Edgar Filing: ATMOS ENERGY CORP

ATO 2013.12.31 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 December 31, 2013



¨	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 January 31, 2014.



Class		Shares Outstanding
No Par Value		90,958,751

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
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

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	December 31, 2013		September 30, 2013
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	7,861,741	$	7,722,019
Less accumulated depreciation and amortization	1,708,778		1,691,364
Net property, plant and equipment	6,152,963		6,030,655
Current assets
Cash and cash equivalents	194,563		66,199
Accounts receivable, net	661,213		301,992
Gas stored underground	286,542		244,741
Other current assets	157,252		64,201
Total current assets	1,299,570		677,133
Goodwill	741,363		741,363
Deferred charges and other assets	422,195		485,117
	$	8,616,091	$	7,934,268
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2013 — 90,958,302 shares; September 30, 2013 — 90,640,211 shares	$	455	$	453
Additional paid-in capital	1,769,516		1,765,811
Retained earnings	828,311		775,267
Accumulated other comprehensive income	63,032		38,878
Shareholders’ equity	2,661,314		2,580,409
Long-term debt	1,955,750		2,455,671
Total capitalization	4,617,064		5,036,080
Current liabilities
Accounts payable and accrued liabilities	458,198		241,611
Other current liabilities	365,508		368,891
Short-term debt	689,795		367,984
Current maturities of long-term debt	500,000		—
Total current liabilities	2,013,501		978,486
Deferred income taxes	1,230,052		1,164,053
Regulatory cost of removal obligation	356,617		359,299
Pension and postretirement liabilities	359,534		358,787
Deferred credits and other liabilities	39,323		37,563
	$	8,616,091	$	7,934,268

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended December 31
	2013			2012
	(Unaudited) (In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	843,865		$	666,787
Regulated transmission and storage segment	71,341			60,681
Nonregulated segment	447,721			399,894
Intersegment eliminations	(107,779		)	(93,207		)
	1,255,148			1,034,155
Purchased gas cost
Natural gas distribution segment	544,694			387,156
Regulated transmission and storage segment	—			—
Nonregulated segment	429,155			377,435
Intersegment eliminations	(107,658		)	(92,798		)
	866,191			671,793
Gross profit	388,957			362,362
Operating expenses
Operation and maintenance	115,757			106,527
Depreciation and amortization	60,469			59,579
Taxes, other than income	42,011			41,334
Total operating expenses	218,237			207,440
Operating income	170,720			154,922
Miscellaneous income (expense)	(2,132		)	698
Interest charges	32,115			30,522
Income from continuing operations before income taxes	136,473			125,098
Income tax expense	49,457			47,750
Income from continuing operations	87,016			77,348
Income from discontinued operations, net of tax ($0 and $1,728)	—			3,117
Net income	$	87,016		$	80,465
Basic earnings per share
Income per share from continuing operations	$	0.96		$	0.85
Income per share from discontinued operations	—			0.04
Net income per share — basic	$	0.96		$	0.89
Diluted earnings per share
Income per share from continuing operations	$	0.95		$	0.85
Income per share from discontinued operations	—			0.03
Net income per share — diluted	$	0.95		$	0.88
Cash dividends per share	$	0.37		$	0.35
Weighted average shares outstanding:
Basic	90,833			90,359
Diluted	91,746			91,309

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended December 31
	2013		2012
	(Unaudited) (In thousands)
Net income	$	87,016	$	80,465
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $1,435 and $(220)	2,394		(373		)
Cash flow hedges:
Amortization and unrealized gain on interest rate agreements, net of tax of $8,013 and $7,049	13,942		12,264
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $4,999 and $(233)	7,818		(365		)
Total other comprehensive income	24,154		11,526
Total comprehensive income	$	111,170	$	91,991

