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in

 

29


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.

The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and are in the process of preparing a response to the landowners’ motion, which response was filed on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. 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.

In addition, in a related matter, 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 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. Since that time, we have continued to be engaged in discovery activities in this case.

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 March 31, 2013, AEH was committed to purchase 95.1 Bcf within one year, 37.6 Bcf within one to three years and 23.4 Bcf after three years under indexed contracts. AEH is committed to purchase 1.3 Bcf within one year and 0.5 Bcf within one to three years under fixed price contracts with prices ranging from $3.50 to $6.36 per Mcf. Purchases under these contracts totaled $327.8 million and $264.3 million for the three months ended March 31, 2013 and 2012 and $617.3 million and $576.4 million for the six months ended March 31, 2013 and 2012.

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.

 

30


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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 March 31, 2013 are as follows (in thousands):

 

2013

   $ 66,443  

2014

     78,398  

2015

      

2016

      

2017

      

Thereafter

      
  

 

 

 
   $ 144,841  
  

 

 

 

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, 2012. There were no material changes to the estimated storage and transportation fees for the six months ended March 31, 2013.

Regulatory Matters

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 Commodities Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. The costs of participating in financial markets for hedging certain risks inherent in our business have been increased as a result of the new legislation and related rules and regulations. We also are subject to additional recordkeeping and reporting obligations with regard to certain of our swap transactions. Although the CFTC and SEC have issued a number of required rules and regulations, we expect additional rules and regulations to be adopted, which should provide further clarity regarding the extent of the impact of this legislation on us.

As of March 31, 2013, annual rate filing mechanisms were in progress in Louisiana and the City of Dallas service area in our Mid-Tex Division and infrastructure program filings were in progress for Atmos Pipeline — Texas and Georgia. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

11.    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, 2012. During the six months ended March 31, 2013, there were no material changes in our concentration of credit risk.

12.    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,

 

   

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.

 

31


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our 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, 2012. We evaluate performance based on net income or loss of the respective operating units.

Income statements for the three and six month periods ended March 31, 2013 and 2012 by segment are presented in the following tables:

 

     Three Months Ended March 31, 2013  
     Natural
Gas
Distribution
     Regulated
Transmission
and Storage
    Nonregulated     Eliminations     Consolidated  
     (In thousands)  

Operating revenues from external parties

   $ 904,181      $ 19,655     $ 385,160     $     $ 1,308,996  

Intersegment revenues

     995        42,193       43,788       (86,976      
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     905,176        61,848       428,948       (86,976     1,308,996  

Purchased gas cost

     558,170              404,641       (86,566     876,245  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     347,006        61,848       24,307       (410     432,751  

Operating expenses

           

Operation and maintenance

     89,344        15,390       6,763       (411     111,086  

Depreciation and amortization

     47,631        8,690       859             57,180  

Taxes, other than income

     49,592        4,277       438             54,307  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     186,567        28,357       8,060       (411     222,573  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     160,439        33,491       16,247       1       210,178  

Miscellaneous income (expense)

     2,591        (99     (91     (689     1,712  

Interest charges

     25,664        7,857       498       (688     33,331  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations before income taxes

     137,366        25,535       15,658             178,559  

Income tax expense

     51,176        9,005       6,038             66,219  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations

     86,190        16,530       9,620             112,340  

Income from discontinued operations, net of tax

     4,085                          4,085  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 90,275      $ 16,530     $ 9,620     $     $ 116,425  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

   $ 131,465      $ 67,208     $ 417     $     $ 199,090  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

32


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Three Months Ended March 31, 2012  
     Natural
Gas
Distribution
     Regulated
Transmission
and Storage
    Nonregulated     Eliminations     Consolidated  
     (In thousands)  

Operating revenues from external parties

   $ 870,744      $ 20,430     $ 334,335     $     $ 1,225,509  

Intersegment revenues

     323        37,607       36,428       (74,358      
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     871,067        58,037       370,763       (74,358     1,225,509  

Purchased gas cost

     498,739              374,992       (74,009     799,722  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     372,328        58,037       (4,229     (349     425,787  

Operating expenses

           

Operation and maintenance

     88,035        15,847       5,769       (351     109,300  

Depreciation and amortization

     50,903        7,792       725             59,420  

Taxes, other than income

     50,029        3,915       691             54,635  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     188,967        27,554       7,185       (351     223,355  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     183,361        30,483       (11,414     2       202,432  

Miscellaneous income (expense)

     623        (56     567       (628     506  

Interest charges

     28,816        7,614       839       (626     36,643  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

     155,168        22,813       (11,686           166,295  

Income tax expense (benefit)

     60,693        8,193       (4,675           64,211  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     94,475        14,620       (7,011           102,084  

Income from discontinued operations, net of tax

     7,027                          7,027  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 101,502      $ 14,620     $ (7,011   $     $ 109,111  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

   $ 114,402      $ 38,871     $ 3,456     $     $ 156,729  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

33


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Six Months Ended March 31, 2013  
     Natural
Gas
Distribution
     Regulated
Transmission
and Storage
    Nonregulated      Eliminations     Consolidated  
     (In thousands)  

Operating revenues from external parties

   $ 1,569,730      $ 38,354     $ 735,067      $     $ 2,343,151  

Intersegment revenues

     2,233        84,175       93,775        (180,183      
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
     1,571,963        122,529       828,842        (180,183     2,343,151  

Purchased gas cost

     945,326              782,076        (179,364     1,548,038  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Gross profit

     626,637        122,529       46,766        (819     795,113  

Operating expenses

            

Operation and maintenance

     173,080        31,710       13,645        (822     217,613  

Depreciation and amortization

     97,691        17,080       1,988              116,759  

Taxes, other than income

     86,343        8,226       1,072              95,641  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total operating expenses

     357,114        57,016       16,705        (822     430,013  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     269,523        65,513       30,061        3       365,100  

Miscellaneous income (expense)

     2,460        (226     1,576        (1,400     2,410  

Interest charges

     49,227        14,728       1,295        (1,397     63,853  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Income from continuing operations before income taxes

     222,756        50,559       30,342              303,657  

Income tax expense

     83,473        17,924       12,572              113,969  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Income from continuing operations

     139,283        32,635       17,770              189,688  

Income from discontinued operations, net of tax

     7,202                           7,202  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 146,485      $ 32,635     $ 17,770      $     $ 196,890  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Capital expenditures

   $ 277,336      $ 111,039     $ 742      $     $ 389,117  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

 

34


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     Six Months Ended March 31, 2012  
     Natural
Gas
Distribution
    Regulated
Transmission
and Storage
    Nonregulated     Eliminations     Consolidated  
     (In thousands)  

Operating revenues from external parties

   $ 1,546,633     $ 39,870     $ 723,000     $     $ 2,309,503  

Intersegment revenues

     547       74,926       91,939       (167,412      
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     1,547,180       114,796       814,939       (167,412     2,309,503  

Purchased gas cost

     891,257             803,763       (166,696     1,528,324  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     655,923       114,796       11,176       (716     781,179  

Operating expenses

          

Operation and maintenance

     180,031       32,812       11,820       (719     223,944  

Depreciation and amortization

     100,885       15,443       1,458             117,786  

Taxes, other than income

     88,221       7,699       1,626             97,546  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     369,137       55,954       14,904       (719     439,276  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     286,786       58,842       (3,728     3       341,903  

Miscellaneous income (expense)

     (1,274     (336     603       (503     (1,510

Interest charges

     56,955       14,823       1,091       (500     72,369  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

     228,557       43,683       (4,216           268,024  

Income tax expense (benefit)

     89,581       15,649       (1,674           103,556  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     138,976       28,034       (2,542           164,468  

Income from discontinued operations, net of tax

     13,150                         13,150  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 152,126     $ 28,034     $ (2,542   $     $ 177,618  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures

   $ 243,135     $ 62,991     $ 4,997     $     $ 311,123  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

35


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Balance sheet information at March 31, 2013 and September 30, 2012 by segment is presented in the following tables.

