UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED ~~MARCH~~SEPTEMBER 3130, 2013



o	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	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).

Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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).



Energen Corporation	YES	x	NO	o
Alabama Gas Corporation	YES	x	NO	o

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.

Energen Corporation - Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Alabama Gas Corporation - Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



Energen Corporation	YES	o	NO	x
Alabama Gas Corporation	YES	o	NO	x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of ~~May~~November 1, 2013.

Energen Corporation		$0.01 par value		72,~~222~~685,~~501~~415 shares
Alabama Gas Corporation		$0.01 par value		1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED ~~MARCH~~SEPTEMBER 3130, 2013

TABLE OF CONTENTS

		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	(a) Consolidated Condensed Statements of Income of Energen Corporation	3
	(b) Consolidated Condensed Statements of Comprehensive Income of Energen Corporation	4
	(c) Consolidated Condensed Balance Sheets of Energen Corporation	5
	(d) Consolidated Condensed Statements of Cash Flows of Energen Corporation	7
	(e) Condensed Statements of Income of Alabama Gas Corporation	8
	(f) Condensed Balance Sheets of Alabama Gas Corporation	9
	(g) Condensed Statements of Cash Flows of Alabama Gas Corporation	11
	(h) Notes to Unaudited Condensed Financial Statements	12
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2730
	Selected Business Segment Data of Energen Corporation	3640
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3842
Item 4.	Controls and Procedures	3943
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 1.	Legal Proceedings	44
Item 6.	Exhibits	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
SIGNATURES		41
Item 6.	Exhibits	44
SIGNATURES		45

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	March 31,
	September 30,						September 30,
(in thousands, except per share data)	2013			2012			2013			2012
Operating Revenues
Oil and gas operations	$	~~254~~272,~~994~~038		$	~~223~~214,~~957~~620		$	875,350		$	799,339
Natural gas distribution	~~237~~48,~~685~~368			~~194~~61,~~487~~809			390,567			327,183
Total operating revenues	~~492~~320,~~679~~406			~~418~~276,~~444~~429			1,265,917			1,126,522
Operating Expenses
Cost of gas	9520,~~442~~435			5920,~~586~~924			163,448			94,179
Operations and maintenance	~~145~~141,~~837~~271			~~110~~123,~~561~~730			413,401			336,568
Depreciation, depletion and amortization	~~115~~136,~~295~~123			9496,~~534~~634			365,355			276,465
Asset impairment	—			21,545
Taxes, other than income taxes	24,858			19,572			77,955			64,314
Taxes, other than income taxes	28,772			26,235
Accretion expense	1,771			1,605			5,187			4,691
Accretion expense	1,997			1,813
Total operating expenses	324,458			262,465			1,025,346			776,217
Total operating expenses	387,343			314,274
Operating Income (Loss)	(4,052		)	13,964			240,571			350,305
Operating Income	105,336			104,170
Other Income (Expense)
Other Income (Expense)
Interest expense	(17,689		)	(17,195		)	(51,751		)	(48,447		)
Interest expense	(16,754		)	(15,425		)
Other income	13,062			1,488			15,578			3,678
Other income	1,758			2,032
Other expense	(434		)	(84		)	(631		)	(305		)
Other expense	(69		)	(113		)
Total other expense	(5,061		)	(15,791		)	(36,804		)	(45,074		)
Total other expense	(15,065		)	(13,506		)
Income (Loss) From Continuing Operations Before Income Taxes	(9,113		)	(1,827		)	203,767			305,231
Income Before Income Taxes	90,271			90,664
Income tax expense (benefit)	(3,627		)	(322		)	73,897			110,508
Income tax expense	33,579			33,258
Income (Loss) From Continuing Operations	(5,486		)	(1,505		)	129,870			194,723
Net Income	$	56,692		$	57,406
Discontinued Operations, net of taxes
Diluted Earnings Per Average Common Share	$	0.78		$	0.79
Income (loss) from discontinued operations	1,866			3,551			6,269			(3,984		)
Basic Earnings Per Average Common Share	$	0.79		$	0.80
Loss on disposal of discontinued operations	(15,678		)	—			(15,678		)	—
Dividends Per Common Share	$	0.145		$	0.140
Income (Loss) From Discontinued Operations	(13,812		)	3,551			(9,409		)	(3,984		)
Diluted Average Common Shares Outstanding	72,288			72,326
Net Income (Loss)	$	(19,298	)	$	2,046		$	120,461		$	190,739
Basic Average Common Shares Outstanding	72,143			72,102
Diluted Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.69
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.05		)
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Basic Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.70
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.06		)
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Dividends Per Common Share	$	0.145		$	0.140		$	0.435		$	0.420
Diluted Average Common Shares Outstanding	72,346			72,316			72,272			72,301
Basic Average Common Shares Outstanding	72,346			72,130			72,220			72,121

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	March 31,
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Net Income	$	56,692		$	57,406
Net Income (Loss)	$	(19,298	)	$	2,046		$	120,461		$	190,739
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of commodity derivative instruments, net of tax of ($16,424) and ($7,498)	(26,798		)	(12,234		)
Current period change in fair value of commodity derivative instruments, net of tax of $42, ($30,622), ($6,669) and $30,621	69			(49,962		)	(10,882		)	49,961
Reclassification adjustment for commodity derivative instruments, net of tax of ($6,570) and $302	(10,720		)	493
Reclassification adjustment for commodity derivative instruments, net of tax of ($3,205), ($4,924), ($11,486) and ($14,303)	(5,229		)	(8,034		)	(18,740		)	(23,337		)
Current period change in fair value of interest rate swap, net of tax of ($11) and ($265)	(20		)	(492		)
Current period change in fair value of interest rate swap, net of tax of ($188), ($375), ($23) and ($1,205)	(350		)	(697		)	(42		)	(2,240		)
Reclassification adjustment for interest rate swap, net of tax of $143 and $137	266			254
Reclassification adjustment for interest rate swap, net of tax of $156, $142, $449 and $422	290			263			833			783
Total cash flow hedges	(375,~~272~~220		)	(1158,~~979~~430		)	(28,831		)	25,167
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $26 and $25	48			47
Amortization of net obligation at transition, net of taxes of $26, $25, $77 and $75	48			47			143			140
Amortization of prior service cost, net of taxes of $27 and $30	51			55
Amortization of prior service cost, net of taxes of $28, $30, $82 and $89	51			55			153			166
Amortization of net loss, including settlement charges, net of taxes of $920 and $412	1,709			766
Amortization of net loss, including settlement charges, net of taxes of $729, $413, $2,383 and $1,238	1,354			766			4,425			2,300
Total pension and postretirement plans	1,808			868
Current period change in fair value of pension and postretirement plans, net of taxes of $2,238, ($4,073), $2,238 and ($4,073)	4,157			(7,564		)	4,157			(7,564		)
Comprehensive Income	$	21,228		$	46,295
Total pension and postretirement plans	5,610			(6,696		)	8,878			(4,958		)
Comprehensive Income (Loss)	$	(18,908	)	$	(63,080	)	$	100,508		$	210,948

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	~~March~~September 3130, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	2012,~~303~~413	$	9,704
Accounts receivable, net of allowance for doubtful accounts of $5,446 at March 31, 2013, and $6,549 at December 31, 2012	241,507		277,900
Accounts receivable, net of allowance for doubtful accounts of $6,070 at September 30, 2013, and $6,549 at December 31, 2012	200,043		277,900
Inventories
Storage gas inventory	939,~~264~~507		32,205
Materials and supplies	2519,~~283~~187		28,291
Liquified natural gas in storage	32,~~109~~990		3,498
Regulatory asset	2411,~~135~~213		45,515
Income tax receivable	17,~~883~~653		6,664
Deferred income taxes	27,278		8,520
Assets held for sale	183,862		—
Prepayments and other	12,084		12,823
Deferred income taxes	42,722		8,520
Total current assets	364,846		425,120
Prepayments and other	12,996		12,823
Total current assets	532,586		425,120
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,~~712~~655,~~635~~343		6,439,127
Less accumulated depreciation, depletion and amortization	1,~~858~~657,~~960~~682		1,765,241
Oil and gas properties, net	4,~~853~~997,~~675~~661		4,673,886
Utility plant	1,~~435~~471,~~924~~174		1,416,590
Less accumulated depreciation	~~583~~594,~~625~~604		573,947
Utility plant, net	~~852~~876,~~299~~570		842,643
Other property, net	2529,~~218~~733		25,107
Total property, plant and equipment, net	5,~~731~~903,~~192~~964		5,541,636
Other Assets
Regulatory asset	~~109~~89,~~002~~004		110,566
Other postretirement assets	117,~~732~~417		1,404
Long-term derivative instruments	2612,~~199~~786		40,577
Deferred charges and other	6059,~~207~~115		56,587
Total other assets	~~197~~178,~~140~~322		209,134
TOTAL ASSETS	$	6,~~293~~614,~~178~~872	$	6,175,890

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	~~March~~September 3130, 2013			December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	75125,000		$	50,000
Notes payable to banks	~~712~~901,000			643,000
Accounts payable	~~285~~256,~~920~~109			257,579
Accrued taxes	3851,~~666~~878			30,076
Customers' deposits	25,231			24,705
Customers’ deposits	20,531			24,705
Amounts due customers	1019,~~580~~974			19,718
Accrued wages and benefits	1725,~~587~~896			24,984
Regulatory liability	4140,~~886~~168			45,116
Royalty payable	3849,~~771~~976			34,426
Other	27,344			30,178
Liabilities related to assets held for sale	23,945			—
Total current liabilities	1,272,985			1,159,782
Other	26,812			30,178
Long-term debt	1,078,529			1,103,528
Total current liabilities	1,541,289			1,159,782
Long-term debt	1,028,509			1,103,528
Deferred Credits and Other Liabilities
Asset retirement obligation	~~120~~106,~~599~~604			118,023
Pension and other postretirement liabilities	~~106~~90,~~515~~893			110,282
Regulatory liability	6881,~~812~~414			80,404
Long-term derivative instruments	91,~~705~~961			11,305
Deferred income taxes	~~931~~979,~~628~~898			905,601
Other	1214,~~981~~638			10,275
Total deferred credits and other liabilities	1,~~250~~275,~~240~~408			1,235,890
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,083,108 shares issued at March 31, 2013, and 75,067,760 shares issued at December 31, 2012	751			751
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,485,159 shares issued at September 30, 2013, and 75,067,760 shares issued at December 31, 2012	755			751
Premium on capital stock	~~493~~514,~~928~~784			492,108
Capital surplus	2,802			2,802
Retained earnings	2,~~360~~403,~~274~~062			2,314,055
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	816,~~834~~730			46,352
Pension and postretirement plans	(5043,~~699~~629		)	(52,507		)
Interest rate swap	(1,~~910~~365		)	(2,156		)
Deferred compensation plan	3,~~416~~319			2,774
Treasury stock, at cost: 2,969,784 shares at March 31, 2013, and 2,998,620 shares at December 31, 2012	(125,972		)	(127,489		)
Treasury stock, at cost: 2,977,920 shares at September 30, 2013, and 2,998,620 shares at December 31, 2012	(126,792		)	(127,489		)
Total shareholders' equity	2,691,424			2,676,690
Total shareholders’ equity	2,769,666			2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,~~293~~614,~~178~~872		$	6,175,890

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Three months ended March 31, (in thousands)	2013			2012
Nine months ended September 30, (in thousands)	2013			2012
Operating Activities
Net income	$	56120,~~692~~461		$	57190,~~406~~739
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	~~115~~392,~~295~~854			94300,~~534~~863
Asset impairment	—24,612			21,545
Accretion expense	16,~~997~~131			15,~~813~~581
Deferred income taxes	2951,~~028~~682			2380,~~182~~724
Bad debt expense (recovery)	218			(258		)
Bad debt expense	1,203			370
Exploratory expense	~~541~~8,759			111,~~076~~420
Change in derivative fair value	3753,~~977~~581			47(34,~~221~~469		)
(Gain) loss on sale of assets	(656		)	47
Gain on sale of assets	(10,980		)	(420		)
Other, net	11,078			4,261
Stock based compensation expense	11,759			6,820
Other, net	25,455			10,779
Net change in:
Accounts receivable	~~(35~~50,~~312~~767		)	2057,~~063~~334
Inventories	261,~~338~~169			~~1,473~~62
Accounts payable	9(74,~~670~~183		)	7(12,~~327~~562		)
Amounts due customers, including gas supply pass-through	1036,~~254~~891			(3152,~~926~~466		)
Income tax receivable	~~4,781~~(989		)	51,~~852~~817
Pension and other postretirement benefit contributions	(1011,~~334~~332		)	(35,~~176~~056		)
Other current assets and liabilities	340,~~886~~176			~~(19~~20,~~460~~038		)
Net cash provided by operating activities	~~261~~728,~~453~~016			~~230~~603,~~980~~119
Investing Activities
Additions to property, plant and equipment	(~~297~~961,~~301~~798		)	(~~276~~898,~~791~~202		)
Acquisitions, net of cash acquired	(1321,~~146~~400		)	(68104,~~176~~200		)
Proceeds from sale of assets	116,~~370~~220			132,~~766~~420
Other, net	(~~362~~1,210		)	(~~375~~746		)
Net cash used in investing activities	(~~309~~968,~~439~~188		)	(~~331~~1,~~576~~000,728		)
Financing Activities
Payment of dividends on common stock	(1031,~~473~~454		)	(1030,~~095~~292		)
Issuance of common stock	—13,680			~~604~~1,164
Payment of long-term debt	(1055		)	(251,143		)
Net change in short-term debt	69258,000			~~150~~465,000
Tax benefit on stock compensation	682,710			~~227~~514
Other	—			(38		)
Net cash provided by financing activities	58242,~~585~~881			~~140~~435,~~673~~205
Net change in cash and cash equivalents	102,~~599~~709			4037,~~077~~596
Cash and cash equivalents at beginning of period	9,704			9,541
Cash and Cash Equivalents at End of Period	$	2012,~~303~~413		$	4947,~~618~~137

The accompanying notes are an integral part of these unaudited consolidated condensed financial statements.