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended December 31
	2013			2012
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	87,016		$	80,465
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization	60,469			60,500
Charged to other accounts	221			128
Deferred income taxes	47,127			45,951
Other	5,228			3,242
Net assets / liabilities from risk management activities	(5,477		)	(15,641		)
Net change in operating assets and liabilities	(160,284		)	(144,787		)
Net cash provided by operating activities	34,300			29,858
Cash Flows From Investing Activities
Capital expenditures	(180,567		)	(190,027		)
Other, net	(5,867		)	(1,273		)
Net cash used in investing activities	(186,434		)	(191,300		)
Cash Flows From Financing Activities
Net increase in short-term debt	320,783			256,933
Cash dividends paid	(33,984		)	(31,992		)
Repurchase of equity awards	(6,289		)	(3,124		)
Other	(12		)	(13		)
Net cash provided by financing activities	280,498			221,804
Net increase in cash and cash equivalents	128,364			60,362
Cash and cash equivalents at beginning of period	66,199			64,239
Cash and cash equivalents at end of period	$	194,563		$	124,601

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 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, 2013, our regulated businesses generated approximately 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 December 31, 2013, covered service areas located in eight states. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers. In addition, we transport natural gas for others through our distribution system. 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, 2013. 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, 2013. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2013 are not indicative of our results of operations for the full 2014 fiscal year, which ends September 30, 2014.

Except as noted in Note 5, 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, 2013.

Certain prior-year amounts have been reclassified to conform with the current-year presentation.

Due to the April 1, 2013 sale of our Georgia distribution operations, prior year financial results for this service area are shown in discontinued operations.

During the three months ended December 31, 2013, there were no new accounting standards announced that will become applicable to the Company in future periods. Disclosure requirements for offsetting arrangements for financial instruments became effective for us beginning on October 1, 2013. We have presented these disclosures in Note 8. 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 three months ended December 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.

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



	December 31, 2013		September 30, 2013
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	180,512	$	187,977
Merger and integration costs, net	5,120		5,250
Deferred gas costs	8,630		15,152
Regulatory cost of removal asset	9,998		10,008
Rate case costs	5,806		6,329
Texas Rule 8.209⁽²⁾	31,838		30,364
APT annual adjustment mechanism	5,773		5,853
Recoverable loss on reacquired debt	20,796		21,435
Other	4,480		4,380
	$	272,953	$	286,748
Regulatory liabilities:
Deferred gas costs	$	50,094	$	16,481
Deferred franchise fees	4,792		1,689
Regulatory cost of removal obligation	425,028		427,524
Other	9,788		7,887
	$	489,702	$	453,581


⁽¹⁾	Includes $18.2 million and $17.4 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.

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. 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.

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, 2013. We evaluate performance based on net income or loss of the respective operating units.

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



	Three Months Ended December 31, 2013
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	842,432		$	21,170		$	391,546	$	—		$	1,255,148
Intersegment revenues	1,433			50,171			56,175		(107,779		)	—
	843,865			71,341			447,721		(107,779		)	1,255,148
Purchased gas cost	544,694			—			429,155		(107,658		)	866,191
Gross profit	299,171			71,341			18,566		(121		)	388,957
Operating expenses
Operation and maintenance	89,663			17,300			8,915		(121		)	115,757
Depreciation and amortization	49,551			9,786			1,132		—			60,469
Taxes, other than income	37,084			4,663			264		—			42,011
Total operating expenses	176,298			31,749			10,311		(121		)	218,237
Operating income	122,873			39,592			8,255		—			170,720
Miscellaneous income (expense)	(471		)	(1,181		)	324		(804		)	(2,132		)
Interest charges	23,325			8,957			637		(804		)	32,115
Income before income taxes	99,077			29,454			7,942		—			136,473
Income tax expense	36,320			10,008			3,129		—			49,457
Net income	$	62,757		$	19,446		$	4,813	$	—		$	87,016
Capital expenditures	$	127,506		$	52,921		$	140	$	—		$	180,567