 

     March 31, 2013  
     Natural
Gas
Distribution
     Regulated
Transmission
and Storage
     Nonregulated     Eliminations     Consolidated  
     (In thousands)  

ASSETS

            

Property, plant and equipment, net

   $ 4,585,510      $ 1,064,816      $ 59,947     $     $ 5,710,273  

Investment in subsidiaries

     806,009               (2,096     (803,913      

Current assets

            

Cash and cash equivalents

     27,463               38,084             65,547  

Assets from risk management activities

     3,376               3,704             7,080  

Other current assets

     659,313        28,205        520,574       (278,299     929,793  

Intercompany receivables

     666,407                     (666,407      
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total current assets

     1,356,559        28,205        562,362       (944,706     1,002,420  

Intangible assets

                   142             142  

Goodwill

     573,550        132,422        34,711             740,683  

Noncurrent assets from risk management activities

     36,582               4,248             40,830  

Deferred charges and other assets

     432,774        17,766        8,842             459,382  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
   $ 7,790,984      $ 1,243,209      $ 668,156     $ (1,748,619   $ 7,953,730  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

CAPITALIZATION AND LIABILITIES

  

         

Shareholders’ equity

   $ 2,543,470      $ 360,796      $ 445,213     $ (806,009   $ 2,543,470  

Long-term debt

     2,455,514                           2,455,514  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total capitalization

     4,998,984        360,796        445,213       (806,009     4,998,984  

Current liabilities

            

Current maturities of long-term debt

                                

Short-term debt

     491,498                     (258,500     232,998  

Liabilities from risk management activities

     59                           59  

Other current liabilities

     546,766        7,677        156,969       (17,703     693,709  

Intercompany payables

            612,744        53,663       (666,407      
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total current liabilities

     1,038,323        620,421        210,632       (942,610     926,766  

Deferred income taxes

     896,660        260,798        10,682             1,168,140  

Noncurrent liabilities from risk management activities

                                

Regulatory cost of removal obligation

     366,854                           366,854  

Deferred credits and other liabilities

     490,163        1,194        1,629             492,986  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
   $ 7,790,984      $ 1,243,209      $ 668,156     $ (1,748,619   $ 7,953,730  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

36


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

     September 30, 2012  
     Natural
Gas
Distribution
     Regulated
Transmission
and Storage
     Nonregulated     Eliminations     Consolidated  
     (In thousands)  

ASSETS

            

Property, plant and equipment, net

   $ 4,432,017      $ 979,443      $ 64,144     $     $ 5,475,604  

Investment in subsidiaries

     747,496               (2,096     (745,400      

Current assets

            

Cash and cash equivalents

     12,787               51,452             64,239  

Assets from risk management activities

     6,934               17,773             24,707  

Other current assets

     546,187        11,788        404,097       (223,056     739,016  

Intercompany receivables

     636,557                     (636,557      
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total current assets

     1,202,465        11,788        473,322       (859,613     827,962  

Intangible assets

                   164             164  

Goodwill

     573,550        132,422        34,711             740,683  

Noncurrent assets from risk management activities

     2,283                           2,283  

Deferred charges and other assets

     417,893        24,353        6,733             448,979  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
   $ 7,375,704      $ 1,148,006      $ 576,978     $ (1,605,013   $ 7,495,675  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

CAPITALIZATION AND LIABILITIES

  

         

Shareholders’ equity

   $ 2,359,243      $ 328,161      $ 419,335     $ (747,496   $ 2,359,243  

Long-term debt

     1,956,305                           1,956,305  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total capitalization

     4,315,548        328,161        419,335       (747,496     4,315,548  

Current liabilities

            

Current maturities of long-term debt

                   131             131  

Short-term debt

     782,719                     (211,790     570,929  

Liabilities from risk management activities

     85,366               15             85,381  

Other current liabilities

     526,089        12,478        90,116       (9,170     619,513  

Intercompany payables

            584,578        51,979       (636,557      
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total current liabilities

     1,394,174        597,056        142,241       (857,517     1,275,954  

Deferred income taxes

     789,288        220,647        5,148             1,015,083  

Noncurrent liabilities from risk management activities

                   9,206             9,206  

Regulatory cost of removal obligation

     381,164                           381,164  

Deferred credits and other liabilities

     495,530        2,142        1,048             498,720  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 
   $ 7,375,704      $ 1,148,006      $ 576,978     $ (1,605,013   $ 7,495,675  
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

37


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of March 31, 2013, the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended March 31, 2013 and 2012, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2013 and 2012. 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, 2012, 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 12, 2012, 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, 2012, 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

May 2, 2013

 

38


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, 2012.

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 threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; 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 approximately three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which at March 31, 2013 covered service areas located in nine states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers.

Through our nonregulated businesses, we 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 and to third parties.

 

39


As discussed in Note 12, 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.

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, 2012 and include the following:

 

   

Regulation

 

   

Unbilled revenue

 

   

Financial instruments and hedging activities

 

   

Fair value measurements

 

   

Impairment assessments

 

   

Pension and other postretirement plans

 

   

Contingencies

Our critical accounting policies are reviewed periodically by the Audit Committee. There were no significant changes to these critical accounting policies during the six months ended March 31, 2013.

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. Historically, this generally has resulted 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. As a result of the seasonality of the natural gas industry, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 56 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years.

However, we anticipate that rate design changes, implemented upon the completion of our most recent rate cases in our Mid-Tex and West Texas Divisions during the first quarter of fiscal 2013, will change this trend. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design allows our

 

40


rates to be more closely aligned with the natural gas distribution industry standard rate design. In addition, we anticipate these divisions, which represent approximately 50 percent of the operating income for our natural gas distribution segment, will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. For fiscal 2013, as expected, we experienced a quarter-over-quarter decline in operating income when these rates were implemented. However, we expect this decline to be more than offset by higher operating income during the third and fourth fiscal quarters compared with prior-year periods.

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, typically peaks in November and declines as we utilize storage gas to serve our customers.

We reported net income of $116.4 million, or $1.27 per diluted share for the three months ended March 31, 2013 compared with net income of $109.1 million, or $1.20 per diluted share in the prior-year quarter. Excluding the impact of unrealized margins, diluted earnings per share decreased $0.03 compared with the prior-year quarter. During the six months ended March 31, 2013 we earned $196.9 million or $2.15 per diluted share, compared with $177.6 million, or $1.94 per diluted share in the prior-year period. Excluding the impact of unrealized margins, diluted earnings per share increased $0.11 compared with the prior-year period. The quarter-over-quarter decrease in net income, excluding unrealized margins, was primarily due to a decrease in natural gas distribution net income resulting primarily from the implementation of the aforementioned rate design changes in our Texas service areas, while the period-over-period increase primarily reflects recent rate increases approved in our regulated transmission and storage segment and improved asset optimization margins in our nonregulated segment, coupled with lower interest expense.

