ATO 2013.06.30 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 June 30, 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 August 2, 2013.
Class
  
Shares Outstanding
No Par Value
  
90,640,211



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
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

2


PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
June 30, 2013
 
September 30, 2012
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
7,494,175

 
$
7,134,470

Less accumulated depreciation and amortization
1,652,960

 
1,658,866

Net property, plant and equipment
5,841,215

 
5,475,604

Current assets
 
 
 
Cash and cash equivalents
31,979

 
64,239

Accounts receivable, net
350,237

 
234,526

Gas stored underground
209,101

 
256,415

Other current assets
90,936

 
272,782

Total current assets
682,253

 
827,962

Goodwill and intangible assets
740,814

 
740,847

Deferred charges and other assets
538,516

 
451,262

 
$
7,802,798

 
$
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: June 30, 2013 — 90,639,520 shares; September 30, 2012 — 90,239,900 shares
$
453

 
$
451

Additional paid-in capital
1,757,059

 
1,745,467

Retained earnings
800,643

 
660,932

Accumulated other comprehensive income (loss)
23,289

 
(47,607
)
Shareholders’ equity
2,581,444

 
2,359,243

Long-term debt
2,455,593

 
1,956,305

Total capitalization
5,037,037

 
4,315,548

Current liabilities
 
 
 
Accounts payable and accrued liabilities
229,876

 
215,229

Other current liabilities
348,706

 
489,665

Short-term debt
141,998

 
570,929

Current maturities of long-term debt
—

 
131

Total current liabilities
720,580

 
1,275,954

Deferred income taxes
1,197,274

 
1,015,083

Regulatory cost of removal obligation
360,578

 
381,164

Pension and postretirement liabilities
444,540

 
457,196

Deferred credits and other liabilities
42,789

 
50,730

 
$
7,802,798

 
$
7,495,675

See accompanying notes to condensed consolidated financial statements.

3


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
467,144

 
$
315,634

Regulated transmission and storage segment
74,041

 
67,073

Nonregulated segment
421,808

 
256,250

Intersegment eliminations
(105,058
)
 
(62,543
)
 
857,935

 
576,414

Purchased gas cost
 
 
 
Natural gas distribution segment
227,649

 
120,575

Regulated transmission and storage segment
—

 
—

Nonregulated segment
418,548

 
224,829

Intersegment eliminations
(104,759
)
 
(62,161
)
 
541,438

 
283,243

Gross profit
316,497

 
293,171

Operating expenses
 
 
 
Operation and maintenance
121,258

 
106,045

Depreciation and amortization
58,129

 
58,956

Taxes, other than income
50,714

 
46,624

Total operating expenses
230,101

 
211,625

Operating income
86,396

 
81,546

Miscellaneous expense
(467
)
 
(2,075
)
Interest charges
32,741

 
34,909

Income from continuing operations before income taxes
53,188

 
44,562

Income tax expense
19,714

 
16,548

Income from continuing operations
33,474

 
28,014

Income from discontinued operations, net of tax ($0 and $1,792)
—

 
3,118

Gain on sale of discontinued operations, net of tax ($2,909 and $0)
5,294

 
—

Net income
$
38,768

 
$
31,132

Basic earnings per share
 
 
 
Income per share from continuing operations
$
0.37

 
$
0.31

Income per share from discontinued operations
0.06

 
0.03

Net income per share — basic
$
0.43

 
$
0.34

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
0.36

 
$
0.31

Income per share from discontinued operations
0.06

 
0.03

Net income per share — diluted
$
0.42

 
$
0.34

Cash dividends per share
$
0.350

 
$
0.345

Weighted average shares outstanding:
 
 
 
Basic
90,603

 
90,118

Diluted
91,550

 
90,993

See accompanying notes to condensed consolidated financial statements.