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	March 31,
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating Revenues	$	~~237~~48,~~685~~368		$	~~194~~61,~~487~~809		$	390,567		$	327,183
Operating Expenses
Cost of gas	9520,~~442~~435			5920,~~586~~924			163,448			94,179
Operations and maintenance	3833,~~017~~650			3437,~~066~~235			107,672			107,470
Depreciation and amortization	1011,~~729~~063			10,~~446~~572			32,665			31,551
Income taxes
Current	25(7,~~921~~703		)	25(9,~~440~~242		)	16,440			13,567
Deferred	32,~~020~~093			3,~~198~~264			6,448			9,431
Taxes, other than income taxes	145,~~204~~764			115,~~829~~821			27,814			23,718
Total operating expenses	~~187~~65,~~333~~302			~~144~~68,~~565~~574			354,487			279,916
Operating Income	50,352			49,922
Operating Income (Loss)	(16,934		)	(6,765		)	36,080			47,267
Other Income (Expense)
Allowance for funds used during construction	~~219~~184			~~134~~187			630			452
Other income	~~750~~12,092			~~986~~787			13,203			1,925
Other expense	(69434		)	(6284		)	(623		)	(254		)
Total other income	~~900~~11,842			~~1,058~~890			13,210			2,123
Interest Expense
Interest on long-term debt	3,~~378~~377			3,~~424~~423			10,133			10,270
Other interest expense	~~652~~492			~~638~~741			1,600			1,915
Total interest expense	43,~~030~~869			4,~~062~~164			11,733			12,185
Net Income	$	47,222		$	46,918
Net Income (Loss)	$	(8,961	)	$	(10,039	)	$	37,557		$	37,205

The accompanying notes are an integral part of these unaudited condensed financial statements.

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	~~March~~September 3130, 2013			December 31, 2012
ASSETS
Property, Plant and Equipment
Utility plant	$	1,~~435~~471,~~924~~174		$	1,416,590
Less accumulated depreciation	~~583~~594,~~625~~604			573,947
Utility plant, net	~~852~~876,~~299~~570			842,643
Other property, net	41			42
Current Assets
Cash and cash equivalents	178,~~260~~541			5,559
Accounts receivable
Gas	9939,~~657~~962			94,011
Other	54,~~698~~655			5,117
Affiliated companies	46,~~620~~579			5,742
Allowance for doubtful accounts	(45,~~600~~300		)	(5,700		)
Inventories
Storage gas inventory	939,~~264~~507			32,205
Materials and supplies	5,~~541~~401			5,528
Liquified natural gas in storage	32,~~109~~990			3,498
Regulatory asset	2411,~~135~~213			45,515
Income tax receivable	—1,601			2,762
Deferred income taxes	1822,~~669~~314			18,799
Prepayments and other	36,~~674~~595			4,451
Total current assets	~~187~~144,~~027~~058			217,487
Other Assets
Regulatory asset	~~109~~89,~~002~~004			110,566
Pension and other postretirement assets	113,~~103~~399			848
Deferred charges and other	1110,~~098~~994			11,290
Total other assets	~~121~~113,~~203~~397			122,704
TOTAL ASSETS	$	1,~~160~~134,~~570~~066		$	1,182,876

The accompanying notes are an integral part of these unaudited condensed financial statements.

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	~~March~~September 3130, 2013		December 31, 2012
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder's equity
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at March 31, 2013 and December 31, 2012	20		20
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2013 and December 31, 2012	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	~~364~~330,~~783~~234		325,999
Total common shareholder's equity	399,287		360,503
Total common shareholder’s equity	364,738		360,503
Long-term debt	~~250~~249,~~018~~973		250,028
Total capitalization	~~649~~614,~~305~~711		610,531
Current Liabilities
Notes payable to banks	3049,000		77,000
Accounts payable	3832,~~264~~997		51,741
Accrued taxes	4728,~~068~~635		24,186
Customers' deposits	25,231		24,705
Customers’ deposits	20,531		24,705
Amounts due customers	1019,~~580~~974		19,718
Accrued wages and benefits	68,~~184~~154		6,703
Regulatory liability	4140,~~886~~168		45,116
Other	9,~~535~~293		9,018
Total current liabilities	208,~~748~~752		258,187
Deferred Credits and Other Liabilities
Deferred income taxes	~~192~~199,~~271~~372		189,381
Pension and other postretirement liabilities	3928,~~914~~371		43,611
Regulatory liability	6881,~~812~~414		80,404
Other	1,~~520~~446		762
Total deferred credits and other liabilities	~~302~~310,~~517~~603		314,158
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,~~160~~134,~~570~~066	$	1,182,876

The accompanying notes are an integral part of these unaudited condensed financial statements.

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended March 31, (in thousands)	2013			2012
Nine months ended September 30, (in thousands)	2013			2012
Operating Activities
Net income	$	4737,~~222~~557		$	4637,~~918~~205
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1032,~~729~~665			1031,~~446~~551
Deferred income taxes	36,~~020~~448			39,~~198~~431
Bad debt expense (recovery)	217			(258		)
Bad debt expense	1,120			364
Other, net	3,685			(2,564		)
Gain on sale of assets	10,889			—
Other, net	1,524			4,681
Net change in:
Accounts receivable	~~(23~~19,~~409~~801		)	1429,~~706~~539
Inventories	23(6,~~317~~667		)	5,~~985~~975
Accounts payable	(1116,~~306~~181		)	(2017,~~364~~222		)
Amounts due customers, including gas supply pass-through	1036,~~254~~891			(3152,~~926~~466		)
Income tax receivable	21,~~762~~161			86,~~374~~002
Pension and other postretirement benefit contributions	(5,~~365~~848		)	(~~681~~2,044		)
Other current assets and liabilities	~~24,183~~(112		)	11(9,~~425~~795		)
Net cash provided by operating activities	85119,~~309~~248			4543,~~259~~221
Investing Activities
Additions to property, plant and equipment	(1967,~~046~~085		)	(1449,~~245~~746		)
Other, net	886			(767		)
Proceeds from sale of assets	13,838			—
Net cash used in investing activities	(18,160		)	(15,012		)
Other, net	(1,642		)	2,490
Net cash used in investing activities	(54,889		)	(47,256		)
Financing Activities
Dividends	(833,~~438~~322		)	(828,~~027~~182		)
Payment of long-term debt	(1055		)	(25143		)
Net change in short-term debt	(47,000		)	10,000
Net increases in advances from affiliates	—			24,867
Net change in short-term debt	(28,000		)	10,000
Other	—			(38		)
Net cash provided by (used in) financing activities	(5561,~~448~~377		)	16,~~910~~504
Net change in cash and cash equivalents	112,~~701~~982			322,~~157~~469
Cash and cash equivalents at beginning of period	5,559			7,817
Cash and Cash Equivalents at End of Period	$	178,~~260~~541		$	3910,~~974~~286

The accompanying notes are an integral part of these unaudited condensed financial statements.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company'’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the ~~quarter~~nine months ended ~~March~~September 3130, 2012 resulted in aan ~~decrease~~increase of $31.9 million and a decrease of $40.58 million to Energen and Alagasco'’s operating cash flows, respectively. The Company and Alagasco determined that the amounts were not material to the respective statements of cash flows. This adjustment ~~caused~~had no impact toon Energen or Alagasco'’s statements of income.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. ~~RSE~~The Company’s current ~~extension~~RSE isorder ~~for~~had aan ~~seven-year~~original ~~period~~term extending through December 31, 2014. ~~RSE~~At ~~will~~its ~~continue~~meeting ~~after~~on ~~December~~November 315, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, ~~unless~~which are described as follows. The term of the order is extended through September 30, ~~after~~2018. ~~notice~~Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance based adjustment of 5 basis points to the ~~Company~~return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from a ~~hearing~~2007 base year, adjusted for inflation using the ~~APSC~~Index ~~votes~~Range. Alagasco expects these modifications to ~~modify~~be orincluded ~~discontinue~~in a final written order in the ~~RSE~~fourth ~~methodology~~quarter of 2013.

Alagasco'’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent ~~throughout~~through ~~the~~December ~~term~~31, ~~of the RSE order~~2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco'’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended ~~March~~September 3130, 2013, Alagasco had a net $2.4.3 million pre-tax and a net $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million and a $13.0 million annual increase in revenues became effective December 1, 2012 and 2011, respectively.

RSE currently limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. ~~Under~~Currently, under the inflation-based ~~Cost Control Measurement (~~CCM) established by the APSC, if the percentage change in ~~operations and maintenance (~~O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the ~~Consumer~~September ~~Price~~ Index ~~For All Urban Consumers (Index~~ Range) on a rate year basis, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012 and 2011.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

~~(3)~~base ~~extraordinary~~for ~~O&M~~the ~~expenses,~~following ~~other~~year ~~than~~will ~~environmental~~be ~~response~~set ~~costs~~at ~~and~~the ~~self~~top ~~insurance~~of ~~costs,~~the ~~resulting~~Index ~~from~~Range. aCertain ~~single~~items ~~force~~that ~~majeure~~fluctuate ~~event~~based oron ~~multiple~~situations ~~force~~demonstrated ~~majeure~~to ~~events~~be ~~greater~~beyond ~~than~~Alagasco’s ~~$275,000~~control ~~and~~may ~~$412,500,~~be ~~respectively,~~excluded ~~during~~from athe ~~rate~~CCM ~~year;~~calculation. ~~and~~Alagasco’s ~~(4)~~O&M ~~negative~~expense ~~individual~~fell ~~large~~within ~~commercial~~the ~~and~~Index ~~industrial~~Range ~~customer~~for ~~budget~~the ~~revenue~~rate ~~variances~~years ~~that~~ended ~~exceed~~September ~~$350~~30,~~000~~ ~~during~~2013 aand ~~rate year~~2012.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen'’s oil and gas subsidiary, ~~recognizes~~periodically ~~all~~enters ~~derivatives~~into onderivative ~~the~~commodity ~~balance~~instruments ~~sheet~~to ~~and~~hedge ~~measures~~its ~~all~~exposure ~~derivatives~~to atprice ~~fair~~fluctuations ~~value.~~on Ifoil, anatural ~~derivative~~gas isand ~~designated~~natural asgas aliquids ~~cash~~production. ~~flow~~In ~~hedge,~~prior ~~the effectiveness of the hedge~~years, orAlagasco ~~the~~entered ~~degree~~into ~~that~~cash ~~the~~flow ~~gain~~derivative ~~(loss)~~commodity ~~for~~instruments ~~the~~to ~~hedging~~hedge ~~instrument~~its ~~offsets~~exposure ~~the~~to ~~loss~~price ~~(gain)~~fluctuations on ~~the~~its ~~hedged~~gas ~~item, is measured at each reporting period~~supply. ~~The~~Such ~~effective~~instruments ~~portion~~may ofinclude over-the-counter ~~gain~~(OTC) orswaps ~~loss~~and onbasis ~~the~~hedges ~~derivative~~typically ~~instrument~~with isinvestment ~~recognized~~and incommercial ~~other~~banks ~~comprehensive~~and ~~income~~energy-trading ~~(OCI)~~firms. asHedge atransactions ~~component~~are ofpursuant ~~shareholders’~~to ~~equity~~standing ~~and~~authorizations ~~subsequently~~by ~~reclassified~~the asBoard ~~operating~~of ~~revenues~~Directors, ~~when~~which ~~the~~do ~~forecasted~~not ~~transaction~~authorize ~~affects~~speculative ~~earnings~~positions. The ~~ineffective~~Company ~~portion~~recognizes ofall aderivatives ~~derivative's~~on ~~change~~the inbalance ~~fair~~sheet ~~value~~and ismeasures ~~required~~all toderivatives beat ~~recognized~~fair ~~in operating revenues immediately~~value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net ~~loss~~gain position with ~~six~~seven of its active counterparties and in a net loss position with the remaining six at ~~March~~September 3130, 2013. The ~~two~~ largest counterparty net loss ~~positions~~position at ~~March~~September 3130, 2013, Morgan Stanley Capital Group, ~~Inc and Barclays Bank PLC,~~ constituted approximately $2419.78 million ~~and $5.1 million, respectively,~~ of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with ~~seven of its active counterparties at March 31, 2013. The two largest counterparty net gain positions at March 31, 2013,~~ Macquarie Bank Limited ~~and~~for ~~BP Corporation North America Inc., constituted~~ approximately $10.30 million ~~and $5~~.3 ~~million, respectively, of Energen Resources’ net gain on fair value of derivatives.~~