	Three Months Ended December 31, 2012
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	665,549		$	18,699		$	349,907	$	—		$	1,034,155
Intersegment revenues	1,238			41,982			49,987		(93,207		)	—
	666,787			60,681			399,894		(93,207		)	1,034,155
Purchased gas cost	387,156			—			377,435		(92,798		)	671,793
Gross profit	279,631			60,681			22,459		(409		)	362,362
Operating expenses
Operation and maintenance	83,736			16,320			6,882		(411		)	106,527
Depreciation and amortization	50,060			8,390			1,129		—			59,579
Taxes, other than income	36,751			3,949			634		—			41,334
Total operating expenses	170,547			28,659			8,645		(411		)	207,440
Operating income	109,084			32,022			13,814		2			154,922
Miscellaneous income (expense)	(131		)	(127		)	1,667		(711		)	698
Interest charges	23,563			6,871			797		(709		)	30,522
Income from continuing operations before income taxes	85,390			25,024			14,684		—			125,098
Income tax expense	32,297			8,919			6,534		—			47,750
Income from continuing operations	53,093			16,105			8,150		—			77,348
Income from discontinued operations, net of tax	3,117			—			—		—			3,117
Net income	$	56,210		$	16,105		$	8,150	$	—		$	80,465
Capital expenditures	$	145,871		$	43,831		$	325	$	—		$	190,027

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



	December 31, 2013
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,799,657	$	1,293,093	$	60,213		$	—		$	6,152,963
Investment in subsidiaries	863,214		—		(2,096		)	(861,118		)	—
Current assets
Cash and cash equivalents	152,058		—		42,505			—			194,563
Assets from risk management activities	88,934		—		9,001			—			97,935
Other current assets	740,359		11,184		564,079			(308,550		)	1,007,072
Intercompany receivables	793,589		—		—			(793,589		)	—
Total current assets	1,774,940		11,184		615,585			(1,102,139		)	1,299,570
Intangible assets	—		—		110			—			110
Goodwill	574,190		132,462		34,711			—			741,363
Noncurrent assets from risk management activities	45,878		—		2,614			—			48,492
Deferred charges and other assets	345,075		20,960		7,558			—			373,593
	$	8,402,954	$	1,457,699	$	718,695		$	(1,963,257	)	$	8,616,091
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,661,314	$	415,868	$	447,346		$	(863,214	)	$	2,661,314
Long-term debt	1,955,750		—		—			—			1,955,750
Total capitalization	4,617,064		415,868		447,346			(863,214		)	4,617,064
Current liabilities
Current maturities of long-term debt	500,000		—		—			—			500,000
Short-term debt	972,795		—		—			(283,000		)	689,795
Liabilities from risk management activities	36		—		—			—			36
Other current liabilities	645,433		20,429		181,262			(23,454		)	823,670
Intercompany payables	—		719,438		74,151			(793,589		)	—
Total current liabilities	2,118,264		739,867		255,413			(1,100,043		)	2,013,501
Deferred income taxes	916,095		299,819		14,138			—			1,230,052
Regulatory cost of removal obligation	356,617		—		—			—			356,617
Pension and postretirement liabilities	359,534		—		—			—			359,534
Deferred credits and other liabilities	35,380		2,145		1,798			—			39,323
	$	8,402,954	$	1,457,699	$	718,695		$	(1,963,257	)	$	8,616,091



	September 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,719,873	$	1,249,767	$	61,015		$	—		$	6,030,655
Investment in subsidiaries	831,136		—		(2,096		)	(829,040		)	—
Current assets
Cash and cash equivalents	4,237		—		61,962			—			66,199
Assets from risk management activities	1,837		—		10,129			—			11,966
Other current assets	428,366		11,709		452,126			(293,233		)	598,968
Intercompany receivables	783,738		—		—			(783,738		)	—
Total current assets	1,218,178		11,709		524,217			(1,076,971		)	677,133
Intangible assets	—		—		121			—			121
Goodwill	574,190		132,462		34,711			—			741,363
Noncurrent assets from risk management activities	109,354		—		—			—			109,354
Deferred charges and other assets	347,687		19,227		8,728			—			375,642
	$	7,800,418	$	1,413,165	$	626,696		$	(1,906,011	)	$	7,934,268
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,580,409	$	396,421	$	434,715		$	(831,136	)	$	2,580,409
Long-term debt	2,455,671		—		—			—			2,455,671
Total capitalization	5,036,080		396,421		434,715			(831,136		)	5,036,080
Current liabilities
Current maturities of long-term debt	—		—		—			—			—
Short-term debt	645,984		—		—			(278,000		)	367,984
Liabilities from risk management activities	1,543		—		—			—			1,543
Other current liabilities	491,681		20,288		110,306			(13,316		)	608,959
Intercompany payables	—		712,768		70,970			(783,738		)	—
Total current liabilities	1,139,208		733,056		181,276			(1,075,054		)	978,486
Deferred income taxes	871,360		283,554		8,960			179			1,164,053
Regulatory cost of removal obligation	359,299		—		—			—			359,299
Pension and postretirement liabilities	358,787		—		—			—			358,787
Deferred credits and other liabilities	35,684		134		1,745			—			37,563
	$	7,800,418	$	1,413,165	$	626,696		$	(1,906,011	)	$	7,934,268