4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
2,039,107

 
$
1,862,814

Regulated transmission and storage segment
196,570

 
181,869

Nonregulated segment
1,250,650

 
1,071,189

Intersegment eliminations
(285,241
)
 
(229,955
)
 
3,201,086

 
2,885,917

Purchased gas cost
 
 
 
Natural gas distribution segment
1,172,975

 
1,011,832

Regulated transmission and storage segment
—

 
—

Nonregulated segment
1,200,624

 
1,028,592

Intersegment eliminations
(284,123
)
 
(228,857
)
 
2,089,476

 
1,811,567

Gross profit
1,111,610

 
1,074,350

Operating expenses
 
 
 
Operation and maintenance
338,871

 
329,989

Depreciation and amortization
174,888

 
176,742

Taxes, other than income
146,355

 
144,170

Total operating expenses
660,114

 
650,901

Operating income
451,496

 
423,449

Miscellaneous income (expense)
1,943

 
(3,585
)
Interest charges
96,594

 
107,278

Income from continuing operations before income taxes
356,845

 
312,586

Income tax expense
133,683

 
120,104

Income from continuing operations
223,162

 
192,482

Income from discontinued operations, net of tax ($3,986 and $9,339)
7,202

 
16,268

Gain on sale of discontinued operations, net of tax ($2,909 and $0)
5,294

 
—

Net income
$
235,658

 
$
208,750

Basic earnings per share
 
 
 
Income per share from continuing operations
$
2.46

 
$
2.13

Income per share from discontinued operations
0.14

 
0.18

Net income per share — basic
$
2.60

 
$
2.31

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
2.43

 
$
2.10

Income per share from discontinued operations
0.14

 
0.18

Net income per share — diluted
$
2.57

 
$
2.28

Cash dividends per share
$
1.050

 
$
1.035

Weighted average shares outstanding:
 
 
 
Basic
90,497

 
90,131

Diluted
91,445

 
91,006

See accompanying notes to condensed consolidated financial statements.

5



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(Unaudited)
(In thousands)
Net income
$
38,768

 
$
31,132

 
$
235,658

 
$
208,750

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(202), $(523), $(532) and $1,194
(348
)
 
(888
)
 
(921
)
 
2,059

Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $17,865, $(18,399), $38,427 and $(9,995)
31,079

 
(31,328
)
 
66,852

 
(17,019
)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(2,243), $11,401, $3,174 and $(2,595)
(3,508
)
 
17,830

 
4,965

 
(4,060
)
Total other comprehensive income (loss)
27,223

 
(14,386
)
 
70,896

 
(19,020
)
Total comprehensive income
$
65,991

 
$
16,746

 
$
306,554

 
$
189,730


See accompanying notes to condensed consolidated financial statements.

6


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
235,658

 
$
208,750

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Gain on sale of discontinued operations
(8,203
)
 
—

Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
176,737

 
183,884

Charged to other accounts
446

 
310

Deferred income taxes
130,365

 
120,713

Other
14,460

 
22,386

Net assets / liabilities from risk management activities
(6,386
)
 
12,759

Net change in operating assets and liabilities
(33,502
)
 
(29,996
)
Net cash provided by operating activities
509,575

 
518,806

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(582,473
)
 
(497,374
)
Proceeds from the sale of discontinued operations
153,023

 
—

Other, net
(3,139
)
 
(4,247
)
Net cash used in investing activities
(432,589
)
 
(501,621
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(435,084
)
 
(6,688
)
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
(96,060
)
 
(94,338
)
Repurchase of common stock
—

 
(12,535
)
Repurchase of equity awards
(5,146
)
 
(5,219
)
Issuance of common stock
8

 
251

Net cash used in financing activities
(109,246
)
 
(120,898
)
Net decrease in cash and cash equivalents
(32,260
)
 
(103,713
)
Cash and cash equivalents at beginning of period
64,239

 
131,419

Cash and cash equivalents at end of period
$
31,979

 
$
27,706


See accompanying notes to condensed consolidated financial statements.

7


ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 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 generated 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 June 30, 2013, covered service areas located in eight 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 nine-month period ended June 30, 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 June 30, 2013 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as noted in Note 10, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

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 June 30, 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 nine months ended June 30, 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 adoption of this standard should not have an impact on our financial position, results of operations or cash flows. The second standard, which became effective during our second fiscal quarter, requires the presentation of amounts reclassified out of accumulated other

8


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 this standard did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the nine months ended June 30, 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.
 