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of ~~March~~September 3130, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

~~The~~Prior ~~Company~~to ~~periodically~~June ~~enters~~30, ~~into~~2013, ~~derivative~~the ~~transactions~~Company ~~that~~utilized ~~do not qualify for~~ cash flow hedge accounting ~~but~~where ~~are~~applicable ~~considered~~for byits ~~management~~derivative totransactions. ~~represent~~If ~~valid~~a ~~economic~~derivative ~~hedges~~is ~~and~~designated ~~are accounted for~~ as ~~mark-to-market~~a ~~transactions.~~cash ~~These~~flow ~~economic hedges may include~~hedge, ~~but~~the ~~are~~effectiveness ~~not~~of ~~limited~~the tohedge, ~~hedges~~or onthe ~~estimated~~degree ~~future~~that ~~production~~the ~~not~~gain ~~yet~~(loss) ~~flowing,~~for ~~basis~~the ~~hedges~~hedging ~~without~~instrument aoffsets ~~corresponding~~the ~~New~~loss ~~York~~(gain) ~~Mercantile~~on ~~Exchange~~the ~~(NYMEX)~~hedged ~~hedge~~item, ~~and~~is ~~hedges~~measured onat ~~non-operated~~each orreporting ~~other~~period. ~~properties~~The ~~for~~effective ~~which~~portion ~~all~~ of the ~~necessary~~gain ~~information~~or toloss ~~qualify~~on ~~for~~the ~~cash~~derivative ~~flow~~instrument ~~hedge~~is ~~accounting~~recognized isin ~~either~~other ~~not~~comprehensive ~~readily~~income ~~available~~(OCI) oras ~~subject~~a tocomponent ~~change.~~of ~~Derivatives~~shareholders’ ~~that~~equity doand ~~not~~subsequently ~~qualify~~reclassified ~~for~~as ~~hedge~~operating ~~treatment~~revenues orwhen ~~are~~the ~~not~~forecasted ~~designated~~transaction asaffects ~~cash~~earnings. ~~flow~~The ~~hedges~~ineffective ~~are~~portion ~~recorded~~of ata derivative’s change in fair value ~~with~~is ~~gains~~required orto ~~losses~~be recognized in operating revenues ~~in the period of change~~immediately. ~~Effective~~All ~~March~~other ~~31,~~derivative ~~2013,~~transactions ~~Energen~~not ~~Resources~~previously ~~dedesignated~~qualified ~~5,078~~for ~~thousand~~cash ~~barrels~~flow ~~(MBbl)~~hedge ofaccounting ~~various~~are ~~Permian~~still ~~Basin~~considered ~~NYMEX~~by ~~oil~~management ~~contracts due~~ to ~~lack~~represent ofvalid ~~correlation.~~economic ~~Any~~hedges ~~gains~~and orare ~~losses~~accounted ~~from~~for ~~inception~~as ~~of the hedge~~ mark-to-market ~~March~~transactions. ~~31,~~These ~~2013~~derivatives ~~were~~are ~~frozen~~recorded ~~and~~at ~~will~~fair ~~remain~~value inwith ~~accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent~~ gains or losses ~~will~~recognized bein ~~accounted~~operating ~~for~~revenues asin ~~mark-to-market~~the ~~and~~period ~~recognized~~of ~~immediately through operating revenues~~change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive

income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	~~March~~September 3130, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	51,277			$	—	$	51,277
Long-term asset derivative instruments	25,921				—		25,921
Total derivative assets	77,198				—		77,198
Accounts receivable	(36,245		)	*	—		(36,245		)
Long-term asset derivative instruments	(6,594		)	*	—		(6,594		)
Accounts payable	(11,983		)		—		(11,983		)
Long-term liability derivative instruments	(7,275		)		—		(7,275		)
Total derivative liabilities	(62,097		)		—		(62,097		)
Total derivatives designated	15,101				—		15,101
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	~~(4,342~~$	53,082	)	*	—$	—	~~(4,342~~$	53,082	)
Long-term asset derivative instruments	618,~~872~~346				—		618,~~872~~346
Total derivative assets	271,~~530~~428				—		271,~~530~~428
Accounts payable	(20,816		)		—		(20,816		)
Accounts receivable	(40,789		)	*	—		(40,789		)
Long-term liability derivative instruments	(1,074		)		—		(1,074		)
Long-term asset derivative instruments	(5,560		)	*	—		(5,560		)
Total derivative liabilities	(21,890		)		—		(21,890		)
Accounts payable	(31,928		)		—		(31,928		)
Total derivatives not designated	(19,360		)		—		(19,360		)
Long-term liability derivative instruments	(1,379		)		—		(1,379		)
Total derivatives	$	(4,259	)		$	—	$	(4,259	)
Total derivative liabilities	(79,656		)		—		(79,656		)
Total derivatives not designated	$	(8,228	)		$	—	$	(8,228	)



(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $510.43 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of ~~March~~September 3130, 2013, and December 31, 2012, respectively.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

(in thousands)	Location on Statement of Income	Three ~~monthsendedMarch~~monthsendedSeptember 3130, 2013			Three ~~monthsendedMarch~~monthsendedSeptember 3130, 2012
Loss recognized in OCI on derivatives (effective portion), net of tax of ($16.4) million and ($7.5) million	—	$	(26,798	)	$	(12,234	)
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	178,~~824~~455		$	115,~~872~~998
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(~~534~~22	)	$	(23,~~666~~042	)



(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

(in thousands)	Location on Statement of Income	Three ~~monthsendedMarch~~monthsendedSeptember 3130, 2013			Three ~~monthsendedMarch~~monthsendedSeptember 3130, 2012
Loss recognized in income on derivatives	Operating revenues	$	(3192,~~501~~313	)	$	(4445,~~005~~618	)

As of March 31, 2013, $1.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of March 31, 2013, the Company had 4.2 billion cubic feet (Bcf) and 9.7 Bcf of natural gas hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 10.5 million barrels (MMBbl), 8.2 MMBbl and 0.7 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.



(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825

As of September 30, 2013, $13.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of September 30, 2013, the Company had 13.5 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 4.4 million barrels (MMBbl), 9.8 MMBbl and 5.8 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 11.9 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $6.7 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.

Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average ContractPrice	Description
Natural Gas
2013	93.40	Bcf	$4.8382 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	62,~~752~~434	MBbl	$9091.9944 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	~~720~~5,760	MBbl	$9088.1085 Bbl	NYMEX Swaps
Oil Basis Differential
2013	~~2,701~~907	MBbl	$(32.0299) Bbl	WTS/WTI Basis Swaps*
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	3312.90	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

As of ~~March~~September 3130, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	March 31, 2013
	September 30, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,~~452~~712	)	$	2325,~~142~~005		$	1012,~~690~~293
Noncurrent assets	126,~~194~~828			145,~~005~~958			2612,~~199~~786
Current liabilities	(2440,~~834~~970		)	(79,~~965~~042		)	(3231,~~799~~928		)
Noncurrent liabilities	(52,~~626~~580		)	(21,~~723~~201		)	(81,~~349~~379		)
Net derivative asset (liability)	$	(3049,~~718~~434	)	$	2641,~~459~~206		$	(48,~~259~~228	)



	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

As of ~~March~~September 3130, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which ~~are~~were classified as Level 2 fair values and ~~are~~ included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $2822 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $~~5.2~~22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

	Three months ended			Three months ended
(in thousands)	~~March~~September 3130, 2013			~~March~~September 3130, 2012
Balance at beginning of period	$	8951,~~019~~131		$	65103,~~801~~456
Realized gains	2710,~~107~~852			1318,~~181~~737
Unrealized gains (losses) relating to instruments held at the reporting date*	(63,482		)	39,767
Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
Settlements during period	(269,~~185~~830		)	(1317,~~826~~929		)
Balance at end of period	$	2641,~~459~~206		$	~~104~~57,~~923~~281

*Includes $12.4 million in mark-to-market losses and $3.8 million in mark-to-market gains for the three months ended March 31, 2013 and 2012.



	Nine months ended			Nine months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	41,952			51,858
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
Settlements during period	(40,930		)	(51,050		)
Balance at end of period	$	41,206		$	57,281

*Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012, respectively.

The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands)	Fair Value as of ~~March~~September 3130, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	149,~~529~~499		Discounted Cash Flow	Forward Basis	($0.1412 - $0.1614) Mcf
2014	$	1627,~~066~~678		Discounted Cash Flow	Forward Basis	($0.1413 - $0.1615) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	~~(1,854~~286	)	Discounted Cash Flow	Forward Basis	($0.1214) Mcf
2014	$	~~(2,731~~825	)	Discounted Cash Flow	Forward Basis	($0.1213 - $0.1415) Mcf
Oil Basis - WTS/WTI
2013	$	(61,~~209~~897	)	Discounted Cash Flow	Forward Basis	($01.6606) Bbl
Oil Basis - WTI/WTI
2013	$	(~~2,207~~641	)	Discounted Cash Flow	Forward Basis	($0.1841 - $0.2850) Bbl
Natural Gas Liquids
2013	$	84,~~865~~255		Discounted Cash Flow	Forward Price	$0.7574 - $0.8381 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:

March 31, 2013

September 30, 2013

Gross Amounts Not Offset in the Balance Sheets

(in thousands)

Gross Amounts Recognized

Gross Amounts Offset in the Balance Sheets

Net Amount Presented in the Balance Sheets

Financial Instruments

Cash Collateral Received

Net Amount

Derivative assets

7971,~~728~~428

(4246,~~839~~349

)

3625,~~889~~079

—

3625,~~889~~079

Derivative liabilities

8379,~~987~~656

(4246,~~839~~349

)

4133,~~148~~307

—

4133,~~148~~307



	December 31, 2012
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	149,504	$	(44,135	)	$	105,369	$	—	$	—	$	105,369
Derivative liabilities	$	56,328	$	(44,135	)	$	12,193	$	—	$	—	$	12,193

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2013					March 31, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	56,692	72,143	$	0.79	$	57,406	72,102	$	0.80
Effect of dilutive securities
Stock options			144					216
Non-vested restricted stock			1					8
Diluted EPS	$	56,692	72,288	$	0.78	$	57,406	72,326	$	0.79

For the three months ended March 31, 2013 and 2012 the Company had 988,087 and 849,583 options, respectively, that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months ended March 31, 2013, the Company had 161,249 performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2012, the Company had no performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2013 and 2012, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)



	Three months ended							Three months ended
(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
Effect of dilutive securities
Stock options				—						183
Non-vested restricted stock				—						3
Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03

In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.



	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2013					September 30, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	120,461	72,220	$	1.67	$	190,739	72,121	$	2.64
Effect of dilutive securities
Stock options			41					177
Non-vested restricted stock			10					3
Performance share awards			1					—
Diluted EPS	$	120,461	72,272	$	1.67	$	190,739	72,301	$	2.64

The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:



	Three months ended September 30,		Nine months ended September 30,
(in thousands)	2013	2012	2013	2012
Stock options	—	850	875	850
Performance share awards	—	—	79	—

5. SEGMENT INFORMATION

The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).

	Three months ended						Nine months ended
	March 31,
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating revenues
Operating revenues from continuing operations
Oil and gas operations	$	~~254~~272,~~994~~038		$	~~223~~214,~~957~~620		$	875,350		$	799,339
Natural gas distribution	~~237~~48,~~685~~368			~~194~~61,~~487~~809			390,567			327,183
Total	$	~~492~~320,~~679~~406		$	~~418~~276,~~444~~429		$	1,265,917		$	1,126,522
Operating income (loss)
Operating income (loss) from continuing operations
Oil and gas operations	$	2618,~~327~~607		$	26,~~005~~913		$	181,948		$	280,897
Natural gas distribution	79(22,~~293~~544		)	78(12,~~560~~743		)	58,968			70,265
Eliminations and corporate expenses	(~~284~~115		)	(~~395~~206		)	(345		)	(857		)
Total	$	~~105~~(4,~~336~~052	)	$	~~104~~13,~~170~~964		$	240,571		$	350,305
Other income (expense)
Oil and gas operations	$	(1113,~~993~~209	)	$	(1012,~~558~~703	)	$	(38,686	)	$	(35,402	)
Natural gas distribution	(37,~~130~~973		)	(3,~~004~~274		)	1,477			(10,062		)
Eliminations and other	58175			56186			405			390
Total	$	(155,~~065~~061	)	$	(1315,~~506~~791	)	$	(36,804	)	$	(45,074	)
Income before income taxes	$	90,271		$	90,664
Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231

(in thousands)	~~March~~September 3130, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,~~100~~444,~~983~~672	$	4,975,170
Natural gas distribution	1,~~155~~127,~~950~~487		1,177,134
Eliminations and other	3642,~~245~~713		23,586
Total	$	6,~~293~~614,~~178~~872	$	6,175,890

6. STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 134,076 non-qualified option shares during the first quarter of 2013 with a grant-date fair value of $16.66.

Restricted Stock: Additionally, the Stock Incentive Plan ~~provided~~provides for the grant of restricted stock. In January 2013, 46,121 shares of restricted stock were awarded with a grant date fair value of $48.36. These awards were valued based on the quoted market price of the Company'’s common stock at the date of grant and have a three year vesting period.