We completed the sale of our Georgia service area on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $155 million. The proposed sale was previously announced on August 8, 2012. In connection with the sale, we expect to recognize a net of tax gain of approximately $6 million, subject to post-closing adjustments. Accordingly, the results of operations for this service area are shown in discontinued operations for both periods presented. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these three service areas was completed in August 2012. During the six months ended March 31, 2013, discontinued operations generated net income of $7.2 million, or $0.08 per diluted share, compared with net income of $13.2 million, or $0.14 per diluted share in the prior-year period.

We also took several steps during the six months ended March 31, 2013 to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. We also terminated Atmos Energy Marketing’s $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.

On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.

 

41


Consolidated Results

The following table presents our consolidated financial highlights for the three and six months ended March 31, 2013 and 2012:

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  
     (In thousands, except per share data)  

Operating revenues

   $ 1,308,996      $ 1,225,509      $ 2,343,151      $ 2,309,503  

Gross profit

     432,751        425,787        795,113        781,179  

Operating expenses

     222,573        223,355        430,013        439,276  

Operating income

     210,178        202,432        365,100        341,903  

Miscellaneous income (expense)

     1,712        506        2,410        (1,510

Interest charges

     33,331        36,643        63,853        72,369  

Income from continuing operations before income taxes

     178,559        166,295        303,657        268,024  

Income tax expense

     66,219        64,211        113,969        103,556  

Income from continuing operations

     112,340        102,084        189,688        164,468  

Income from discontinued operations, net of tax

     4,085        7,027        7,202        13,150  

Net income

   $ 116,425      $ 109,111      $ 196,890      $ 177,618  

Diluted net income per share from continuing operations

   $ 1.23      $ 1.12      $ 2.07      $ 1.80  

Diluted net income per share from discontinued operations

     0.04        0.08        0.08        0.14  

Diluted net income per share

   $ 1.27      $ 1.20      $ 2.15      $ 1.94  

Our consolidated net income (loss) during the three and six month periods ended March 31, 2013 and 2012 was earned in each of our business segments as follows:

 

     Three Months Ended March 31  
     2013      2012     Change  
     (In thousands)  

Natural gas distribution segment from continuing operations

   $ 86,190      $ 94,475     $ (8,285

Regulated transmission and storage segment

     16,530        14,620       1,910  

Nonregulated segment

     9,620        (7,011     16,631  
  

 

 

    

 

 

   

 

 

 

Net income from continuing operations

     112,340        102,084       10,256  

Net income from discontinued operations

     4,085        7,027       (2,942
  

 

 

    

 

 

   

 

 

 

Net income

   $ 116,425      $ 109,111     $ 7,314  
  

 

 

    

 

 

   

 

 

 

 

     Six Months Ended March 31  
     2013      2012     Change  
     (In thousands)  

Natural gas distribution segment from continuing operations

   $ 139,283      $ 138,976     $ 307  

Regulated transmission and storage segment

     32,635        28,034       4,601  

Nonregulated segment

     17,770        (2,542     20,312  
  

 

 

    

 

 

   

 

 

 

Net income from continuing operations

     189,688        164,468       25,220  

Net income from discontinued operations

     7,202        13,150       (5,948
  

 

 

    

 

 

   

 

 

 

Net income

   $ 196,890      $ 177,618     $ 19,272  
  

 

 

    

 

 

   

 

 

 

 

42


Regulated operations contributed 91 percent to our consolidated net income from continuing operations for the three and six month periods ended March 31, 2013. The following tables reflect the segregation of our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:

 

     Three Months Ended March 31  
     2013      2012     Change  
     (In thousands, except per share data)  

Regulated operations

   $ 102,720      $ 109,095     $ (6,375

Nonregulated operations

     9,620        (7,011     16,631  
  

 

 

    

 

 

   

 

 

 

Net income from continuing operations

     112,340        102,084       10,256  

Net income from discontinued operations

     4,085        7,027       (2,942
  

 

 

    

 

 

   

 

 

 

Net income

   $ 116,425      $ 109,111     $ 7,314  
  

 

 

    

 

 

   

 

 

 

Diluted EPS from continuing regulated operations

   $ 1.12      $ 1.19     $ (0.07

Diluted EPS from nonregulated operations

     0.11        (0.07     0.18  
  

 

 

    

 

 

   

 

 

 

Diluted EPS from continuing operations

     1.23        1.12       0.11  

Diluted EPS from discontinued operations

     0.04        0.08       (0.04
  

 

 

    

 

 

   

 

 

 

Consolidated diluted EPS

   $ 1.27      $ 1.20     $ 0.07  
  

 

 

    

 

 

   

 

 

 

 

     Six Months Ended March 31  
     2013      2012     Change  
     (In thousands, except per share data)  

Regulated operations

   $ 171,918      $ 167,010     $ 4,908  

Nonregulated operations

     17,770        (2,542     20,312  
  

 

 

    

 

 

   

 

 

 

Net income from continuing operations

     189,688        164,468       25,220  

Net income from discontinued operations

     7,202        13,150       (5,948
  

 

 

    

 

 

   

 

 

 

Net income

   $ 196,890      $ 177,618     $ 19,272  
  

 

 

    

 

 

   

 

 

 

Diluted EPS from continuing regulated operations

   $ 1.87      $ 1.83     $ 0.04  

Diluted EPS from nonregulated operations

     0.20        (0.03     0.23  
  

 

 

    

 

 

   

 

 

 

Diluted EPS from continuing operations

     2.07        1.80       0.27  

Diluted EPS from discontinued operations

     0.08        0.14       (0.06
  

 

 

    

 

 

   

 

 

 

Consolidated diluted EPS

   $ 2.15      $ 1.94     $ 0.21  
  

 

 

    

 

 

   

 

 

 

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.

 

43


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 approximately 96 percent of our residential and commercial meters in the following states for the following time periods:

 

Kansas, West Texas

   October — May

Kentucky, Mississippi, Tennessee, Mid-Tex

   November — April

Louisiana

   December — March

Virginia

   January — December

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 does include 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.

As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which 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. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.

As discussed above, on April 1, 2013, we completed the sale of substantially all of our natural gas distribution operations in Georgia. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. 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.

During the first six months of fiscal 2013, we completed ten regulatory proceedings, which should result in a $66.4 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second fiscal quarters to be lower than in previous periods while operating income earned during the third and fourth fiscal quarters to be higher than in previous periods. For fiscal 2013, as expected, we experienced a quarter-over-quarter decline in operating income when these rates became effective. However, we expect this decline to be more than offset by higher operating income during the third and fourth fiscal quarters compared with the prior-year periods.

 

44


Three Months Ended March 31, 2013 compared with Three Months Ended March 31, 2012

Financial and operational highlights for our natural gas distribution segment for the three months ended March 31, 2013 and 2012 are presented below.