Significant regulatory assets and liabilities as of June 30, 2013 and September 30, 2012 included the following:
 
June 30,
2013
 
September 30,
2012
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
280,136

 
$
296,160

Merger and integration costs, net
5,376

 
5,754

Deferred gas costs
1,271

 
31,359

Regulatory cost of removal asset
6,058

 
10,500

Rate case costs
6,207

 
4,661

Deferred franchise fees
242

 
2,714

Texas Rule 8.209(2)
21,351

 
5,370

APT annual adjustment mechanism
5,167

 
4,539

Other
1,935

 
7,262

 
$
327,743

 
$
368,319

Regulatory liabilities:
 
 
 
Deferred gas costs
$
30,773

 
$
23,072

Deferred franchise fees
2,097

 
—

Regulatory cost of removal obligation
426,656

 
459,688

Other
5,398

 
5,637

 
$
464,924

 
$
488,397

 
(1) 
Includes $15.5 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(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 were classified as assets held for sale at September 30, 2012 as discussed in Note 6. As of June 30, 2013 we did not have any assets or liabilities classified as held for sale due to the sale of substantially all of our Georgia assets on April 1, 2013.
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.

9


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 nine months ended June 30, 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.
 
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 58 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.
 
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.

10


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 only 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 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 June 30, 2013, the remaining amortization periods for the settled Treasury locks extend through fiscal 2043.
 
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of June 30, 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 June 30, 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
 
—

 
(22,250
)
 
 
Cash Flow
 
—

 
26,520

 
 
Not designated
 
14,649

 
75,520

 
 
 
 
14,649

 
79,790

Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of June 30, 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 $14.3 million and $23.7 million of cash held on deposit in margin accounts as of June 30, 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.

11


 
Balance Sheet Location
 
Natural Gas
Distribution
 
Nonregulated
 
Total
 
 
 
 
 
(In thousands)
 
 
June 30, 2013
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets
 
$
—

 
$
12,250

 
$
12,250

Noncurrent commodity contracts
Deferred charges and other assets
 
84,432

 
401

 
84,833

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities
 
—

 
(13,771
)
 
(13,771
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 
—

 
(1,912
)
 
(1,912
)
Total
 
 
84,432

 
(3,032
)
 
81,400

Not Designated As Hedges:
 
 
 
 
 
 
 
Asset Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current assets
 
2,015

 
68,972

 
70,987

Noncurrent commodity contracts
Deferred charges and other assets
 
1,035

 
49,651

 
50,686

Liability Financial Instruments
 
 
 
 
 
 
 
Current commodity contracts
Other current liabilities
 
(1,094
)
 
(69,710
)
 
(70,804
)
Noncurrent commodity contracts
Deferred credits and other liabilities
 
—

 
(50,204
)
 
(50,204
)
Total
 
 
1,956

 
(1,291
)
 
665

Total Financial Instruments
 
 
$
86,388

 
$
(4,323
)
 
$
82,065

 
 
 
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.

12


Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended June 30, 2013 and 2012 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(0.4) million and $19.0 million. For the nine months ended June 30, 2013 and 2012 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $17.3 million and $21.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and nine months ended June 30, 2013 and 2012 is presented below.
 
Three Months Ended 
 June 30
 
2013
 
2012
 
(In thousands)
Commodity contracts
$
14,453

 
$
(14,942
)
Fair value adjustment for natural gas inventory designated as the hedged item
(15,143
)
 
34,296

Total (increase) decrease in purchased gas cost
$
(690
)
 
$
19,354

The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(2,361
)
 
$
2,077

Timing ineffectiveness
1,671

 
17,277

 
$
(690
)
 
$
19,354

 
Nine Months Ended 
 June 30
 
2013
 
2012
 
(In thousands)
Commodity contracts
$
3,921

 
$
38,211

Fair value adjustment for natural gas inventory designated as the hedged item
13,261

 
(16,039
)
Total decrease in purchased gas cost
$
17,182

 
$
22,172

The decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(1,143
)
 
$
2,179

Timing ineffectiveness
18,325

 
19,993

 
$
17,182

 
$
22,172

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 nine months ended June 30, 2013. During the nine months ended June 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market.

Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 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.

13


 
Three Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
558

 
$
558

Gain arising from ineffective portion of commodity contracts
—

 
260

 
260

Total impact on purchased gas cost
—

 
818

 
818

Loss on settled interest rate agreements reclassified from AOCI into interest expense
(1,057
)
 
—

 
(1,057
)
Total Impact from Cash Flow Hedges
$
(1,057
)
 
$
818

 
$
(239
)
 
Three Months Ended June 30, 2012
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
(19,534
)
 
$
(19,534
)
Loss arising from ineffective portion of commodity contracts
—

 
(328
)
 
(328
)
Total impact on purchased gas cost
—

 
(19,862
)
 
(19,862
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(502
)
 
—

 
(502
)
Total Impact from Cash Flow Hedges
$
(502
)
 
$
(19,862
)
 
$
(20,364
)
 
Nine Months Ended June 30, 2013
 
Natural
Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
(9,802
)
 
$
(9,802
)
Gain arising from ineffective portion of commodity contracts
—

 
158

 
158

Total impact on purchased gas cost
—

 
(9,644
)
 
(9,644
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,432
)
 
—

 
(2,432
)
Total Impact from Cash Flow Hedges
$
(2,432
)
 
$
(9,644
)
 
$
(12,076
)
 
 
Nine Months Ended June 30, 2012
 
Natural Gas
Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
(52,358
)
 
$
(52,358
)
Loss arising from ineffective portion of commodity contracts
—

 
(996
)
 
(996
)
Total impact on purchased gas cost
—

 
(53,354
)
 
(53,354
)
Loss on settled interest rate agreements reclassified from AOCI into interest expense
(1,506
)
 
—

 
(1,506
)
Total Impact from Cash Flow Hedges
$
(1,506
)
 
$
(53,354
)
 
$
(54,860
)
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 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.

14


 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$
30,408

 
$
(31,644
)
 
$
65,308

 
$
(17,968
)
Forward commodity contracts
(3,168
)
 
5,914

 
(1,015
)
 
(35,998
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
671

 
316

 
1,544

 
949

Forward commodity contracts
(340
)
 
11,916

 
5,980

 
31,938

Total other comprehensive income (loss) from hedging, net of tax(1)
$
27,571

 
$
(13,498
)
 
$
71,817

 
$
(21,079
)
 
(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 interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 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
)
 
$
(3,133
)
 
$
(5,819
)
Thereafter
(28,350
)
 
(897
)
 
(29,247
)
Total(1) 
$
(31,036
)
 
$
(4,030
)
 
$
(35,066
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
 
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2013 and 2012 was an increase (decrease) in gross profit of $(8.4) million and $11.2 million. For the nine months ended June 30, 2013 and 2012 gross profit decreased $1.7 million and $3.8 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.

15


 
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
449

 
65,308

 
(1,015
)
 
64,742

Amounts reclassified from accumulated other comprehensive income
(1,370
)
 
1,544

 
5,980

 
6,154

Net current-period other comprehensive income
(921
)
 
66,852

 
4,965

 
70,896

June 30, 2013
$
4,740

 
$
22,579

 
$
(4,030
)
 
$
23,289

 
The following tables detail reclassifications out of AOCI for the three and nine months ended June 30, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.
 
Three Months Ended June 30, 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
$
(531
)
 
Operation and maintenance expense
 
(531
)
 
Total before tax
 
193

 
Tax benefit
 
$
(338
)
 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(1,057
)
 
Interest charges
Commodity contracts
558

 
Purchased gas cost
 
(499
)
 
Total before tax
 
168

 
Tax benefit
 
$
(331
)
 
Net of tax
Total reclassifications
$
(669
)
 
Net of tax
 
Nine Months Ended June 30, 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
$
2,158

 
Operation and maintenance expense
 
2,158

 
Total before tax
 
(788
)
 
Tax expense
 
$
1,370

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(2,432
)
 
Interest charges
Commodity contracts
(9,803
)
 
Purchased gas cost
 
(12,235
)
 
Total before tax
 
4,711

 
Tax benefit
 
$
(7,524
)
 
Net of tax
Total reclassifications
$
(6,154
)
 