Performance Share Awards: The Stock Incentive Plan also ~~provided~~provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan ~~provided~~provides that payment of earned performance share awards be made in the form of Company common stock. ~~The~~Performance ~~Company~~share ~~estimated~~awards ~~fair~~are ~~value~~valued ofin ~~performance~~a ~~share~~Monte ~~awards~~Carlo ~~based~~model onwhich ~~the~~uses ~~quoted~~historical ~~market~~volatility ~~price~~and ofother ~~the~~variables ~~Company's~~to ~~common~~estimate ~~stock~~the ~~and~~probability ~~adjusted~~of ~~each~~satisfying ~~period~~the ~~for~~market ~~the~~condition ~~expected~~of ~~payout~~the ~~ratio~~award. The Company granted 84,311 performance share awards during the first quarter of 2013 with a two year vesting period and a grant-date fair value of $59.19. The Company also

1920

granted 80,395 performance share awards during the first quarter of 2013 with a three year award period and a grant-date fair value of $60.81.

~~2004~~ Stock Appreciation Rights Plan

The Energen ~~2004~~ Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $2039.0510 as of ~~March~~September 3130, 2013.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the ~~three~~first ~~months~~quarter ~~ended~~of ~~March 31,~~ 2013, Energen Resources awarded 33,796 Petrotech units, ~~none of which included a market condition,~~ with a fair value of $5075.4567 as of ~~March~~September 3130, 2013, none of which included a market condition. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $70133.3958 as of ~~March~~September 3130, 2013. These awards have a three-year vesting period. During the third quarter of 2013, Energen Resources awarded 5,854 Petrotech units with a three-year vesting period and a fair value of $75.67 as of September 30, 2013, and 2,952 Petrotech units with a seventeen-month vesting period and a fair value of $75.88 as of September 30, 2013, none of which included a market condition.

Stock Repurchase Program

During the three months and nine months ended ~~March~~September 3130, 2013, the Company had noncash purchases of approximately $710.8 million and $0.9 million,~~000~~ respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

7. EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:

	Three months endedMarch 31,
	Three months endedSeptember 30,						Nine months endedSeptember 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	10,806		$	7,895
Interest cost	2,~~718~~725			2,700			8,161			8,101
Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
Actuarial loss	3,~~690~~597			2,099			10,962			6,297
Prior service cost amortization	~~122~~123			129			367			388
Settlement charge	~~144~~17			—			161			—
Net periodic expense	$	6,~~563~~351		$	3,997		$	19,318		$	11,992

There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are ~~currently~~ expected to be made to the pension plans byduring 2013. During 2014, the Company ~~during~~may ~~2013~~make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months and nine months ending ~~March~~September 3130, 2013, the Company made benefit payments aggregating $0.92 million and $1.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $~~2.9~~36,000 ~~million~~ through the remainder of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco.

2021

The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:

	Three months endedMarch 31,
	Three months endedSeptember 30,						Nine months endedSeptember 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	1,333		$	1,390
Interest cost	869			1,062			2,605			3,186
Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
Actuarial loss	—			9			—			27
Transition amortization	324			479			973			1,438
Net periodic expense	$	395		$	904		$	1,184		$	2,713

For the three months and nine months ended ~~March~~September 3130, 2013, the Company made contributions aggregating $0.54 million and $1.2 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $10.14 million to the postretirement benefit plans through the remainder of 2013.

8. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 297.65 million barrels of oil equivalent (MMBOE) through ~~November~~September ~~2021~~2017.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources'’ total resulting exposure could be as much as $1914 million depending on the contractor'’s ability to remarket the drilling rig.

Certain of Alagasco'’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $94185 million through September 2024. During both the ~~three~~nine months ending ~~March~~September 3130, 2013 and 2012, Alagasco recognized approximately $1436.48 million ~~and $14.3 million, respectively,~~ of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately ~~158~~146 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers'’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At ~~March~~September 3130, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through ~~January~~October 2014 and an aggregate purchase price of $10.18 million with a market value of $10.28 million.

~~Legal~~Income ~~Matters~~Taxes: The ~~Energen~~Company ~~and~~uses ~~its~~the ~~affiliates~~liability ~~are,~~method ~~from~~of ~~time~~accounting tofor ~~time,~~income ~~parties~~taxes. toUnder ~~various~~this ~~pending~~method, ora ~~threatened~~deferred ~~legal~~tax ~~proceedings.~~asset ~~Certain~~or ofliability ~~these~~is ~~lawsuits~~recognized ~~include~~for ~~claims~~the ~~for~~estimated ~~punitive~~future ~~damages~~tax ineffects ~~addition~~attributable to ~~other~~temporary ~~specified~~differences ~~relief.~~between ~~Based~~the ~~upon~~financial ~~information~~statement ~~presently~~basis ~~available~~ and inthe ~~light~~tax basis of ~~available~~assets ~~legal~~ and ~~other defenses, contingent~~ liabilities ~~arising~~as ~~from~~well ~~threatened~~as ~~and~~tax ~~pending~~credit ~~litigation~~carryforwards. In ~~are~~accordance ~~not~~with ~~considered~~Accounting ~~material~~Standards inCodification ~~relation~~740-30-25-7, to the ~~respective~~Company ~~financial~~has ~~positions~~not ofrecognized ~~Energen~~a ~~and~~deferred ~~its~~tax ~~affiliates.~~liability Itfor ~~should~~the bedifference ~~noted,~~between ~~however,~~the ~~that~~book ~~Energen~~basis and ~~its~~the ~~affiliates~~tax ~~conduct~~basis ~~business~~ in ~~jurisdictions~~the instock ~~which~~of ~~the~~its ~~magnitude~~subsidiaries. The ~~and~~unrecorded ~~frequency~~gross ofoutside ~~punitive~~basis ~~and~~difference ~~other~~for ~~damage~~Alagasco ~~awards~~exceeds ~~may~~the ~~bear~~recorded ~~little~~inside orasset nobasis ~~relation~~difference toby ~~culpability~~approximately or$35 ~~actual~~million ~~damages,~~and ~~thus~~would ~~making~~result itin ~~difficult~~an toadditional ~~predict~~deferred ~~litigation~~tax ~~results~~liability of $13 million.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered

material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

21Energen Resources previously disclosed an adverse judgment relating to the ownership of the company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases. The Summary Judgment Order has been appealed by the other party.

OnEnvironmental ~~November~~Matters: 2,Various ~~2011,~~environmental ~~Energen~~laws ~~Resources~~and ~~spudded~~regulations ~~the~~apply ~~Cadenhead~~to ~~25-1 Well (~~the ~~Cadenhead~~operations ~~Well)~~of ~~in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified~~ Energen Resources ~~that~~and ~~it believed it was the owner of the lease from which the Cadenhead Well was producing~~Alagasco. ~~Shortly~~ ~~thereafter~~Historically, ~~Energen Resources filed a declaratory judgment action in~~ the ~~District~~cost ~~Court~~ of ~~Ward~~environmental ~~County,~~compliance ~~Texas to resolve the title dispute. Energen Resources~~ has anot ~~fifty~~materially ~~percent~~affected ~~working interest in~~ the ~~Cadenhead~~Company’s ~~Well. The~~financial ~~Cadenhead~~position, ~~Well~~results ~~produced~~of ~~approximately~~operations 63or ~~net~~cash ~~MBOE in 2012 and is expected to produce approximately 34 net MBOE in 2013~~flows. New Onregulations, ~~January~~enforcement 18policies, ~~2013,~~claims afor ~~judgment~~damages ~~was~~or ~~entered~~other ~~which~~events ~~was~~could ~~adverse~~result toin ~~Energen~~significant ~~Resources'~~unanticipated ~~claim of ownership~~costs. ~~The~~ ~~Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.~~

~~Environmental~~Under ~~Matters:~~oversight ~~Various~~of ~~environmental~~the ~~laws~~Site ~~and~~Remediation ~~regulations~~Section ~~apply~~of to the ~~operations~~Railroad Commission of ~~Energen~~Texas, ~~Resources~~the ~~and~~Company ~~Alagasco.~~is ~~Historically,~~currently in the ~~cost~~process of ~~environmental~~cleanup ~~compliance~~and ~~has~~remediation ~~not~~of ~~materially~~oil ~~affected~~and ~~the~~gas ~~Company's~~wastes ~~financial~~in ~~position,~~nine ~~results~~reserve ofpits ~~operations~~in orMitchell ~~cash~~County, ~~flows~~Texas. ~~New~~ ~~regulations,~~The ~~enforcement~~Company ~~policies~~estimates that the cleanup, ~~claims~~remediation ~~for~~and ~~damages~~related orcosts ~~other~~will ~~events~~approximate ~~could~~$1.8 ~~result~~million inof ~~significant~~which ~~unanticipated~~$1.6 ~~costs~~million has been incurred and $0.2 million has been reserved.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco'’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States Environmental Protection Agency (EPA), Alagasco and the current site owner. In ~~May~~ 2012, Alagasco ~~received~~responded ~~from~~to ~~the~~an EPA a Request for Information Pursuant to Section 104 of CERCLA relating to the EPA'’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in ~~and around~~ Birmingham, Jefferson County, Alabama. The ~~inquiry~~Request ~~requests~~related ~~information~~to ~~about~~a former site of a ~~parcel~~manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue ~~site~~Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The ~~parcel~~letter isidentifies Alagasco as a potentially responsible party (PRP) under CERCLA for the ~~former~~cleanup ~~site~~of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has requested additional information from EPA regarding its designation as a ~~manufactured~~PRP, ~~gas~~and ~~distribution~~an ~~facility~~opportunity to discuss this designation further with EPA. Alagasco ~~has~~is ~~responded~~unable to determine the ~~inquiry~~extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company'’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department'’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of ~~March~~September 3130, 2013.

9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen'’s long-term debt, including the current portion, ~~approximates~~was approximately $1,~~216~~188.92 million and $1,255.8 million and ~~has~~both had a carrying value of $1,154.0 million ~~and $1,154.0 million~~ at ~~March~~September 3130, 2013 and December 31, 2012, respectively. The fair value of Alagasco'’s fixed-rate long-term debt, including the current portion, ~~approximates~~was approximately $~~271~~262.38 million and $284.7 million and ~~has~~both had a carrying value of $250.0 million ~~and $250.0 million~~ at ~~March~~September 3130, 2013 and December 31, 2012, respectively. The fair values ~~were~~are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company'’s interest rate swap was a $2.91 million and a $3.3 million liability at ~~March~~September 3130, 2013 and December 31, 2012, respectively, and is classified as Level 2 fair value liability. The fair value of the Company'’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

22Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.8 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. Uncollected finance receivables are written off approximately 15 months after the account has been final billed. Alagasco had finance receivables past due 90 days or more of $0.7 million and $0.5 million as of September 30, 2013 and December 31, 2012, respectively.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At March 31, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.4 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.6 million and $0.5 million as of March 31, 2013 and December 31, 2012, respectively.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2012	$	470
Provision	~~116~~191
Allowance for credit losses as of March 31, 2013	$	586
Allowance for credit losses as of September 30, 2013	$	661

10. REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the balance sheets:

(in thousands)	~~March~~September 3130, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	253	$	89,316	$	170	$	90,708
Pension assets	$	263	$	69,249	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		1617,~~884~~579		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,~~802~~176		—		3,322
Gas supply adjustment	2310,~~857~~925		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	2411,~~135~~213	$	~~109~~89,~~002~~004	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	26,~~262~~573	$	—	$	1,740	$	—
Unbilled service margin	226,~~108~~351		—		25,078		—
Postretirement liabilities	—		113,~~487~~951		—		1,237
Refundable negative salvage	1716,~~483~~321		4140,~~352~~946		18,265		53,467
Asset retirement obligation	—		25,211		—		24,930
Gain on sale of property	10,890		—		—		—
Other	33		762		33		770
Asset retirement obligation	—		25,772		—		24,930
Total regulatory liabilities	$	41,886	$	68,812	$	45,116	$	80,404
Other	33		745		33		770
Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

11. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

During the ~~three~~nine months ended ~~March~~September 3130, 2013, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	~~901~~2,466
Liabilities settled	(~~322~~542		)
Accretion expense	1,997
Accretion expense (including discontinued operations of $944)	6,131
Balance as of March 31, 2013	$	120,599
Reclassification associated with held for sale properties*	(19,474		)
Balance as of September 30, 2013	$	106,604

~~The~~* ~~Company~~Asset ~~recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset~~ retirement ~~activity~~obligation ~~exists.~~associated ~~Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance~~ with ~~rates~~Black ~~approved~~Warrior byBasin ~~the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $25.2 million~~ and ~~$24.9~~North ~~million~~Louisiana/East toTexas ~~purge~~properties ~~and~~are ~~cap~~included ~~its gas pipelines upon abandonment~~ as aliabilities ~~regulatory~~related ~~liability~~to ~~as of March 31, 2013 and December 31, 2012, respectively. Regulatory~~ assets held for ~~accumulated~~sale ~~asset removal costs of $2.8 million and $3.3 million as of March 31, 2013 and December 31, 2012, are included as regulatory assets~~ in ~~noncurrent~~current ~~assets~~liabilities on the balance ~~sheets~~sheet. ~~The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.~~