 

     Three Months Ended March 31  
     2013      2012      Change  
     (In thousands, unless otherwise noted)  

Gross profit

   $ 347,006      $ 372,328      $ (25,322

Operating expenses

     186,567        188,967        (2,400
  

 

 

    

 

 

    

 

 

 

Operating income

     160,439        183,361        (22,922

Miscellaneous income

     2,591        623        1,968  

Interest charges

     25,664        28,816        (3,152
  

 

 

    

 

 

    

 

 

 

Income from continuing operations before income taxes

     137,366        155,168        (17,802

Income tax expense

     51,176        60,693        (9,517
  

 

 

    

 

 

    

 

 

 

Income from continuing operations

     86,190        94,475        (8,285

Income from discontinued operations, net of tax

     4,085        7,027        (2,942
  

 

 

    

 

 

    

 

 

 

Net income

   $ 90,275      $ 101,502      $ (11,227
  

 

 

    

 

 

    

 

 

 

Consolidated natural gas distribution sales volumes from continuing operations — MMcf

     120,123        101,420        18,703  

Consolidated natural gas distribution transportation volumes from continuing operations — MMcf

     36,540        36,241        299  
  

 

 

    

 

 

    

 

 

 

Consolidated natural gas distribution throughput from continuing operations — MMcf

     156,663        137,661        19,002  

Consolidated natural gas distribution throughput from discontinued operations — MMcf

     2,674        7,233        (4,559
  

 

 

    

 

 

    

 

 

 

Total consolidated natural gas distribution throughput — MMcf

     159,337        144,894        14,443  
  

 

 

    

 

 

    

 

 

 

Consolidated natural gas distribution average transportation revenue per Mcf

   $ 0.47      $ 0.43      $ 0.04  

Consolidated natural gas distribution average cost of gas per Mcf sold

   $ 4.67      $ 4.94      $ (0.27

The $22.9 million quarter-over-quarter decrease in natural gas distribution operating income primarily reflects the impact of the rate design changes implemented in the Mid-Tex and West Texas divisions, which was the primary driver of the $25.3 million decrease in gross profit.

The decreases were partially offset by a $2.4 million decrease in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, primarily due to the following:

 

   

$3.3 million decrease in depreciation expense due to new depreciation rates approved in the most recent Mid-Tex rate case that went into effect in January 2013.

 

   

$2.4 million gain realized on the sale of certain investments.

 

   

$0.4 million decrease in taxes, other than income.

These decreases in operating expense were partially offset by a $3.6 million increase in expenses associated with line locate activities.

 

45


Miscellaneous income increased $2.0 million, primarily due to the completion of a periodic review of our performance based rate (PBR) mechanism in our Tennessee service area and the implementation of a new PBR program in our Mississippi Division.

Interest charges decreased $3.2 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas.

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 March 31, 2013 and 2012. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

 

     Three Months Ended March 31  
     2013      2012      Change  
     (In thousands)  

Mid-Tex

   $ 59,713      $ 88,301      $ (28,588

Kentucky/Mid-States

     24,497        18,725        5,772  

Louisiana

     24,004        22,470        1,534  

West Texas

     15,008        17,989        (2,981

Mississippi

     19,825        17,537        2,288  

Colorado-Kansas

     16,677        13,982        2,695  

Other

     715        4,357        (3,642
  

 

 

    

 

 

    

 

 

 

Total

   $ 160,439      $ 183,361      $ (22,922
  

 

 

    

 

 

    

 

 

 

 

46


Six Months Ended March 31, 2013 compared with Six Months Ended March 31, 2012

Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2013 and 2012 are presented below.

 

     Six Months Ended March 31  
     2013      2012     Change  
     (In thousands, unless otherwise noted)  

Gross profit

   $ 626,637      $ 655,923     $ (29,286

Operating expenses

     357,114        369,137       (12,023
  

 

 

    

 

 

   

 

 

 

Operating income

     269,523        286,786       (17,263

Miscellaneous income (expense)

     2,460        (1,274     3,734  

Interest charges

     49,227        56,955       (7,728
  

 

 

    

 

 

   

 

 

 

Income from continuing operations before income taxes

     222,756        228,557       (5,801

Income tax expense

     83,473        89,581       (6,108
  

 

 

    

 

 

   

 

 

 

Income from continuing operations

     139,283        138,976       307  

Income from discontinued operations, net of tax

     7,202        13,150       (5,948
  

 

 

    

 

 

   

 

 

 

Net income

   $ 146,485      $ 152,126     $ (5,641
  

 

 

    

 

 

   

 

 

 

Consolidated natural gas distribution sales volumes from continuing operations — MMcf

     198,876        184,787       14,089  

Consolidated natural gas distribution transportation volumes from continuing operations — MMcf

     69,429        68,518       911  
  

 

 

    

 

 

   

 

 

 

Consolidated natural gas distribution throughput from continuing operations — MMcf

     268,305        253,305       15,000  

Consolidated natural gas distribution throughput from discontinued operations — MMcf

     4,731        13,337       (8,606
  

 

 

    

 

 

   

 

 

 

Total consolidated natural gas distribution throughput — MMcf

     273,036        266,642       6,394  
  

 

 

    

 

 

   

 

 

 

Consolidated natural gas distribution average transportation revenue per Mcf

   $ 0.46      $ 0.44     $ 0.02  

Consolidated natural gas distribution average cost of gas per Mcf sold

   $ 4.77      $ 4.87     $ (0.10

The $17.3 million period-over-period decrease in natural gas distribution operating income primarily reflects the impact of the rate design changes implemented in the Mid-Tex and West Texas divisions. The impact of these rate design changes decreased gross profit by $31.1 million. Additionally, gross profit was $2.6 million lower than the prior-year period due to a decrease in revenue-related taxes in our Mid-Tex and West Texas divisions due to lower revenues on which the tax is calculated.

These decreases were partially offset by a $12.0 million decrease in operating expenses, primarily due to the following:

 

   

$5.8 million decrease in legal and other administrative costs.

 

   

$3.2 million decrease in depreciation expense due to new depreciation rates approved in the most recent Mid-Tex rate case that went into effect in January 2013.

 

   

$2.4 million gain realized on the sale of certain investments.

Miscellaneous income increased $3.7 million, primarily due to the aforementioned increases associated with our PBR programs in our Tennessee and Mississippi service areas.

 

47


Interest charges decreased $7.7 million, primarily from interest capitalized related to Rule 8.209 infrastructure spending and the early redemption of the 5.125% $250 million senior notes in August 2012.

The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the six months ended March 31, 2013 and 2012. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

 

     Six Months Ended March 31  
     2013      2012      Change  
     (In thousands)  

Mid-Tex

   $ 105,290      $ 136,750      $ (31,460

Kentucky/Mid-States

     40,202        30,107        10,095  

Louisiana

     40,889        37,671        3,218  

West Texas

     24,586        28,664        (4,078

Mississippi

     31,438        27,669        3,769  

Colorado-Kansas

     25,421        22,161        3,260  

Other

     1,697        3,764        (2,067
  

 

 

    

 

 

    

 

 

 

Total

   $ 269,523      $ 286,786      $ (17,263
  

 

 

    

 

 

    

 

 

 

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the six months ended March 31, 2013 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 $66.4 million resulting from ratemaking activity became effective in the six months ended March 31, 2013 as summarized below:

 

Rate Action

   Annual Increase  to
Operating Income
 
  
     (In thousands)  

Rate case filings

   $ 56,700  

Infrastructure programs

     4,206  

Annual rate filing mechanisms

     4,184  

Other rate activity

     1,322  
  

 

 

 
   $ 66,412  
  

 

 

 

Additionally, the following ratemaking efforts were in progress during the second quarter of fiscal 2013 but had not been completed as of March 31, 2013.