4. Earnings Per Share

We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. 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 months ended December 31, 2013 and 2012 are calculated as follows:



	Three Months Ended December 31
	2013		2012
	(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	87,016	$	77,348
Less: Income from continuing operations allocated to participating securities	235		260
Income from continuing operations available to common shareholders	$	86,781	$	77,088
Basic weighted average shares outstanding	90,833		90,359
Income from continuing operations per share — Basic	$	0.96	$	0.85

Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	3,117
Less: Income from discontinued operations allocated to participating securities	—		10
Income from discontinued operations available to common shareholders	$	—	$	3,107
Basic weighted average shares outstanding	90,833		90,359
Income from discontinued operations per share — Basic	$	—	$	0.04
Net income per share — Basic	$	0.96	$	0.89



	Three Months Ended December 31
	2013		2012
	(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	86,781	$	77,088
Effect of dilutive stock options and other shares	1		2
Income from continuing operations available to common shareholders	$	86,782	$	77,090
Basic weighted average shares outstanding	90,833		90,359
Additional dilutive stock options and other shares	913		950
Diluted weighted average shares outstanding	91,746		91,309
Income from continuing operations per share — Diluted	$	0.95	$	0.85

Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	—	$	3,107
Effect of dilutive stock options and other shares	—		—
Income from discontinued operations available to common shareholders	$	—	$	3,107
Basic weighted average shares outstanding	90,833		90,359
Additional dilutive stock options and other shares	913		950
Diluted weighted average shares outstanding	91,746		91,309
Income from discontinued operations per share — Diluted	$	—	$	0.03
Net income per share — Diluted	$	0.95	$	0.88

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

2011 Share Repurchase Program

We did not repurchase any shares during the three months ended December 31, 2013 and 2012 under our 2011 share repurchase program.

5. Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. Except as noted below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2013.

Long-term debt

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



	December 31, 2013		September 30, 2013
	(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		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
Total long-term debt	2,460,000		2,460,000
Less:
Original issue discount on unsecured senior notes and debentures	4,250		4,329
Current maturities	500,000		—
	$	1,955,750	$	2,455,671

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 primarily 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 $950 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1.0 billion of working capital funding. At December 31, 2013 and September 30, 2013, a total of $689.8 million and $368.0 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 $985 million of working capital funding, including a five-year $950 million unsecured facility with an accordion feature, which, if utilized would increased the borrowing capacity to $1.2 billion, a $25 million unsecured facility and a $10 million unsecured revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.1 million at December 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 rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2014.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, had two $25 million 364-day bilateral credit facilities that expired in December 2013. The $25 million 364-day uncommitted bilateral facility was extended to December 2014. The $25 million committed bilateral facility was replaced with a $15 million committed 364-day bilateral credit 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 $15.4 million at December 31, 2013. On January 29, 2014, the $25 million 364-day uncommitted bilateral facility was amended to temporarily increase the amount available under this facility to $50 million to address the increase in volumes and prices driven by colder than normal weather this winter-heating season. The maximum available under the facility will return to $25 million on June 30, 2014.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to 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, 2014.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.75 billion in common stock and/or debt securities. As of December 31, 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 December 31, 2013, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 56 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain 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 certain of 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 December 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.