12The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $25.8 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2013 and December 31, 2012, respectively. ~~ACQUISITION~~Regulatory ~~AND~~assets ~~DISPOSITION~~for OFrate ~~PROPERTIES~~recovery of accumulated asset removal costs of $2.2 million and $3.3 million as of September 30, 2013 and December 31, 2012, are

During the first quarter of 2013, Alagasco entered into a purchase and sale agreement to sell its Birmingham Metro Operations Center which is located on 11.7 acres in downtown Birmingham and has been in service since the 1940's. The sales price is approximately $14 million and the sale is expected to close in August of 2013. Effective upon closing, Alagasco plans to lease the facility from the purchaser for a period of approximately 18 months. 25

~~During~~included ~~the~~as ~~first~~regulatory ~~quarter~~assets ofin ~~2012,~~noncurrent ~~Energen~~assets ~~Resources recognized a noncash impairment writedown~~ on ~~certain properties in East Texas of $21.5 million pre-tax to adjust~~ the ~~carrying~~balance ~~amount of these properties to their fair value based on expected future discounted cash flows~~sheets. ~~Significant~~The ~~assumptions in valuing the proved reserves included the reserve quantities, anticipated operating~~ costs, ~~anticipated~~associated ~~production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate~~ with ~~the~~asset ~~risk~~retirement ofobligations ~~the~~are ~~underlying~~either ~~cash~~currently ~~flow~~being ~~estimates.~~recovered ~~The~~in ~~impairment~~rates ~~was~~or ~~caused~~are byprobable ~~the impact~~ of ~~lower~~recovery ~~future~~in ~~natural gas prices. During the first quarter of 2012,~~ future ~~natural gas price curves shifted significantly lower, especially in the next 5 years~~rates. ~~This nonrecurring impairment writedown is classified as Level 3 fair value.~~

2412. DISPOSITION OF PROPERTIES

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million on the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. The gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. Based upon the November 5, 2013 review by the APSC, Alagasco will recognize the deferred revenues from the sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(2610,~~818~~924		)	—4,157			(266,~~818~~767		)
Amounts reclassified from accumulated other comprehensive income (loss)	(1017,~~454~~907		)	14,~~808~~721			(813,~~646~~186		)
Change in accumulated other comprehensive income (loss)	(3728,~~272~~831		)	18,~~808~~878			(3519,~~464~~953		)
Balance as of March 31, 2013	$	6,924		$	(50,699	)	$	(43,775	)
Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).

	Three months ended			Nine months ended
	March 31, 2013
	September 30, 2013			September 30, 2013
(in thousands)	Amounts Reclassified			~~Line Item Where Presented~~			Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	178,~~290~~433		~~Operating revenues~~$	30,226		Operating revenues
Interest rate swap	(~~409~~446		)	~~Interest expense~~(1,282		)	Interest expense
Total cash flow hedges	167,~~881~~987			28,944
Income tax expense	(63,~~427~~048		)	(11,037		)
Net of tax	104,~~454~~939			17,907
Pension and postretirement plans:
Transition obligation	(74		)	~~Operations and maintenance~~(220		)	Operations and maintenance
Prior service cost	(78		)	~~Operations and maintenance~~(235		)	Operations and maintenance
Actuarial losses*	(2,~~254~~036		)	~~Operations and maintenance~~(6,387		)	Operations and maintenance
Actuarial losses on settlement charges*	(~~375~~46		)	~~Regulatory asset~~(421		)	Regulatory asset
Total pension and postretirment plans	(2,781		)
Total pension and postretirement plans	(2,234		)	(7,263		)
Income tax expense	~~973~~783			2,542
Net of tax	(1,~~808~~451		)	(4,721		)
Total reclassifications for the period	$	83,~~646~~488		$	13,186

* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

2526

14. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

2615. DISCONTINUED OPERATIONS

~~ITEM~~In 2October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). ~~MANAGEMENT'S~~The ~~DISCUSSION~~Company ~~AND~~will ~~ANALYSIS~~record OFa ~~FINANCIAL~~pre-tax ~~CONDITION~~gain ~~AND~~on ~~RESULTS~~the OFsale ~~OPERATIONS~~of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013 and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months and nine months ended September 30, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.

The following table details held-for-sale properties by major classes of assets and liabilities:



(in thousands)	September 30, 2013
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	3,704		$	1,418		$	5,122
Inventories	1,078			63			1,141
Oil and gas properties	304,012			348,380			652,392
Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
Other property, net	1,970			183			2,153
Total assets held-for-sale	127,753			56,109			183,862
Accounts payable	(1,713		)	(2		)	(1,715		)
Royalty payable	(792		)	(936		)	(1,728		)
Other current liabilities	(358		)	(35		)	(393		)
Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
Total held-for-sale properties	$	119,513		$	40,404		$	159,917

During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations in the nine months ended September 30, 2012. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.



	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)	2013			2012		2013			2012

Oil and gas revenues	$	18,258		$	18,895	$	55,483		$	57,601
Pretax income (loss) from discontinued operations	$	2,971		$	5,526	$	9,980		$	(6,028	)
Income tax expense (benefit)	1,105			1,975		3,711			(2,044		)
Income (Loss) From Discontinued Operations	$	1,866		$	3,551	$	6,269		$	(3,984	)
Loss on disposal of discontinued operations	$	(24,612	)	$	—	$	(24,612	)	$	—
Income tax benefit	(8,934		)	—		(8,934		)	—
Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—	$	(15,678	)	$	—
Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551	$	(9,409	)	$	(3,984	)
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.05	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.05	)
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.06	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.06	)

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Energen's had a net ~~income~~loss ~~totaled~~totaling $5619.73 million ($0.7827 per diluted share) for the three months ended ~~March~~September 3130, 2013 compared with net income of $572.40 million ($0.7903 per diluted share) for the same period in the prior year. In the third quarter of 2013, Energen’s loss from continuing operations totaled $5.5 million ($0.08 per diluted share) and compared with loss from continuing operations of $1.5 million ($0.02 per diluted share) in the same period a year ago. Loss from discontinued operations for the current-quarter period was $13.8 million as compared with income of $3.6 million from the prior-year third quarter. Energen Resources Corporation, Energen'’s oil and gas subsidiary, had a net ~~income~~loss for the three months ended ~~March~~September 3130, 2013, of $810.82 million as compared with a net gain of $912.54 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of $3.6 million in the current quarter as compared with $8.8 million in the same quarter last year. This decrease in net income from continuing operations was primarily the result of ~~increased~~higher ~~lease~~depreciation, ~~operating~~depletion ~~expense~~and ~~excluding~~amortization ~~production~~(DD&A) ~~taxes~~expense (approximately $1624 million after-tax), ~~higher~~increased ~~depreciation,~~lease ~~depletion~~operating ~~and~~expense ~~amortization~~excluding ~~(DD&A)~~production ~~expense~~taxes (approximately $137 million after-tax), higher administrative expense (approximately $47 million after-tax), ~~lower~~increased ~~natural gas~~ production ~~volumes~~taxes (approximately $43 million after-tax), decreased natural gas liquids commodity prices (approximately $21 million after-tax), and a year-over-year after-tax $~~0.7~~10 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $2639.7 million non-cash mark-to-market loss on derivatives for the ~~first~~third quarter of 2013 and an after-tax $2529.37 million non-cash mark-to-market loss on derivatives for the ~~first~~third quarter of 2012). Positively affecting net income was the impact of higher natural gas, oil and natural gas liquids production volumes (approximately $2031 million after-tax), and increased natural gas and oil commodity prices (approximately $416 million after-tax) ~~and a noncash impairment in the first quarter of 2012 on certain natural gas properties in East Texas of approximately $13~~.4 ~~million after-tax.~~ Energen'’s natural gas utility, Alagasco, reported a net ~~income~~loss of $479.20 million in the ~~first~~third quarter of 2013 compared to net ~~income~~loss of $4610.90 million in the same period last year. This increase primarily reflects the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support systems devoted to public service.

For the 2013 year-to-date, Energen’s net income totaled $120.5 million ($1.67 per diluted share) compared to net income of $190.7 million ($2.64 per diluted share) for the same period in the prior year. For the nine months ended September 30, 2013, Energen’s income from continuing operations totaled $129.9 million ($1.80 per diluted share) and compared with income from continuing operations of $194.7 million ($2.69 per diluted share) in the same period a year ago. Discontinued operations generated a loss for the current year-to-date period of $9.4 million as compared with a loss of $4.0 million from the same period a year ago. Energen Resources generated net income for the nine months ended September 30, 2013, of $82.4 million as compared with income of $153.6 million in the previous period. Energen Resources generated net income from continuing operations of $91.7 million in the current year-to-date as compared with income of $157.4 million in the same period last year. Higher DD&A expense (approximately $55 million after-tax), increased lease operating expense excluding production taxes (approximately $33 million after-tax), higher administrative expense (approximately $16 million after-tax), increased production taxes (approximately $6 million after-tax), decreased natural gas liquids commodity prices (approximately $4 million after-tax), increased interest expense (approximately $2 million after-tax), lower natural gas production volumes (approximately $1 million after-tax) and a year-over-year after-tax $52.7 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.7 million non-cash mark-to-market loss on derivatives for the nine months ended September 30, 2013 and an after-tax $22 million non-cash mark-to-market gain on derivatives for the nine months ended September 30, 2012) were partially offset by increased oil and natural gas liquids production volumes (approximately $77 million after-tax) and higher natural gas and oil commodity prices (approximately $29 million after-tax). Alagasco’s net income of $37.6 million in the current year-to-date compared to net income of $37.2 million in the same period in the previous year.

Oil and Gas Operations

Revenues from continuing oil and gas operations rose 1326.98 percent to $~~255~~272.0 million for the three months ended ~~March 31~~September 30, 2013 largely as a result of higher production volumes and increased realized natural gas and oil commodity prices partially offset by the non-cash mark-to-market decrease in derivatives combined with decreased realized natural gas liquids commodity prices. Revenues from continuing oil and gas operations rose 9.5 percent to $875.4 million for the nine months ended September 30, 2013 primarily as a result of significantly increased oil and natural gas liquids production volumes ~~combined~~along with increased realized natural gas and oil commodity prices partially offset by lower natural gas production volumes, ~~and~~ decreased realized natural gas liquids commodity prices and the non-cash mark-to-market decrease in derivatives. During the current quarter, revenue per unit of production for natural gas increased 810.49 percent to $4.2706 per thousand cubic feet (Mcf), while oil revenue per unit of production rose ~~slightly~~8.3 percent to $8589.6667 per barrel. Natural gas liquids revenue per unit of production fell 113.8 percent to an average price of $0.75 per gallon. In the year-to-date, revenue per unit of production for natural gas rose 13.7 percent to $4.14 per Mcf, oil revenue per unit of production increased 3.7 percent to $87.59 per barrel and natural gas liquids revenue per unit of production fell 7.5 percent to an average price of $0.7774 per gallon. Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the non-cash mark-to-market hedges.

Production for the current quarter increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties offset by normal production declines. Natural gas production in the first quarter declined 7.4 percent to 17.7 billion cubic feet (Bcf), oil volumes increased 18.6 percent to 2,317 thousand barrels (MBbl) and natural gas liquids production rose 6.2 percent to 27.6 million gallons (MMgal). Oil and natural gas liquids comprised approximately 50 percent of Energen Resources' production for the current quarter.30

~~Energen~~Production ~~Resources~~from ~~may,~~continuing inoperations for the ~~ordinary~~current ~~course~~quarter ofand ~~business,~~year-to-date beincreased ~~involved~~largely indue ~~the~~to ~~sale~~higher ofvolumes ~~developed~~related orto ~~undeveloped~~increased field development in certain Permian Basin liquids-rich properties. ~~The~~offset ~~Company~~by ~~includes~~normal ~~gains~~production ~~and~~declines. ~~losses~~Natural ongas production in the ~~disposition~~third ofquarter ~~these~~rose ~~assets~~1.7 inpercent ~~operating~~to ~~revenues~~14.9 ~~Energen~~billion ~~Resources~~cubic ~~recorded~~feet a(Bcf), ~~pre-tax~~oil ~~gain~~volumes ofincreased $021.5 percent to 2,764 thousand barrels (MBbl) and natural gas liquids production rose 45.6 percent to 36.7 million ingallons (MMgal). For the ~~first~~year-to-date, ~~quarter~~natural ofgas ~~2013~~production ~~from~~declined ~~the~~1.5 ~~sale~~percent ofto ~~various~~43.4 ~~Permian~~Bcf, ~~Basin~~while ~~properties~~oil volumes rose 19.6 percent to 7,670 MBbl. Natural gas liquids production increased 24.7 percent to 98.5 MMgal. Oil and natural gas liquids comprised approximately 59 percent and 58 percent of Energen Resources’ ~~recorded~~production nofrom ~~property~~continuing ~~sales~~operations infor the ~~first~~current quarter ofand ~~2012.~~year-to-date, respectively.