 

Division

  

Rate Action

   Jurisdiction    Operating Income
Requested
 
               (In thousands)  

Mid-Tex

   DARR    City of Dallas    $ 2,883  

Louisiana

   Rate Stabilization Clause(1)    TransLa      2,730  

Louisiana

   Rate Stabilization Clause    LGS      1,570  

Kentucky/Mid-States

   Infrastructure Replacement(2)    Georgia      1,013  
        

 

 

 
         $ 8,196  
        

 

 

 

 

48


 

  (1) 

In March 2013, the Company accepted the Staff’s recommended adjustments and implemented an increase of $2.3 million on April 1, 2013.

 

  (2) 

On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp., who assumed responsibility of the docket on April 1, 2013. Any increase in operating income awarded by the Commission will be included in Liberty Energy’s future results of operations.

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 cases that were completed during the six months ended March 31, 2013.

 

Division

   State      Increase in Annual
Operating Income
     Effective
Date
 
     (In thousands)  

2013 Rate Case Filings:

        

Mid-Tex

     Texas       $ 42,601        12/04/2012   

Kentucky/Mid-States

     Tennessee         7,530        11/08/2012   

West Texas

     Texas         6,569        10/01/2012   
     

 

 

    

Total 2013 Rate Case Filings

      $ 56,700     
     

 

 

    

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 March 31, 2013, we had infrastructure programs approved in Texas, Kansas, Colorado, Kentucky, Virginia and Georgia. The following table summarizes our infrastructure program filings with effective dates occurring during the six months ended March 31, 2013.

 

Division

   Period End      Incremental
Net Utility
Plant
Investment
     Increase in
Annual
Operating
Income
     Effective
Date
 
            (In thousands)      (In thousands)         

2013 Infrastructure Programs:

           

Colorado-Kansas — Kansas

     09/2012       $ 5,376      $ 601        01/09/2013   

Kentucky/Mid-States — Georgia

     09/2011         6,519        1,079        10/01/2012   

Kentucky/Mid-States — Kentucky

     09/2013         19,296        2,425        10/01/2012   

Kentucky/Mid-States — Virginia

     09/2013         756        101        10/01/2012   
     

 

 

    

 

 

    

Total 2013 Infrastructure Programs

      $ 31,947      $ 4,206     
     

 

 

    

 

 

    

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. As of March 31, 2013 we had annual rate filing mechanisms in our Louisiana, Georgia and Mississippi service areas and in a portion of our Mid-Tex Division. These mechanisms are referred to as the Dallas annual rate review (DARR) in our Mid-Tex

 

49


Division, stable rate filings in the Mississippi Division, Georgia rate adjustment mechanism in our Kentucky/Mid-States Division and a rate stabilization clause in the Louisiana Division. We have initiated discussions regarding a new rate review mechanism processes in our West Texas and Mid-Tex Divisions and expect to file under the new mechanism in fiscal 2013. The following annual rate filing mechanism was completed during the six months ended March 31, 2013.

 

Division

   Jurisdiction    Test Year
Ended
     Additional
Annual
Operating
Income
     Effective
Date
 
          (In thousands)  

2013 Filings:

           

Kentucky/Mid-States

   Georgia      09/30/2013       $ 743        02/01/2013   

Mississippi

   Mississippi      06/30/2012         3,441        11/01/2012   
        

 

 

    

Total 2013 Filings

         $ 4,184     
        

 

 

    

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the six months ended March 31, 2013:

 

Division

   Jurisdiction    Rate Activity   Additional
Annual
Operating
Income
     Effective
Date
 
          (In thousands)  

2013 Other Rate Activity:

          

Colorado-Kansas

   Kansas    Ad Valorem(1)   $ 1,322         02/01/2013   
       

 

 

    

Total 2013 Other Rate Activity

        $ 1,322      
       

 

 

    

 

  (1) 

The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service 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 arrangements, lending arrangements and sales of excess gas.

Our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Mid-Tex service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve could influence customers to transport gas through our pipeline to capture arbitrage gains.

The results of Atmos Pipeline — Texas Division are also significantly impacted by the natural gas requirements of the Mid-Tex Division because it is the primary supplier of natural gas for our 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.

 

50


Three Months Ended March 31, 2013 compared with Three Months Ended March 31, 2012

Financial and operational highlights for our regulated transmission and storage segment for the three months ended March 31, 2013 and 2012 are presented below.

 

     Three Months Ended March 31  
     2013     2012     Change  
     (In thousands, unless otherwise noted)  

Mid-Tex transportation

   $ 42,947     $ 39,114     $ 3,833  

Third-party transportation

     14,769       14,309       460  

Storage and park and lend services

     1,562       1,867       (305

Other

     2,570       2,747       (177
  

 

 

   

 

 

   

 

 

 

Gross profit

     61,848       58,037       3,811  

Operating expenses

     28,357       27,554       803  
  

 

 

   

 

 

   

 

 

 

Operating income

     33,491       30,483       3,008  

Miscellaneous expense

     (99     (56     (43

Interest charges

     7,857       7,614       243  
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     25,535       22,813       2,722  

Income tax expense

     9,005       8,193       812  
  

 

 

   

 

 

   

 

 

 

Net income

   $ 16,530     $ 14,620     $ 1,910  
  

 

 

   

 

 

   

 

 

 

Gross pipeline transportation volumes — MMcf

     179,021       176,361       2,660  
  

 

 

   

 

 

   

 

 

 

Consolidated pipeline transportation volumes — MMcf

     105,099       109,626       (4,527
  

 

 

   

 

 

   

 

 

 

The $3.0 million increase in regulated transmission and storage operating income compared to the prior-year quarter was primarily a result of the GRIP filing approved by the RRC during fiscal 2012, which authorized an annual operating income increase of $14.7 million effective April 2012. This increase was partially offset by a $0.8 million increase in operating expenses largely attributable to increased pipeline maintenance activities.

At March 31, 2013, a GRIP filing was in progress with the RRC in which $26.7 million of additional annual operating income was requested.

Six Months Ended March 31, 2013 compared with Six Months Ended March 31, 2012

Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2013 and 2012 are presented below.

 

     Six Months Ended March 31  
     2013     2012     Change  
     (In thousands, unless otherwise noted)  

Mid-Tex transportation

   $ 83,732     $ 76,457     $ 7,275  

Third-party transportation

     29,318       29,248       70  

Storage and park and lend services

     3,072       3,673       (601

Other

     6,407       5,418       989  
  

 

 

   

 

 

   

 

 

 

Gross profit

     122,529       114,796       7,733  

Operating expenses

     57,016       55,954       1,062  
  

 

 

   

 

 

   

 

 

 

Operating income

     65,513       58,842       6,671  

Miscellaneous expense

     (226     (336     110  

Interest charges

     14,728       14,823       (95
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     50,559       43,683       6,876  

Income tax expense

     17,924       15,649       2,275  
  

 

 

   

 

 

   

 

 

 

Net income

   $ 32,635     $ 28,034     $ 4,601  
  

 

 

   

 

 

   

 

 

 

Gross pipeline transportation volumes — MMcf

     340,505       337,190       3,315  
  

 

 

   

 

 

   

 

 

 

Consolidated pipeline transportation volumes — MMcf

     213,842       214,663       (821
  

 

 

   

 

 

   

 

 

 

 

51


The $6.7 million increase in regulated transmission and storage operating income compared to the prior-year period was primarily a result of the GRIP filing approved by the RRC during fiscal 2012, which authorized an annual operating income increase of $14.7 million effective April 2012. This increase was partially offset by a $1.1 million increase in operating expenses largely attributable to increased pipeline maintenance activities.