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 carrying value, which substantially approximates fair

16


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 nine months ended June 30, 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 June 30, 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)
 
June 30, 2013
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$
—

 
$
87,482

 
$
—

 
$
—

 
$
87,482

Nonregulated segment
1,196

 
130,078

 
—

 
(119,278
)
 
11,996

Total financial instruments
1,196

 
217,560

 
—

 
(119,278
)
 
99,478

Hedged portion of gas stored underground
76,706

 
—

 
—

 
—

 
76,706

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds
—

 
5,122

 
—

 
—

 
5,122

Registered investment companies
39,051

 
—

 
—

 
—

 
39,051

Bonds
—

 
27,473

 
—

 
—

 
27,473

Total available-for-sale securities
39,051

 
32,595

 
—

 
—

 
71,646

Total assets
$
116,953

 
$
250,155

 
$
—

 
$
(119,278
)
 
$
247,830

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Natural gas distribution segment
$
—

 
$
1,094

 
$
—

 
$
—

 
$
1,094

Nonregulated segment
179

 
135,418

 
—

 
(133,530
)
 
2,067

Total liabilities
$
179

 
$
136,512

 
$
—

 
$
(133,530
)
 
$
3,161


17


 
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 June 30, 2013, we had $14.3 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $2.5 million was used to offset current risk management liabilities under master netting arrangements and the remaining $11.8 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.
 

18


Available-for-sale securities are comprised of the following:
 
Amortized
Cost
 
Gross
Unrealized
Gain
 
Gross
Unrealized
Loss
 
Fair
Value
 
(In thousands)
As of June 30, 2013
 
 
 
 
 
 
 
Domestic equity mutual funds
$
26,993

 
$
6,611

 
$
—

 
$
33,604

Foreign equity mutual funds
4,536

 
925

 
(14
)
 
5,447

Bonds
27,390

 
132

 
(49
)
 
27,473

Money market funds
5,122

 
—

 
—

 
5,122

 
$
64,041

 
$
7,668

 
$
(63
)
 
$
71,646

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 June 30, 2013 and September 30, 2012, our available-for-sale securities included $44.2 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2013, we maintained investments in bonds that have contractual maturity dates ranging from July 2013 through December 2019. During the nine months ended June 30, 2013, we recognized a net gain of $2.2 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 June 30, 2013:
 
June 30, 2013
 
(In thousands)
Carrying Amount
$
2,460,000

Fair Value
$
2,707,340


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 $153 million. The sale was previously announced on August 8, 2012. In connection with the sale, we recognized a net of tax gain of $5.3 million.
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 months ended June 30, 2013, net income from discontinued operations includes the aforementioned gain on sale, while for the nine months ended June 30, 2013, net income from discontinued operations includes the operating results of our Georgia operations and the gain on sale. For the three and nine months ended June 30, 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.

19


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 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 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Operating revenues
$
—

 
$
18,162

 
$
37,962

 
$
103,107

Purchased gas cost
—

 
6,803

 
21,464

 
57,936

Gross profit
—

 
11,359

 
16,498

 
45,171

Operating expenses
—

 
6,522

 
5,858

 
20,069

Operating income
—

 
4,837

 
10,640

 
25,102

Other nonoperating income
—

 
73

 
548

 
505

Income from discontinued operations before income taxes
—

 
4,910

 
11,188

 
25,607

Income tax expense
—

 
1,792

 
3,986

 
9,339

Income from discontinued operations
—

 
3,118

 
7,202

 
16,268

Gain on sale of discontinued operations, net of tax
5,294

 
—

 
5,294

 
—

Net income from discontinued operations
$
5,294

 
$
3,118

 
$
12,496

 
$
16,268


The following table presents balance sheet data related to assets held for sale. At September 30, 2012 assets held for sale include assets and liabilities associated with our Georgia operations. At June 30, 2013 we did not have any assets or liabilities held for sale.
 