~~Operations~~Energen ~~and~~Resources ~~maintenance~~may, ~~(O&M)~~in ~~expense~~the ~~increased~~ordinary ~~$31.4~~course ~~million~~of ~~for~~business, be involved in the ~~quarter~~sale of developed or undeveloped properties. ~~Lease~~With ~~operating~~respect ~~expense~~to ~~(excluding~~developed ~~production~~properties, ~~taxes)~~sales ~~generally~~may ~~reflects~~occur ~~year~~as ~~over~~a ~~year~~result ~~increases~~of, inbut ~~the~~not ~~number~~limited to, disposing of ~~active~~non-strategic ~~wells~~or ~~resulting~~marginal ~~from~~assets and accepting offers where the buyer gives greater value to a property than does Energen Resources'. ~~ongoing~~The ~~development,~~Company ~~exploratory~~reflects gains and ~~acquisition~~losses ~~activities.~~on ~~Lease~~the ~~operating~~disposition ~~expense~~of ~~(excluding~~these ~~production~~assets, ~~taxes)~~the ~~increased~~writedown ~~$24.9~~of ~~million~~certain properties held-for-sale, and income or loss from the ~~quarter~~operations ~~largely~~of ~~due~~the toassociated ~~additional~~held-for-sale ~~workover~~properties ~~and~~as ~~repair~~discontinued ~~expense~~operations ~~(approximately~~for ~~$10.7~~those ~~million),~~sales ~~increased~~that ~~water~~qualify ~~disposal~~for ~~costs~~such ~~(approximately~~reporting $3under generally accepted accounting standards.5 ~~million),~~During ~~higher~~the adthree ~~valorem~~months ~~taxes~~and ~~(approximately~~nine ~~$3.5~~months ~~million)~~ended September 30, ~~additional~~2013, ~~equipment~~Energen ~~rental~~Resources ~~expense(approximately~~recorded ~~$3.4~~in ~~million),~~loss ~~increased~~on ~~gathering~~disposal ~~costs~~of ~~(approximately~~discontinued operations a non-cash impairment writedown of $124.36 million) ~~and~~pre-tax ~~increased~~on ~~chemical~~certain natural gas and ~~treatment~~oil ~~costs~~assets ~~(approximately~~located ~~$1.1~~in ~~million)~~North Louisiana/East Texas. Energen OnResources ahad ~~per~~no ~~unit~~disposal ~~basis,~~of ~~the~~discontinued ~~average~~operations ~~lease~~during ~~operating~~the ~~expense~~third ~~(excluding~~quarter ~~production~~of ~~taxes)~~2012 ~~for~~or the ~~current~~year-to-date ~~quarter~~ended ~~was~~September ~~$13~~30, 2012.77 ~~per~~The ~~barrel~~Company ofincludes ~~oil~~gains ~~equivalent~~and ~~(BOE)~~losses ason ~~compared~~the todisposition ~~$9.84~~of ~~per~~assets ~~BOE~~that indo ~~the~~not ~~same~~qualify ~~period~~as adiscontinued ~~year~~operations ~~ago~~in operating revenues. ~~Administrative~~Energen ~~expense~~Resources ~~increased~~recorded ~~$6.8~~a ~~million~~pre-tax ~~for~~loss ~~the~~of ~~three~~$37,000 ~~months~~in ~~ended~~the ~~March 31,~~third ~~2013~~quarter ~~largely~~of ~~due~~2013 toand ~~higher~~a ~~labor~~pre-tax ~~costs~~gain ~~(approximately~~of $20.91 million) ~~and~~in ~~increased~~the ~~costs~~year-to-date from the ~~Company’s~~sale ~~benefit~~of ~~and~~various ~~performance-based~~Permian ~~compensation~~Basin ~~plans~~properties. ~~(approximately~~Energen ~~$2.6~~Resources ~~million).~~recorded ~~Exploration~~a ~~expense~~pre-tax ~~fell~~gain of $0.31 million in the ~~first~~third quarter of ~~2013~~2012 and a pre-tax gain of $0. 2 million year-to-date from the sale of various properties.

Operations and maintenance (O&M) expense increased $21.2 million for the quarter and $77.1 million for the year-to-date. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting from Energen Resources'’ ~~DD&A~~ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) increased $11.7 million for the quarter largely due to additional workover and repair expense (approximately $5.5 million), higher water disposal costs (approximately $1.9 million), increased gathering costs (approximately $201.6 million), increased marketing and transportation costs (approximately $1.5 million), ~~excluding~~higher ~~the~~electrical ~~prior~~costs (approximately $0.9 million) and additional equipment rental expense (approximately $0.9 million) partially offset by lower ad valorem taxes (approximately $2 million). In the year-to-date, ~~impairment~~lease ~~writedown~~operating onexpense ~~certain~~(excluding ~~properties~~production intaxes) ~~East~~increased ~~Texas~~$51.4 ofmillion primarily due to increased workover and repair expense (approximately $21.5 million), ~~pre-tax~~additional toequipment ~~adjust~~rental ~~the~~expense ~~carrying~~(approximately ~~amount~~$5.3 ofmillion), ~~certain~~higher ~~properties~~water todisposal ~~their~~costs ~~fair~~(approximately ~~value~~$5.3 ~~based~~million), onincreased ~~expected~~gathering ~~future~~costs ~~discounted~~(approximately ~~cash~~$3.8 ~~flows~~million), higher marketing and transportation costs (approximately $2.9 ~~The~~million), increased ad valorem taxes (approximately $2.9 million), higher electrical costs (approximately $2.8 million), increased chemical and treatment costs (approximately $2.5 million) and increased environmental compliance costs (approximately $2.3 million). On a per unit basis, the average ~~depletion~~lease ~~rate~~operating expense (excluding production taxes) for the current quarter was $1711.4630 per barrel of oil equivalent (BOE) as compared to $10.81 per BOE in the same period a year ago. For the nine months ended September 30, 2013, the average lease operating expense (excluding production taxes) was $12.20 per BOE as compared to $10.17 per BOE in the previous period. Administrative expense increased $11.2 million for the three months ended September 30, 2013 largely due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $7.2 million), higher labor costs (approximately $2.2 million) and increased legal expenses (approximately $1.7 million). For the nine months ended September 30, 2013, administrative expense rose $25.2 million primarily due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $15.1 million), higher labor costs (approximately $7.2 million) and increased legal expenses (approximately $2 million). Exploration expense decreased $1.7 million in the third quarter of 2013 and rose $0.5 million year-to-date.

Energen Resources’ DD&A expense for the quarter rose $39 million. For the year-to-date, Energen Resources’ DD&A expense increased $87.8 million. The average depletion rate for the current quarter was $20.27 per BOE as compared to $16.03 per BOE in the same period a year ago. For the nine months ended September 30, 2013, the average depletion rate was $19.10 per BOE as compared to $15.49 per BOE, excluding the asset impairment, in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $25.9 million and $62.2 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and the impact from downward reserve revisions related to natural gas reserves at year-end. Higher production volumes contributed approximately $12.9 million and $25 million to the increase in DD&A expense for the quarter and year-to-date, respectively.

Energen Resources’ expense for taxes other than income taxes was $145.443 ~~per~~million ~~BOE,~~and ~~excluding~~$9.5 million higher in the ~~asset~~three ~~impairment~~months and nine months ended September 30, in2013, ~~the~~respectively, ~~same~~largely ~~period~~due ato ~~year~~production-related ~~ago~~taxes. ~~The~~In ~~increase~~the inquarter, ~~the~~higher ~~current~~natural ~~quarter~~gas ~~per~~and ~~unit~~oil ~~DD&A~~commodity ~~rate,~~market ~~which~~prices contributed approximately $173.94 million to the increase in ~~DD&A~~production-related ~~expense,~~taxes ~~was~~and ~~largely~~higher ~~due~~oil toand ~~higher~~natural ~~rates~~gas ~~resulting~~liquids ~~from~~commodity anproduction ~~increase~~volumes incontributed ~~development~~approximately ~~costs~~$2 million to the increase. ~~Higher~~In ~~production~~the ~~volumes~~year-to-date, higher net commodity market prices contributed approximately $25.46 million to the increase in ~~DD&A~~production-related ~~expense~~taxes ~~for~~and ~~the~~higher ~~quarter.~~commodity

~~Energen Resources' expense for taxes other than income taxes was $0.2 million higher in the three months ended March~~ 31, 2013 largely due to production-related taxes. Higher oil and natural gas liquids commodity production volumes contributed approximately $0.4 million to the increase in production-related taxes partially offset by a decrease of approximately $0.2 million primarily due to lower net commodity market prices. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

production volumes contributed approximately $4.1 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues ~~increased~~decreased $4313.24 million for the quarter largely due to ~~higher~~adjustments from the utility’s rate setting mechanisms combined with a decrease in customer usage partially offset by a decrease in the pass-through of gas costs. During the third quarter of 2013, Alagasco had a net $4.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and annine ~~increase~~months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the third quarter of 2012, Alagasco had a net $1.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the third quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes rose slightly while commercial and industrial customer sales volumes rose 2.1 percent. Transportation volumes fell slightly in period comparisons. Revenues for the year-to-date rose $63.4 million primarily due to the pass-through of gas costs along with additional customer usage partially offset by adjustments from the utility’s rate setting mechanisms. During the ~~first~~year-to-date ~~quarter of~~ 2013, Alagasco had a net $210.46 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. ~~For~~In the ~~quarter~~2012 year-to-date, ~~weather~~Alagasco had a net reduction in revenues of $6.3 million pre-tax to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current year-to-date, that was 2848.71 percent colder ~~than~~compared inwith the same ~~quarter~~period in the prior year contributed to a 2632.6 percent increase in residential sales volumes and a 2221.21 percent rise in commercial and industrial customer sales volumes. Transportation volumes ~~increased~~decreased ~~6.3~~slightly ~~percent~~ in period comparisons. ~~Higher~~Decreased gas purchase volumes partially offset by higher gas costs ~~combined~~resulted ~~with~~in ana 2.3 percent decrease in cost of gas for the quarter. For the year-to-date a significant increase in gas costs combined with higher gas purchase volumes resulted in a 6073.26 percent increase in cost of gas ~~for the quarter~~. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco'’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco'’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense ~~rose~~declined 119.6 percent in the current quarter primarily due to ~~higher~~lower ~~labor-related~~distribution operation expenses (approximately $0.5 million) and decreased consulting and technology costs (approximately $10.95 million). In the nine months ended September 30, ~~additional~~2013, ~~distribution~~O&M ~~operation~~expense ~~expenses~~increased slightly largely due to increased labor-related costs (approximately $13 million), and higher bad debt expense (approximately $0.58 million) ~~and~~partially ~~increased~~offset ~~business~~by ~~development~~decreased consulting and ~~marketing~~technology expense (approximately $1 million) and lower insurance costs (approximately $0.48 million).

A 24.76 percent increase in depreciation expense in the current quarter and a 3.5 percent increase in the year-to-date was primarily due to the extension and replacement of the utility'’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company rose $10.35 million in the ~~first~~third quarter of 2013 and $3.3 million year-to-date largely due to higher short-term borrowings. Other income for the Company increased $11.3 million for both the three months and nine months ended September 30, 2013 primarily due to the pre-tax gain of $10.9 million on the August 2013 sale of Alagasco’s Metro Operations Center. Income tax expense for the Company ~~increased~~decreased $03.3 million and $36.6 million in the current quarter and year-to-date, respectively, largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $~~261~~728.50 million as compared to $~~231~~603.01 million in the prior period. The Company’s working capital needs were influenced by accrued taxes, commodity prices and the timing of payments and recoveries, including gas supply pass-through adjustments and refundable negative salvage costs. ~~Working capital needs at Alagasco were additionally affected by higher gas costs and changes to storage gas inventory compared to the prior period.~~

The Company had a net outflow of cash from investing activities of $~~309~~968.42 million for the ~~three~~nine months ended ~~March~~September 3130, 2013 primarily due to additions of property, plant and equipment of $~~310~~983 million. Energen Resources incurred on a cash basis $~~291~~916 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $1967.01 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems.

The Company provided net cash of $58.6 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders. 32

The Company provided net cash of $242.9 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders and the issuance of common stock through the Company’s stock-based compensation plan.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2013, the Company expects its oil and gas capital spending to total approximately $1~~,015~~.1 ~~million~~billion, ~~including~~primarily ~~$795~~all ~~million~~of which is for existing properties, including exploration to date of $96321 million. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory.

segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

~~Impairment~~Discontinued Operations

~~During~~In ~~the~~October ~~first quarter of 2012~~2013, Energen Resources ~~recognized~~completed athe ~~noncash~~sale ~~impairment~~of ~~writedown~~its onBlack ~~certain~~Warrior Basin coalbed methane properties in ~~East~~Alabama ~~Texas~~for of $~~21.5~~160 million ~~pre-tax~~(subject to ~~adjust~~closing ~~the~~adjustments). ~~carrying~~The ~~amount~~Company ofwill ~~these~~record ~~properties~~a topre-tax ~~their~~gain ~~fair value based~~ on ~~expected~~the ~~future~~sale ~~discounted~~of ~~cash~~approximately ~~flows.~~$35 ~~Significant~~million ~~assumptions~~ in ~~valuing~~ the ~~proved~~fourth ~~reserves~~quarter ~~included~~of ~~the~~2013. The ~~reserve~~sale ~~quantities,~~had ~~anticipated~~an ~~operating~~effective ~~costs,~~date ~~anticipated~~of ~~production~~July ~~taxes~~1, ~~future~~2013 ~~expected natural gas prices~~ and ~~basis~~the ~~differentials,~~proceeds ~~anticipated~~from ~~production declines, and a discount rate of 10 percent commensurate with~~ the ~~risk~~sale ofwere ~~the~~used ~~underlying~~to ~~cash~~repay ~~flow~~short-term ~~estimates~~obligations. The ~~impairment~~property was ~~caused~~classified byas ~~the~~held-for ~~impact~~sale ofand ~~lower~~as ~~future~~discontinued ~~natural~~operations ~~gas~~during ~~prices. During~~ the ~~first~~third quarter of ~~2012,~~2013. ~~future~~At ~~natural~~December ~~gas~~31, ~~price curves shifted significantly lower~~2012, ~~especially~~proved inreserves ~~the~~associated ~~next~~with 5Energen’s ~~years.~~Black ~~This~~Warrior ~~nonrecurring~~Basin ~~impairment~~properties ~~writedown~~totaled is97 ~~classified~~Bcf asof ~~Level~~natural ~~3 fair value~~gas.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and as discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve-months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/ East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.