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. These activities are reflected as gas delivery and related services in the table below.

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. Most 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. These activities are reflected as storage and transportation services in the table below.

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.

Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of gas and demand fees paid to contract for storage capacity to offer more competitive pricing to those customers.

Further, natural gas market conditions, most notably the price of natural gas and the level of price volatility affect our nonregulated businesses. Natural gas prices and the level of volatility are influenced by a number of factors including, but not limited to, general economic conditions, the demand for natural gas in different parts of the country, the level of domestic natural gas production and the level of natural gas inventory levels.

Natural gas prices can influence:

 

   

The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources. Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy sources to natural gas.

 

   

Collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment.

 

   

The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this segment.

Natural gas price volatility can also influence our nonregulated business in the following ways:

 

   

Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access.

 

   

Price volatility also influences the spreads between the current (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads.

 

52


   

Increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.

Although natural gas prices have risen somewhat during the last 12 months, the natural gas marketing industry continues to experience compressed basis differentials and lower spot-to-forward price volatility. Accordingly, while we anticipate continuing to profit on a fiscal year basis from our nonregulated activities, we anticipate this segment will continue to represent less than ten percent of our consolidated results.

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 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.

Three Months Ended March 31, 2013 compared with Three Months Ended March 31, 2012

Financial and operating highlights for our nonregulated segment for the three months ended March 31, 2013 and 2012 are presented below.

 

     Three Months Ended March 31  
     2013     2012     Change  
     (In thousands, unless otherwise noted)  

Realized margins

      

Gas delivery and related services

   $ 15,264     $ 14,271     $ 993  

Storage and transportation services

     3,596       3,451       145  

Other

     784       996       (212
  

 

 

   

 

 

   

 

 

 
     19,644       18,718       926  

Asset optimization(1)

     2,022       (10,045     12,067  
  

 

 

   

 

 

   

 

 

 

Total realized margins

     21,666       8,673       12,993  

Unrealized margins

     2,641       (12,902     15,543  
  

 

 

   

 

 

   

 

 

 

Gross profit

     24,307       (4,229     28,536  

Operating expenses

     8,060       7,185       875  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     16,247       (11,414     27,661  

Miscellaneous income (loss)

     (91     567       (658

Interest charges

     498       839       (341
  

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     15,658       (11,686     27,344  

Income tax expense (benefit)

     6,038       (4,675     10,713  
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 9,620     $ (7,011   $ 16,631  
  

 

 

   

 

 

   

 

 

 

Gross nonregulated delivered gas sales volumes — MMcf

     109,723       111,656       (1,933
  

 

 

   

 

 

   

 

 

 

Consolidated nonregulated delivered gas sales volumes — MMcf

     97,732       99,844       (2,112
  

 

 

   

 

 

   

 

 

 

Net physical position (Bcf)

     20.8       38.0       (17.2
  

 

 

   

 

 

   

 

 

 

 

  (1) 

Net of storage fees of $3.2 million and $4.8 million.

 

53


Operating income increased $27.7 million compared to the prior-year quarter, primarily as a result of a $13.0 million increase in realized margins and a $15.5 million increase in unrealized margins. The increase in realized margins primarily reflects increased asset optimization margins due to gains realized on the settlement of financial positions during the current-year quarter. In the prior-year quarter, AEH realized losses on the settlement of financial positions as it rolled positions into the fiscal third and fourth quarters of the prior year. Additionally, AEH experienced a $1.6 million reduction in storage demand fees during the current-year quarter due to renewing storage contracts at current market rates and replacing certain nonstrategic storage capacity contracts with more favorably structured contracts such as park and loan agreements or multi-turn storage contracts.

Realized margins for gas delivery and related services increased $1.0 million primarily due to an increase in gas delivery per-unit margins from 12.8 cents per Mcf in the prior-year quarter to 13.9 cents per Mcf, partially offset by a two percent decrease in consolidated sales volumes. The increase in per-unit margins reflects enhanced trading opportunities in the cash markets during the current quarter as a result of colder weather that produced price volatility. The decrease in sales volumes is primarily attributable to a decrease in industrial sales volumes due to increased competition.

Unrealized margins increased $15.5 million, primarily due to favorable market prices in the current quarter that increased the fair value of our physical storage position.

Six Months Ended March 31, 2013 compared with Six Months Ended March 31, 2012

Financial and operational highlights for our nonregulated segment for the six months ended March 31, 2013 and 2012 are presented below.

 

     Six Months Ended March 31  
     2013     2012     Change  
     (In thousands, unless otherwise noted)  

Realized margins

      

Gas delivery and related services

   $ 25,334     $ 25,384     $ (50

Storage and transportation services

     7,117       6,640       477  

Other

     1,797       2,013       (216
  

 

 

   

 

 

   

 

 

 
     34,248       34,037       211  

Asset optimization(1)

     (13,101     (31,639     18,538  
  

 

 

   

 

 

   

 

 

 

Total realized margins

     21,147       2,398       18,749  

Unrealized margins

     25,619       8,778       16,841  
  

 

 

   

 

 

   

 

 

 

Gross profit

     46,766       11,176       35,590  

Operating expenses

     16,705       14,904       1,801  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     30,061       (3,728     33,789  

Miscellaneous income

     1,576       603       973  

Interest charges

     1,295       1,091       204  
  

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     30,342       (4,216     34,558  

Income tax expense (benefit)

     12,572       (1,674     14,246  
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 17,770     $ (2,542   $ 20,312  
  

 

 

   

 

 

   

 

 

 

Gross nonregulated delivered gas sales volumes — MMcf

     208,732       218,118       (9,386
  

 

 

   

 

 

   

 

 

 

Consolidated nonregulated delivered gas sales volumes — MMcf

     182,450       190,714       (8,264
  

 

 

   

 

 

   

 

 

 

Net physical position (Bcf)

     20.8       38.0       (17.2
  

 

 

   

 

 

   

 

 

 

 

  (1) 

Net of storage fees of $9.2 million and $9.5 million.

 

54


Operating income increased $33.8 million compared to the prior-year period primarily as a result of an $18.7 million increase in realized margins and a $16.8 million increase in unrealized margins. The increase in realized margins primarily reflects higher asset optimization margins.

In the prior-year period, AEH executed a strategy to take advantage of falling natural gas prices by injecting gas into storage to capture incremental physical to forward spread values that were subsequently realized during the fiscal third and fourth quarters of fiscal 2012. As a result, AEH realized significant losses on the settlement of financial positions in the prior-year period. Additionally, realized asset optimization margins for the prior-year period included a $1.7 million charge to write down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.

In the current-year period, AEH experienced significantly smaller realized losses from its asset optimization activities due to more favorable financial trading as market prices declined less in the current-year period against the execution strategy compared to the prior-year period.

Realized margins for gas delivery, storage and transportation services and other services were flat compared to the prior-year period. The four percent decrease in consolidated sales volumes primarily represents a decrease in industrial sales volumes due to increased competition. The impact of lower sales volumes was offset by an increase in per-unit margins from 11.6 cents per Mcf to 12.1 cents per Mcf. The increase in per-unit margins reflects enhanced trading opportunities in the cash markets as a result of colder weather in the second fiscal quarter of the current year that produced price volatility.