6. 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 months ended December 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. On October 2, 2013, due to the retirement of one of our executives, we recognized a settlement loss of $4.5 million associated with our Supplemental Executive Benefits Plan (SEBP). In association with the retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.



	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2013			2012			2013			2012
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,738		$	5,202		$	4,196		$	4,700
Interest cost	6,824			6,025			3,988			3,241
Expected return on assets	(5,901		)	(5,739		)	(1,292		)	(997		)
Amortization of transition obligation	—			—			68			270
Amortization of prior service credit	(34		)	(35		)	(363		)	(362		)
Amortization of actuarial loss	3,932			5,561			158			1,049
Settlement loss	4,539			—			—			—
Net periodic pension cost	$	14,098		$	11,014		$	6,755		$	7,901

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



	Pension Benefits				Other Benefits
	2013		2012		2013		2012
Discount rate	4.95	%	4.04	%	4.95	%	4.04	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected return on plan assets	7.25	%	7.75	%	4.60	%	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 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, 2014. During the first three months of fiscal 2014, we contributed $4.7 million to our defined benefit plans and we anticipate contributing approximately $10 million to $15 million during the remainder of the fiscal year.

We contributed $5.9 million to our other post-retirement benefit plans during the three months ended December 31, 2013. We expect to contribute a total of approximately $15 million to $20 million to these plans during the remainder of the fiscal year.

7. Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 10 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2013.

Kentucky Litigation

Since April 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 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 to the landowners’ motion 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 been engaged in discovery activities in this case.

Tennessee Business License Tax

Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment and set February 1, 2014 as the date by which AEM and the TDOR will set a date for filing any cross motions for partial summary judgment as to the remaining issue. The Company anticipates a decision by the Chancery Court on the remaining issue in fiscal 2014. The cumulative assessment is expected to be approximately $11 million for the period December 2002 through December 2013, including tax, interest and penalties. We have accrued what we believe to be an adequate amount for the anticipated resolution of this matter and we will continue to review and if appropriate adjust this reserve until this matter is resolved. We continue to believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

We are a party to other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

Purchase Commitments

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2013, AEH was committed to purchase 91.1 Bcf within one year, 14.8 Bcf within one to three years and 0.9 Bcf after three years under indexed contracts. AEH is committed to purchase 4.4 Bcf within one year under fixed price contracts with prices ranging from $3.60 to $6.36 per Mcf. Purchases under these contracts totaled $350.2 million and $289.5 million for the three months ended December 31, 2013 and 2012.

Our natural gas distribution divisions maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

Our 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, 2013. There were no material changes to the estimated storage and transportation fees for the three months ended December 31, 2013.

Regulatory Matters

Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations. Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.

As of December 31, 2013, rate cases were in progress in our Colorado, Kentucky and West Texas service areas, annual rate filing mechanisms were in progress in Louisiana and Mississippi and an infrastructure program filing and ad valorem filing were in progress in Kansas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

8. 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, 2013. During the three months ended December 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.

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 2013-2014 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 39 percent, or 24.8 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 52 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.

Interest Rate Risk Management Activities

We periodically manage interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings.

As of December 31, 2013, we have 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 December 31, 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 December 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 December 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	—	(18,585	)
	Cash Flow	—	31,500
	Not designated	15,796	59,095
		15,796	72,010

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 December 31, 2013 and September 30, 2013. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties.



		Natural Gas Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
December 31, 2013
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	12,238		$	(12,089	)
Interest rate contracts	Other current assets / Other current liabilities	83,578		—			—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			783			(983		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	44,833		—			—			—
Total		128,411		—			13,021			(13,072		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	5,356		(36		)	55,288			(63,144		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,045		—			35,740			(32,926		)
Total		6,401		(36		)	91,028			(96,070		)
Gross Financial Instruments		134,812		(36		)	104,049			(109,142		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(101,435		)	101,435
Net Financial Instruments		134,812		(36		)	2,614			(7,707		)
Cash collateral		—		—			9,001			7,707
Net Assets/Liabilities from Risk Management Activities		$	134,812	$	(36	)	$	11,615		$	—