During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations for the nine months ended September 30, 2013. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) ~~and~~which isestablished ~~allowed~~the toRate ~~earn~~Stabilization aand ~~range~~Equalization of(RSE) ~~return~~rate-setting ofprocess 13in 1983.15 ~~percent~~Alagasco’s tocurrent ~~13.65~~allowed ~~percent~~range of return on average common equity ~~throughout~~is ~~the~~13.15 ~~term~~percent ofto ~~the~~13.65 ~~Rate~~percent ~~Stabilization~~through ~~and~~December ~~Equalization~~31, ~~(RSE) order~~2013. The Company’s current RSE order ~~has~~had aan original term extending through December 31, 2014. At its ~~March~~meeting ~~2013~~on ~~monthly~~November ~~meeting~~5, 2013, the APSC ~~announced~~voted ~~the~~to ~~schedule~~make ~~for~~certain aRSE ~~series~~modifications ofeffective ~~public~~January ~~informal~~1, ~~proceedings~~2014, towhich ~~review~~are ~~the~~described ~~Company’s~~as ~~RSE mechanism~~follows. The ~~Company~~term ~~expects~~of ~~discussion~~the ~~topics~~order tois ~~include~~extended through September 30, 2018. Alagasco’s allowed range of return on average common equity ~~and~~will ~~the~~be ~~term~~10.5 ~~length~~percent ofto ~~renewals~~10.95 ~~The~~percent ~~public~~with ~~proceedings~~an ~~are~~adjusting ~~scheduled~~point of 10.8 percent. Alagasco is eligible to ~~occur~~receive ona ~~September~~performance based adjustment of 5, ~~September~~basis ~~25,~~points ~~October~~to 9the ~~and~~return ~~November~~on 13equity adjusting point, ~~2013.~~based ~~RSE~~on ~~limits~~meeting ~~the~~certain ~~utility’s~~customer satisfaction criteria. The equity upon which a return iswill be permitted towill 55be 56.5 percent ofwith ~~total~~Alagasco ~~capitalization,~~allowed ~~subject~~ to ~~certain~~budget ~~adjustments~~at the cap. Given existing economic conditions, Alagasco expects only modest growth in equity supporting Alagasco'’s investment in its distribution system and support systems devoted to public service as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $12.9 million, $14.2 million, $22.2 million and $2.7 million for the periods January through March 2013, January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $17.5 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $41.4 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refunds as of March 2013 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco's average customer count for 2012 declined approximately 0.6 percent from 2011 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco's average customer count include recent warmer weather trends, enhanced credit and collection efforts and the loss of customers due to a 2011 weather event. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices, weather conditions and the underlying current and future economic conditions facing the utility's customer base. During the three months ended March 31, 2013, Alagasco reduced the bad debt reserve by approximately $1.1 million primarily due to certain aged receivables transitioned to the utility's long-term collections, in addition to the impact of its collection related initiatives.33

~~Alagasco~~Refunds ~~maintains~~of annegative ~~investment~~salvage incosts ~~storage~~to ~~gas~~customers ~~that~~through islower ~~expected~~tariff torates ~~average~~were ~~approximately~~$14.5 million, $2814.2 million, in$22.2 million and $2.7 million for the periods January through September 2013, ~~but~~January ~~will~~through ~~vary~~December ~~depending~~2012, ~~upon~~January ~~the~~through ~~price~~December of2011 ~~natural~~and ~~gas.~~in ~~During~~December ~~2013~~2010, respectively. Alagasco ~~plans~~anticipates torefunding ~~invest~~approximately an$16.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $7541 million inof ~~capital~~refundable ~~expenditures~~negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the ~~normal~~Enhanced ~~needs~~Stability Reserve (ESR) and other commission-approved charges. The refunds as of ~~its~~September ~~distribution~~2013 and ~~support~~the ~~systems~~remaining ~~and~~amount ~~for~~refundable ~~technology-related~~over ~~projects~~the ~~designed~~entire nine year period are due to ~~improve~~a ~~customer~~re-estimation ~~service~~of future removal costs provided for through the prior depreciation rates. The ~~utility~~re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

29Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco’s average customer count for 2012 declined approximately 0.6 percent from 2011 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco’s average customer count include recent warmer weather trends, enhanced credit and collection efforts and the loss of customers due to a 2011 weather event. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices, weather conditions and the underlying current and future economic conditions facing the utility’s customer base. During the nine months ended September 30, 2013, Alagasco reduced the bad debt reserve by approximately $0.4 million primarily due to certain aged receivables transitioned to the utility’s long-term collections, in addition to the impact of its collection related initiatives.

Alagasco maintains an investment in storage gas that is expected to average approximately $26 million in 2013 but will vary depending upon the price of natural gas. During 2013, Alagasco plans to invest an estimated $91 million in capital expenditures for the normal needs of its distribution and support systems and for technology-related projects designed to improve customer service. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

~~During~~In ~~the~~August ~~first quarter of~~ 2013, Alagasco ~~entered~~recorded ~~into~~ a ~~purchase~~pre-tax ~~and~~gain ~~sale~~of ~~agreement~~$10.9 tomillion ~~sell~~on the sale of its ~~Birmingham~~ Metro Operations Center which is located onin 11Birmingham, Alabama.7 ~~acres~~The inCompany ~~downtown~~received ~~Birmingham~~approximately ~~and~~$13.8 ~~has~~million ~~been~~pre-tax in ~~service~~cash ~~since~~from the ~~1940's~~sale of this property. The ~~sales~~gain ~~price~~on isthe ~~approximately~~sale ~~$14~~was ~~million~~recognized in other income and ~~the~~a ~~sale~~related isreduction ~~expected~~in revenues was recognized to ~~close~~defer the gain as a regulatory liability pending review by the APSC. Based upon the November 5, 2013 review by the APSC, Alagasco will recognize the deferred revenues from the sale in ~~August~~the fourth quarter of 2013. Effective upon ~~closing,~~the ~~Alagasco~~sale ~~plans~~of tothe ~~lease~~Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 1820 months.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges typically with investment and commercial banks and energy-trading firms. At ~~March~~September 3130, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net ~~loss~~gain position with ~~six~~seven of its active counterparties and in a net ~~gain~~loss position with the remaining ~~seven~~six at ~~March~~September 3130, 2013. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average ContractPrice	Description
Natural Gas
2013	93.40	Bcf	$4.8382 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	2.5	Bcf*	$4.17 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
	1.1	Bcf*	$4.16 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	5.8	Bcf*	$4.06 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	62,~~752~~434	MBbl	$9091.9944 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	~~720~~5,760	MBbl	$9088.1085 Bbl	NYMEX Swaps
Oil Basis Differential
2013	~~2,701~~907	MBbl	$(32.0299) Bbl	WTS/WTI Basis Swaps**
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps***
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	3312.90	MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to March 31, 2013
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Realized prices are anticipated to be lower than New York Mercantile Exchange (NYMEX) prices primarily due to basis differences and other factors.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	March 31, 2013
	September 30, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,~~452~~712	)	$	2325,~~142~~005		$	1012,~~690~~293
Noncurrent assets	126,~~194~~828			145,~~005~~958			2612,~~199~~786
Current liabilities	(2440,~~834~~970		)	(79,~~965~~042		)	(3231,~~799~~928		)
Noncurrent liabilities	(52,~~626~~580		)	(21,~~723~~201		)	(81,~~349~~379		)
Net derivative asset (liability)	$	(3049,~~718~~434	)	$	2641,~~459~~206		$	(48,~~259~~228	)



	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

Level 3 assets and liabilities as of ~~March~~September 3130, 2013, represent an immaterial amount of total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $2822 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $~~5.2~~22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Energen'’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012.

Credit Facilities and Working Capital

On October 30, 2012, Energen and Alagasco entered into $1,250 million and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen obligations under the $1,250 million syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco.

31At September 30, 2013, the Company reported negative working capital of $1,008.7 million arising from current liabilities of $1,541.3 million exceeding current assets of $532.6 million. The negative working capital is primarily due to a $258 million increase in borrowings during the year-to-date 2013 and a $628 million increase in borrowings during 2012 under the syndicated unsecured credit facilities and in support of Energen’s capital projects. Generally Accepted Accounting Principles require classification as short term for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated unsecured credit facilities were entered into on October 30, 2012 and have a five-year term. In addition, Energen Resources received $160 million (subject to closing adjustments) on the sale of its Black Warrior Basin coalbed methane properties in October 2013. Accordingly, the Company believes that it has adequate financing capacity available for its expected liquidity needs.

AtWorking ~~March~~capital ~~31,~~of ~~2013,~~Energen ~~the~~is ~~Company~~also ~~reported~~influenced ~~negative~~by ~~working~~the ~~capital~~fair value of ~~$908.2~~the ~~million~~Company’s ~~arising~~derivative ~~from~~financial ~~current~~instruments ~~liabilities~~associated ofwith ~~$1,273.0~~future ~~million exceeding current assets of $364~~production.8 ~~million.~~Energen’s ~~The~~accounts ~~negative~~receivable ~~working~~and ~~capital~~accounts ispayable ~~primarily~~at ~~due~~September 30, to2013 ainclude $6912.3 million inand ~~increase~~$31.9 inmillion, ~~borrowings~~respectively, ~~during~~associated ~~the~~with ~~first~~its ~~quarter~~derivative offinancial ~~2013~~instruments. ~~and~~Working acapital ~~$628~~of ~~million~~Alagasco ~~increase~~is inadditionally ~~borrowings~~impacted ~~during~~by ~~2012~~the ~~under~~recovery ~~the~~and ~~syndicated~~pass-through ~~unsecured~~of ~~credit~~regulatory ~~facilities~~items and inthe ~~support~~seasonality of ~~Energen'~~Alagasco’s ~~capital~~business ~~projects.~~and ~~Generally~~reflects ~~Accepted~~an ~~Accounting~~expected ~~Principles~~pass-through ~~require classification as short term for obligations such as these that are subject~~ to ~~the~~rate ~~execution~~payers of ~~individual~~$16.3 ~~notes~~million ~~with~~in ~~maturity~~refundable ~~dates~~negative ~~less~~salvage ~~than~~costs ~~one~~representing ~~year.~~a ~~The~~reduction ~~syndicated~~in ~~unsecured~~future ~~credit~~revenues ~~facilities~~through ~~were~~lower ~~entered~~tariff ~~into~~rates. onEnergen ~~October 30, 2012~~ and ~~have~~Alagasco arely ~~five-year~~upon ~~term.~~cash ~~Accordingly,~~flows ~~the~~from ~~Company~~operations ~~believes~~supplemented ~~that~~by ittheir ~~has~~syndicated ~~adequate~~unsecured ~~financing~~credit ~~capacity~~facilities ~~available~~to ~~for~~fund ~~its~~working ~~expected~~capital ~~liquidity~~ needs.

Working capital of Energen is also influenced by the fair value of the Company's derivative financial instruments associated with future production. Energen's accounts receivable and accounts payable at March 31, 2013 include $10.7 million and $32.8 million, respectively, associated with its derivative financial instruments. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco's business and reflects an expected pass-through to rate payers of $17.5 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by its syndicated unsecured credit facilities to fund working capital needs.

Credit Ratings

On April 26, 2013, Moody'’s Investor Service updated its credit opinion for Energen and Alagasco confirming Energen'’s senior unsecured credit rating as investment grade with a negative outlook. Alagasco'’s senior unsecured credit rating was lowered one notch but remains investment grade with a negative outlook. Energen and Alagasco'’s debt ratings by Standard & Poor'’s are considered investment grade with a stable outlook.

Dividends

Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2012.

Other Commitments

During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004 forward. The Company preliminarily estimates that application of the Order to all of the Company'’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department'’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of ~~March~~September 3130, 2013.

On April 4, 2013, a New Mexico corporate tax bill was signed into law which gradually reduces the New Mexico state income tax rate from the current 7.6 percent to 5.9 percent over a five year period. The Company ~~will~~recognized ~~recognize~~ a $1.6 million income tax benefit during the second quarter of 2013, the period the law was enacted, to reflect the impact of this change.