Operating expenses increased $1.8 million, primarily due to increased employee and contract labor costs.

Miscellaneous income increased $1.0 million primarily due to a gain realized from the sale of a peaking power facility and related assets during the fiscal first quarter.

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 below, we currently have over $1 billion of capacity from our short-term facilities.

On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which, in effect, replaced our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012, on a long-term basis. The net proceeds of approximately $494 million were used to repay $260 million outstanding under our short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes, as discussed in Note 7.

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 2013.

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.

 

55


Cash flows from operating, investing and financing activities for the six months ended March 31, 2013 and 2012 are presented below.

 

     Six Months Ended March 31  
     2013     2012     Change  
     (In thousands)  

Total cash provided by (used in)

      

Operating activities

   $ 376,341     $ 360,723     $ 15,618  

Investing activities

     (392,817     (315,001     (77,816

Financing activities

     17,784       (130,101     147,885  
  

 

 

   

 

 

   

 

 

 

Change in cash and cash equivalents

     1,308       (84,379     85,687  

Cash and cash equivalents at beginning of period

     64,239       131,419       (67,180
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 65,547     $ 47,040     $ 18,507  
  

 

 

   

 

 

   

 

 

 

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 six months ended March 31, 2013, we generated operating cash flow of $376.3 million from operating activities compared with $360.7 million for the six months ended March 31, 2012. The $15.6 million increase in operating cash flows primarily reflects a $17.5 million reduction in pension and postretirement contributions made during the current-year period combined with the timing of customer collections and vendor payments, as well as the effect of a decrease in the amount of cash used to inject gas into storage, primarily in our nonregulated segment.

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 enhance the safety and reliability of the systems used 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 regulatory strategy, we are focusing our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline–Texas Division have rate tariffs that 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 2013 are currently expected to range from $770 million to $790 million. For the six months ended March 31, 2013, capital expenditures were $389.1 million compared with $311.1 million for the six months ended March 31, 2012. The $78.0 million increase in capital expenditures primarily reflects infrastructure spending incurred in our natural gas distribution segment and for the Line W and Line WX expansion projects in our regulated transmission and storage segment.

Cash flows from financing activities

For the six months ended March 31, 2013, our financing activities generated $17.8 million of cash compared with $130.1 million of cash used in the prior-year period, primarily due to the following:

 

   

$493.8 million net cash proceeds received from the issuance of $500 million 4.15% 30-year unsecured senior notes on January 11, 2013.

 

56


   

$12.5 million increase in cash flows due to the absence this year of prior-year common stock repurchases as part of our share repurchase program.

 

   

$2.2 million increase in cash flows due to lower repayments of long-term debt. In the current year, we repaid $0.1 million of long-term debt compared to $2.3 million repaid in the prior year.

These increases were partially offset by the following:

 

   

$293.2 million increase in short-term debt repayments. In the current-year period, $342.1 million of short-term debt was repaid, compared with $48.9 million in the prior-year period, primarily due to the repayment of a $260 million short-term financing facility that was repaid with proceeds received through the issuance of 30-year unsecured senior notes on January 11, 2013.

 

   

$66.6 million payment in the current year related to the settlement of three Treasury Locks associated with the issuance of 30-year unsecured senior notes on January 11, 2013.

The following table summarizes our share issuances for the six months ended March 31, 2013 and 2012.

 

     Six Months Ended
March 31
 
     2013      2012  

Shares issued:

     

1998 Long-Term Incentive Plan

     385,020        219,712  

Outside Directors Stock-for-Fee Plan

     1,125        1,204  
  

 

 

    

 

 

 

Total shares issued

     386,145        220,916  
  

 

 

    

 

 

 

The year-over-year increase in the number of shares issued primarily reflects the type of awards that were issued from the 1998 Long-Term Incentive Plan in each period. In the current-year period, employees were issued restricted stock units, for which we issued new shares. In the prior-year period, employees were issued restricted stock awards, which were held in trust and did not require the issuance of new shares. For the six months ended March 31, 2013 and 2012, we cancelled and retired 87,931 and 99,555 shares attributable to federal withholdings on equity awards. For the six months ended March 31, 2012, we repurchased and retired 387,991 shares through our 2011 share repurchase program.

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 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, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1.0 billion of working capital funding. As of March 31, 2013, the amount available to us under our credit facilities, net of outstanding letters of credit, was $787.1 million.

Shelf Registration

On March 28, 2013, we filed a registration statement with the United States Securities and Exchange Commission to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaces our registration statement that expired on March 31, 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

 

57


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 March 31, 2013, all three ratings agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

 

     S&P      Moody’s      Fitch  

Unsecured senior long-term debt

     BBB+         Baa1         A-   

Commercial paper

     A-2         P-2         F-2   

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.

Debt Covenants

We were in compliance with all of our debt covenants as of March 31, 2013. Our debt covenants are described in greater detail in Note 7 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 March 31, 2013, September 30, 2012 and March 31, 2012:

 

     March 31, 2013     September 30, 2012     March 31, 2012  
     (In thousands, except percentages)  

Short-term debt(1)

   $ 232,998        4.5   $ 570,929        11.7   $ 173,996        3.7

Long-term debt

     2,455,514        46.9     1,956,436         40.0     2,206,344         46.5

Shareholders’ equity

     2,543,470        48.6     2,359,243         48.3     2,360,712         49.8
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 5,231,982         100.0   $ 4,886,608         100.0   $ 4,741,052         100.0
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

  (1) 

Short-term debt at September 30, 2012 included $260 million outstanding related to a short-term facility we used to redeem our $250 million 5.125% Senior notes in August 2012. The balance outstanding under this short-term facility was repaid in January 2013.

Total debt as a percentage of total capitalization, including short-term debt, was 51.4 percent at March 31, 2013, 51.7 percent at September 30, 2012 and 50.2 percent at March 31, 2012. 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 10 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the six months ended March 31, 2013.

 

58


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 six months ended March 31, 2013 and 2012:

 

     Three Months Ended
March 31
    Six Months Ended
March 31
 
     2013     2012     2013     2012  
     (In thousands)  

Fair value of contracts at beginning of period

   $ (64,197   $ (85,829   $ (76,260   $ (79,277

Contracts realized/settled

     (306     (13,807     2,529       (31,537

Fair value of new contracts

     683       176       1,013       (377

Other changes in value

     103,946       51,928       112,844       63,659  
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of contracts at end of period

   $ 40,126     $ (47,532   $ 40,126     $ (47,532
  

 

 

   

 

 

   

 

 

   

 

 

 

The fair value of our natural gas distribution segment’s financial instruments at March 31, 2013 is presented below by time period and fair value source:

 

     Fair Value of Contracts at March 31, 2013  
   Maturity in Years         

Source of Fair Value

   Less
Than 1
     1-3      4-5      Greater
Than 5
     Total
Fair
Value
 
     (In thousands)  

Prices actively quoted

   $ 3,544      $ 36,582      $       $       $ 40,126  

Prices based on models and other valuation methods

                                  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Fair Value

   $ 3,544      $ 36,582      $       $       $ 40,126  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and six months ended March 31, 2013 and 2012:

 

     Three Months Ended
March 31
    Six Months Ended
March 31
 
     2013     2012     2013     2012  
     (In thousands)  