September 30, 2012
 
(In thousands)
Net plant, property & equipment
$
142,865

Gas stored underground
4,688

Other current assets
6,931

Deferred charges and other assets
87

Assets held for sale
$
154,571

 
 
Accounts payable and accrued liabilities
$
2,114

Other current liabilities
3,776

Regulatory cost of removal
3,257

Deferred credits and other liabilities
2,426

Liabilities held for sale
$
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 nine months ended June 30, 2013.
Long-term debt
Long-term debt at June 30, 2013 and September 30, 2012 consisted of the following:
 

20


 
June 30, 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 note 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
4,407

 
3,695

Current maturities
—

 
131

 
$
2,455,593

 
$
1,956,305

 
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 lock agreements 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 June 30, 2013 and September 30, 2012, a total of $142.0 million and $310.9 million was outstanding under our commercial paper program.
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 June 30, 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

21


(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 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, 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 $38.6 million at June 30, 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 replaced our registration statement that expired on March 31, 2013. As of June 30, 2013, $1.75 billion was available under the shelf registration statement.
Debt Covenants
The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2013, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 52 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 June 30, 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.

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 nine months ended June 30, 2013 and 2012 are calculated as follows:

22


 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2013
 
2012
 
2013
 
2012
 
(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations
$
33,474

 
$
28,014

 
$
223,162

 
$
192,482

Less: Income from continuing operations allocated to participating securities
91

 
116

 
760

 
808

Income from continuing operations available to common shareholders
$
33,383

 
$
27,898

 
$
222,402

 
$
191,674

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Income from continuing operations per share — Basic
$
0.37

 
$
0.31

 
$
2.46

 
$
2.13

 
 
 
 
 
 
 
 
Basic Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations
$
5,294

 
$
3,118

 
$
12,496

 
$
16,268

Less: Income from discontinued operations allocated to participating securities
14

 
13

 
43

 
68

Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Income from discontinued operations per share — Basic
$
0.06

 
$
0.03

 
$
0.14

 
$
0.18

Net income per share — Basic
$
0.43

 
$
0.34

 
$
2.60

 
$
2.31


 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
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
$
33,383

 
$
27,898

 
$
222,402

 
$
191,674

Effect of dilutive stock options and other shares
—

 
—

 
5

 
4

Income from continuing operations available to common shareholders
$
33,383

 
$
27,898

 
$
222,407

 
$
191,678

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Additional dilutive stock options and other shares
947

 
875

 
948

 
875

Diluted weighted average shares outstanding
91,550

 
90,993

 
91,445

 
91,006

Income from continuing operations per share — Diluted
$
0.36

 
$
0.31

 
$
2.43

 
$
2.10

 
 
 
 
 
 
 
 
Diluted Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Effect of dilutive stock options and other shares
—

 
—

 
—

 
—

Income from discontinued operations available to common shareholders
$
5,280

 
$
3,105

 
$
12,453

 
$
16,200

Basic weighted average shares outstanding
90,603

 
90,118

 
90,497

 
90,131

Additional dilutive stock options and other shares
947

 
875

 
948

 
875

Diluted weighted average shares outstanding
91,550

 
90,993

 
91,445

 
91,006

Income from discontinued operations per share — Diluted
$
0.06

 
$
0.03

 
$
0.14

 
$
0.18

Net income per share — Diluted
$
0.42

 
$
0.34

 
$
2.57

 
$
2.28


23


There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 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 nine months ended June 30, 2013 as part of our 2011 share repurchase program. For the nine months ended June 30, 2012, we repurchased and retired 387,991 shares for an aggregate value of $12.5 million as part of the program.

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 nine months ended June 30, 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. On April 1, 2013, due to the retirement of certain executives, we recognized a curtailment loss of $3.2 million associated with our Supplemental Executive Benefit Plan and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which will reduce our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.
 
Three Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
5,194

 
$
4,297

 
$
4,700

 
$
4,089

Interest cost
6,019

 
6,677

 
3,241

 
3,465

Expected return on assets
(5,739
)
 
(5,368
)
 
(997
)
 
(651
)
Amortization of transition asset
—

 
—

 
271

 
377

Amortization of prior service cost
(35
)
 
(35
)
 
(363
)
 
(362
)
Amortization of actuarial loss
5,432

 
4,142

 
1,049

 
662

Curtailment
3,161

 
—

 
—