		Natural Gas Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
September 30, 2013
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	9,094		$	(12,173	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			416			(1,639		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	107,512		—			—			—
Total		107,512		—			9,510			(13,812		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	1,837		(1,543		)	65,388			(70,876		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,842		—			40,982			(45,892		)
Total		3,679		(1,543		)	106,370			(116,768		)
Gross Financial Instruments		111,191		(1,543		)	115,880			(130,580		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(115,875		)	115,875
Net Financial Instruments		111,191		(1,543		)	5			(14,705		)
Cash collateral		—		—			10,124			14,705
Net Assets/Liabilities from Risk Management Activities		$	111,191	$	(1,543	)	$	10,129		$	—

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 December 31, 2013 and 2012 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $5.1 million and $16.1 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 months ended December 31, 2013 and 2012 is presented below.



	Three Months Ended December 31
	2013			2012
	(In thousands)
Commodity contracts	$	(8,561	)	$	7,314
Fair value adjustment for natural gas inventory designated as the hedged item	13,779			8,818
Total decrease in purchased gas cost	$	5,218		$	16,132
The (increase) decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(620	)	$	(241	)
Timing ineffectiveness	5,838			16,373
	$	5,218		$	16,132

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.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 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 December 31, 2013
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(2,609	)	$	(2,609	)
Loss arising from ineffective portion of commodity contracts	—			(119		)	(119		)
Total impact on purchased gas cost	—			(2,728		)	(2,728		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(1,058		)	—			(1,058		)
Total Impact from Cash Flow Hedges	$	(1,058	)	$	(2,728	)	$	(3,786	)



	Three Months Ended December 31, 2012
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(5,160	)	$	(5,160	)
Loss arising from ineffective portion of commodity contracts	—			(19		)	(19		)
Total impact on purchased gas cost	—			(5,179		)	(5,179		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(502		)	—			(502		)
Total Impact from Cash Flow Hedges	$	(502	)	$	(5,179	)	$	(5,681	)

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 months ended December 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 December 31
	2013		2012
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	13,270	$	11,945
Forward commodity contracts	6,226		(3,513		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	672		319
Forward commodity contracts	1,592		3,148
Total other comprehensive income from hedging, net of tax⁽¹⁾	$	21,760	$	11,899


⁽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 gains (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 December 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	$	(2,343	)	$	3,458		$	1,115
Thereafter	(27,350		)	(116		)	(27,466		)
Total⁽¹⁾	$	(29,693	)	$	3,342		$	(26,351	)


⁽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 December 31, 2013 and 2012 was a decrease in gross profit of $0.8 million and $0.1 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.

9. 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 tables provide 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, 2013	$	5,448	$	37,906	$	(4,476	)	$	38,878
Other comprehensive income before reclassifications	2,394		13,270		6,226			21,890
Amounts reclassified from accumulated other comprehensive income	—		672		1,592			2,264
Net current-period other comprehensive income	2,394		13,942		7,818			24,154
December 31, 2013	$	7,842	$	51,848	$	3,342		$	63,032



	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	(373		)	11,945			(3,513		)	8,059
Amounts reclassified from accumulated other comprehensive income	—			319			3,148			3,467
Net current-period other comprehensive income	(373		)	12,264			(365		)	11,526
December 31, 2012	$	5,288		$	(32,009	)	$	(9,360	)	$	(36,081	)

The following tables detail reclassifications out of AOCI for the three months ended December 31, 2013 and 2012. Amounts in parentheses below indicate decreases to net income in the statement of income.



	Three Months Ended December 31, 2013
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Cash flow hedges
Interest rate agreements	$	(1,058	)	Interest charges
Commodity contracts	(2,609		)	Purchased gas cost
	(3,667		)	Total before tax
	1,403			Tax benefit
Total reclassifications	$	(2,264	)	Net of tax



	Three Months Ended December 31, 2012
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Cash flow hedges
Interest rate agreements	$	(502	)	Interest charges
Commodity contracts	(5,160		)	Purchased gas cost
	(5,662		)	Total before tax
	2,195			Tax benefit
Total reclassifications	$	(3,467	)	Net of tax