Fair value of contracts at beginning of period

   $ (1,562   $ (15,263   $ (15,123   $ (25,050

Contracts realized/settled

     (492     13,779       12,244       31,228  

Fair value of new contracts

                        

Other changes in value

     (1,965     (1,090     (1,140     (8,752
  

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of contracts at end of period

     (4,019     (2,574     (4,019     (2,574

Netting of cash collateral

     11,971       5,696       11,971       5,696  
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash collateral and fair value of contracts at period end

   $ 7,952     $ 3,122     $ 7,952     $ 3,122  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

59


The fair value of our nonregulated segment’s financial instruments at March 31, 2013 is presented below by time period and fair value source:

 

     Fair Value of Contracts at March 31, 2013  
     Maturity in Years         

Source of Fair Value

   Less
Than 1
    1-3      4-5     Greater
Than 5
     Total
Fair
Value
 
     (In thousands)  

Prices actively quoted

   $ (8,267   $ 4,310      $ (62   $       $ (4,019

Prices based on models and other valuation methods

                                
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Fair Value

   $ (8,267   $ 4,310      $ (62   $       $ (4,019
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Pension and Postretirement Benefits Obligations

For the six months ended March 31, 2013 and 2012, our total net periodic pension and other benefits costs were $37.8 million and $34.6 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 2013 costs were determined using a September 30, 2012 measurement date. As of September 30, 2012, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2011, the measurement date for our fiscal 2012 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2013 pension and benefit costs to 4.04 percent. The expected return on our pension plan assets remained at 7.75 percent, based on historical experience and the current market projection of the target asset allocation. Accordingly, our fiscal 2013 pension and postretirement medical costs for the six months ended March 31, 2013 were higher than the prior-year period.

The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. Based upon the most recent evaluation, we anticipate contributing a total of between $30 million and $40 million to our defined benefit plans in fiscal 2013. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds. With respect to our postretirement medical plans, we anticipate contributing a total of between $25 million and $30 million to these plans during fiscal 2013.

The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans 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 plans and changes in the demographic composition of the participants in the plans.

 

60


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 six month periods ended March 31, 2013 and 2012.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  

METERS IN SERVICE, end of period

           

Residential

     2,816,734        2,803,716        2,816,734        2,803,716  

Commercial

     256,955        256,533        256,955        256,533  

Industrial

     2,127        2,198        2,127        2,198  

Public authority and other

     10,268        10,207        10,268        10,207  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total meters

     3,086,084        3,072,654        3,086,084        3,072,654  
  

 

 

    

 

 

    

 

 

    

 

 

 

INVENTORY STORAGE BALANCE — Bcf(1)

     28.3        35.4        28.3        35.4  

SALES VOLUMES — MMcf(2)

           

Gas sales volumes

           

Residential

     74,929        62,436        121,252        111,905  

Commercial

     36,465        31,247        61,721        57,470  

Industrial

     4,928        4,313        9,483        9,370  

Public authority and other

     3,801        3,424        6,420        6,042  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total gas sales volumes

     120,123        101,420        198,876        184,787  

Transportation volumes

     39,925        37,433        73,947        70,845  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total throughput

     160,048        138,853        272,823        255,632  
  

 

 

    

 

 

    

 

 

    

 

 

 

OPERATING REVENUES (000’s)(2)

           

Gas sales revenues

           

Residential

   $ 589,180        $578,048      $ 1,011,901      $ 1,005,358  

Commercial

     244,338        225,641        429,269        411,720  

Industrial

     24,300        22,793        45,756        47,022  

Public authority and other

     22,470        21,626        38,150        38,999  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total gas sales revenues

     880,288        848,108        1,525,076        1,503,099  

Transportation revenues

     17,792        15,237        33,233        29,529  

Other gas revenues

     7,096        7,722        13,654        14,552  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating revenues

   $ 905,176      $ 871,067      $ 1,571,963      $ 1,547,180  
  

 

 

    

 

 

    

 

 

    

 

 

 

Average transportation revenue per Mcf(1)

   $ 0.45      $ 0.42      $ 0.46      $ 0.43  

Average cost of gas per Mcf sold(1)

   $ 4.67      $ 4.94      $ 4.77      $ 4.87  

See footnote following these tables.

 

61


Natural Gas Distribution Sales and Statistical Data — Discontinued Operations

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  

Meters in service, end of period

     64,089        147,391        64,089        147,391  

Sales volumes — MMcf

           

Total gas sales volumes

     2,069        4,843        3,611        8,795  

Transportation volumes

     605        2,390        1,120        4,542  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total throughput

     2,674        7,233        4,731        13,337  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating revenues (000’s)

   $ 21,678      $ 44,315      $ 37,962      $ 84,945  

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data

 

     Three Months Ended
March 31
     Six Months Ended
March 31
 
     2013      2012      2013      2012  

CUSTOMERS, end of period

           

Industrial

     772        781        772        781  

Municipal

     124        139        124        139  

Other

     437        444        437        444  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,333        1,364        1,333        1,364  
  

 

 

    

 

 

    

 

 

    

 

 

 

NONREGULATED INVENTORY STORAGE

           

BALANCE — Bcf

     25.2        49.0        25.2        49.0  

REGULATED TRANSMISSION AND

           

STORAGE VOLUMES — MMcf(2)

     179,021        176,361        340,505        337,190  

NONREGULATED DELIVERED GAS SALES

           

VOLUMES — MMcf(2)

     109,723        111,656        208,732        218,118  

OPERATING REVENUES (000’s)(2)

           

Regulated transmission and storage

   $ 61,848      $ 58,037      $ 122,529      $ 114,796  

Nonregulated

     428,948        370,763        828,842        814,939  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating revenues

   $ 490,796      $ 428,800      $ 951,371      $ 929,735  
  

 

 

    

 

 

    

 

 

    

 

 

 

Notes to preceding tables:

 

  (1) 

Statistics are shown on a consolidated basis.                                                                                          

 

  (2) 

Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

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.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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, 2012. During the six months ended March 31, 2013, there were no material changes in our quantitative and qualitative disclosures about market risk.

 

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Item 4. Controls and Procedures

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 March 31, 2013 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 second quarter of the fiscal year ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

During the six months ended March 31, 2013, except as noted in Note 10 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, 2012. 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.

 

Item 6. Exhibits

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.

 

ATMOS ENERGY CORPORATION

               (Registrant)

By:

 

/s/    BRET J. ECKERT

 

Bret J. Eckert

Senior Vice President and Chief

Financial Officer

(Duly authorized signatory)

Date: May 2, 2013

 

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EXHIBITS INDEX

Item 6

 

Exhibit
Number

  

Description

  

Page Number or
Incorporation by
Reference to

  12    Computation of ratio of earnings to fixed charges   
  15    Letter regarding unaudited interim financial information   
  31    Rule 13a-14(a)/15d-14(a) Certifications   
  32    Section 1350 Certifications*   
101.INS    XBRL Instance Document   
101.SCH    XBRL Taxonomy Extension Schema   
101.CAL    XBRL Taxonomy Extension Calculation Linkbase   
101.DEF    XBRL Taxonomy Extension Definition Linkbase   
101.LAB    XBRL Taxonomy Extension Labels Linkbase   
101.PRE    XBRL Taxonomy Extension Presentation Linkbase   

 

  * These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

 

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