Recent Accounting Standards Updates

See Note 14, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD LOOKING STATEMENTS AND RISK FACTORS

The disclosure and analysis in this report contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental and regulatory obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, acts of nature, sabotage, terrorism (including cyber-attacks) and other similar acts that disrupt operations or cause damage greater than covered by insurance, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

~~Commodity~~Except ~~prices~~as ~~for~~otherwise ~~crude oil and natural gas are volatile~~disclosed, ~~and~~the aforward-looking ~~substantial~~statements ~~reduction~~do innot ~~commodity~~reflect ~~prices could adversely affect~~ the ~~Company's~~impact ~~results and the carrying value~~ of ~~its~~possible ~~oil~~or ~~and~~pending ~~natural~~acquisitions, ~~gas~~investments, ~~properties:~~divestitures ~~The~~or ~~Company and Alagasco are significantly influenced by commodity prices~~restructurings. ~~Historical~~The ~~markets~~absence ~~for~~of ~~oil,~~errors ~~natural~~in ~~gas~~input ~~and natural gas liquids have been volatile. Energen Resources’ revenues~~data, ~~operating~~calculations ~~results, profitability~~ and ~~cash~~formulas ~~flows~~used ~~depend~~in ~~primarily upon the prices realized for its oil~~estimates, ~~gas~~assumptions and ~~natural~~forecasts ~~gas~~cannot ~~liquid~~be ~~production~~guaranteed. ~~Additionally,~~Neither ~~downward commodity price trends may impact expected cash flows from future production and potentially reduce~~ the ~~carrying value of~~ Company~~-owned~~ ~~oil~~nor ~~and~~Alagasco ~~natural~~undertakes ~~gas~~any ~~properties.~~obligation ~~Alagasco’s~~to ~~competitive~~correct ~~position~~or ~~and~~update ~~customer~~any ~~demand~~forward-looking isstatements ~~significantly~~whether ~~influenced~~as bya ~~prices~~result ~~for~~of ~~natural~~new ~~gas~~information, ~~which~~future ~~are~~events ~~passed-through~~or ~~to customers~~otherwise.

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect the Company’s results and the carrying value of its oil and natural gas properties: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for oil, natural gas and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Market conditions or a downgrade in the credit ratings of the Company or its subsidiaries could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders, the Company and its subsidiaries. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition (including by sale, spin-off or distribution) transactions involving the Company, Energen Resources or Alagasco may negatively impact market and rating agency considerations regarding the credit of the Company or its subsidiaries, and the management of the Company periodically considers these types of transactions. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs, limit availability of funds to the Company and adversely affect the price of outstanding debt securities.

Energen Resources'’ hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk: Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company'’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company'’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources'’ position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

33The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

The Company’s isoperations ~~exposed~~depend toupon ~~counterparty~~the ~~credit~~use ~~risk as a result~~ of ~~its~~third ~~concentrated~~party ~~customer~~facilities ~~base: Revenues~~ and ~~related~~an ~~accounts~~interruption ~~receivable~~of ~~from~~its ~~oil~~ability ~~and~~to ~~gas~~utilize ~~operations~~these ~~primarily~~facilities ~~are~~may ~~generated~~adversely ~~from~~affect ~~the~~its ~~sale~~financial ofcondition ~~produced~~and ~~oil,~~results ~~natural~~of ~~gas~~operations: ~~and~~Energen ~~natural~~Resources ~~gas~~delivers ~~liquids~~ to aand ~~small~~Alagasco ~~number~~is ofserved ~~energy~~by ~~marketing~~third ~~companies~~party facilities. ~~Such~~These ~~sales~~facilities ~~are~~include ~~typically~~third ~~made~~party onoil anand ~~unsecured~~gas ~~credit~~gathering, ~~basis~~transportation, ~~with~~processing ~~payment~~and ~~due~~storage ~~the month following delivery~~facilities. ~~This~~Energen ~~concentration~~Resources ofrelies ~~sales~~upon tosuch afacilities ~~limited~~for ~~number~~access ofto ~~customers~~markets infor ~~the~~its ~~energy~~production. ~~marketing~~Alagasco ~~industry~~relies ~~has~~upon ~~the~~such ~~potential~~facilities tofor ~~affect~~access ~~the Company's overall exposure~~ to ~~credit~~natural ~~risk,~~gas ~~either~~supplies. Such ~~positively~~facilities orare ~~negatively,~~typically ~~based~~limited ~~on changes~~ in ~~economic,~~number ~~industry~~and orgeographically ~~other~~concentrated. ~~conditions~~An ~~specific~~extended tointerruption aof ~~single~~access ~~customer~~to or toservice ~~the~~from ~~energy~~these ~~marketing~~facilities, ~~industry~~whether ~~generally.~~caused ~~Energen~~by ~~Resources~~weather ~~considers~~events, ~~the~~natural ~~credit~~disaster, ~~quality~~accident, ofmechanical ~~its customers and~~failure, incriminal ~~certain~~act ~~instances,~~or ~~may~~otherwise ~~require~~could ~~credit~~result ~~assurances~~in ~~such~~material asadverse afinancial ~~deposit,~~consequences ~~letter~~to ofEnergen ~~credit~~Resources, orAlagasco ~~parent~~and ~~guarantee.~~the Company.

The Company'’s ~~operations~~oil ~~depend~~and ~~upon~~natural ~~the~~gas ~~use~~reserves ofare ~~third~~estimates, ~~party facilities~~ and anactual ~~interruption~~future ofproduction ~~its~~may ~~ability~~vary tosignificantly ~~utilize~~and ~~these~~may ~~facilities~~also ~~may~~be ~~adversely~~negatively ~~affect~~impacted by its ~~financial~~inability ~~condition~~to ~~and~~invest ~~results~~in ofproduction ~~operations:~~on ~~Energen~~planned ~~Resources~~timelines: ~~delivers~~There toare ~~and~~numerous ~~Alagasco~~uncertainties isinherent ~~served~~in byestimating ~~third~~quantities ~~party~~of ~~facilities.~~proved ~~These~~oil ~~facilities~~and ~~include~~gas ~~third~~reserves ~~party~~and ~~oil~~in ~~and~~projecting ~~gas~~future ~~gathering,~~rates ~~transportation,~~of ~~processing~~production and ~~storage~~timing ~~facilities~~of development expenditures. ~~Energen~~The ~~Resources~~total ~~relies~~amount ~~upon~~or ~~such~~timing ~~facilities~~of ~~for~~actual ~~access~~future toproduction ~~markets~~may ~~for~~vary ~~its~~significantly from reserve and production estimates. ~~Alagasco~~In ~~relies~~the ~~upon~~event ~~such~~Energen ~~facilities~~Resources ~~for~~is ~~access~~unable to ~~natural~~fully ~~gas~~invest ~~supplies. Such~~its ~~facilities~~planned ~~are~~development, ~~typically~~acquisition ~~limited~~and inexploratory ~~number~~expenditures, future operating revenues, production, and ~~geographically~~proved ~~concentrated.~~reserves Ancould ~~extended~~be ~~interruption~~negatively affected. The drilling of ~~access~~development toand orexploratory ~~service~~wells ~~from~~can ~~these~~involve ~~facilities~~significant risks, ~~whether~~including ~~caused~~those byrelated ~~weather~~to ~~events~~timing, ~~natural~~success ~~disaster,~~rates ~~accident,~~and ~~mechanical~~cost ~~failure~~overruns, ~~criminal~~and ~~act~~these orrisks ~~otherwise~~can ~~could~~be ~~result~~affected inby ~~material~~lease ~~adverse~~and ~~financial~~rig ~~consequences~~availability, tocomplex ~~Energen~~geology ~~Resources,~~and ~~Alagasco~~other factors. Anticipated drilling plans and ~~the~~capital ~~Company.~~expenditures may also change

The Company's oil and natural gas reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by its inability to invest in production on planned timelines: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.38

~~The~~due ~~Company's~~to ~~operations~~weather, ~~involve~~manpower ~~operational~~and ~~risk~~equipment ~~including risk of personal injury~~availability, ~~property~~changing ~~damage~~emphasis ~~and~~by ~~environmental~~management ~~damage~~ and ~~its~~a ~~insurance~~variety ~~policies~~of doother ~~not~~factors ~~cover~~which ~~all~~could ~~such~~result ~~risks: Inherent~~ in ~~the~~actual ~~oil~~drilling and ~~gas~~capital ~~production~~expenditures ~~activities~~being ofsubstantially ~~Energen~~different ~~Resources~~than ~~and~~currently ~~the gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:~~planned.

The Company’s operations involve operational risk including risk of personal injury, property damage and environmental damage and its insurance policies do not cover all such risks: Inherent in the oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:


•	Pipeline and storage leaks, ruptures and spills;


•	Equipment malfunctions and mechanical failures;


•	Fires and explosions;


•	Well blowouts, explosions and cratering; and


•	Soil, surface water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial financial losses. The location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses and the insurance coverages are subject to retention levels and coverage limits. The occurrence of any of these events could adversely affect Energen Resources'’, Alagasco'’s and the Company'’s financial positions, results of operations and cash flows.

Alagasco operates in a limited service territory and is therefore subject to concentrated regional risks which may negatively affect Alagasco'’s financial condition and results of operations: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

The Company is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company'’s operations.

34The Company’s business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions: The Company relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company’s information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company’s operations, financial position and results of operations.

The Company's business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions: The Company relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company's information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company's operations, financial position and results of operations. 39



SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except sales price data)	2013			2012			2013			2012
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	62,073		$	49,422		$	196,311		$	156,308
Oil	183,950			147,710			607,975			578,167
Natural gas liquids	26,292			17,566			71,556			64,970
Other	(277)			(78)			(492		)	(106		)
Total	$	272,038		$	214,620		$	875,350		$	799,339
Non-cash mark-to-market gains (losses) included in operating revenues from continuing operations above
Natural gas	$	1,684		$	(4,159	)	$	16,610		$	(4,121	)
Oil	(63,889		)	(40,569		)	(63,861		)	36,355
Natural gas liquids	(1,355		)	(2,024		)	(1,208		)	1,801
Total	$	(63,560	)	$	(46,752	)	$	(48,459	)	$	34,035
Production volumes from continuing operations
Natural gas (MMcf)	14,868			14,622			43,428			44,076
Oil (MBbl)	2,764			2,275			7,670			6,414
Natural gas liquids (MMgal)	36.7			25.2			98.5			79.0
Production volumes from continuing operations (MBOE)	6,116			5,312			17,253			15,641
Total production volumes (MBOE)	6,758			6,026			19,159			17,850
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf)	$	4.06		$	3.66		$	4.14		$	3.64
Oil (barrel)	$	89.67		$	82.76		$	87.59		$	84.47
Natural gas liquids (gallon)	$	0.75		$	0.78		$	0.74		$	0.80
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.39		$	2.69		$	3.51		$	2.51
Oil (barrel)	$	103.22		$	86.55		$	92.69		$	89.92
Natural gas liquids (gallon)	$	0.68		$	0.68		$	0.65		$	0.78
Other data from continuing operations
Lease operating expense
Lease operating expense and other	$	69,086		$	57,397		$	210,455		$	159,052
Production taxes	18,939			13,531			49,598			39,882
Total	$	88,025		$	70,928		$	260,053		$	198,934
Depreciation, depletion and amortization	$	125,060		$	86,062		$	332,690		$	244,914
Capital expenditures	$	257,759		$	323,037		$	892,691		$	957,913
Exploration expense	$	8,949		$	10,644		$	13,902		$	13,382
Operating income	$	18,607		$	26,913		$	181,948		$	280,897

SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended
	March 31,
(in thousands, except sales price data)	2013			2012
Oil and Gas Operations
Operating revenues
Natural gas	$	71,072		$	75,580
Oil	161,812			124,314
Natural gas liquids	21,116			23,712
Other	994			351
Total	$	254,994		$	223,957
Non-cash mark-to-market gains (losses) included in operating revenues above
Natural gas	$	(4,375	)	$	283
Oil	(36,652		)	(41,920		)
Natural gas liquids	(21		)	965
Total	$	(41,048	)	$	(40,672	)
Production volumes
Natural gas (MMcf)	17,688			19,092
Oil (MBbl)	2,317			1,953
Natural gas liquids (MMgal)	27.6			26.0
Total production volumes (MBOE)	5,921			5,755
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	4.27		$	3.94
Oil (barrel)	$	85.66		$	85.12
Natural gas liquids (gallon)	$	0.77		$	0.87
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.31		$	2.67
Oil (barrel)	$	82.44		$	98.58
Natural gas liquids (gallon)	$	0.68		$	0.95
Other data
Lease operating expense
Lease operating expense and other	$	81,546		$	56,612
Production taxes	14,363			14,162
Total	$	95,909		$	70,774
Depreciation, depletion and amortization	$	104,566		$	84,088
Asset impairment	$	—		$	21,545
Capital expenditures	$	285,053		$	340,967
Exploration expense	$	1,500		$	1,789
Operating income	$	26,327		$	26,005



Natural Gas Distribution
Operating revenues
Residential	$	31,201		$	30,658		$	259,492		$	201,537
Commercial and industrial	18,194			17,695			103,419			84,889
Transportation	13,197			13,505			45,261			42,765
Other	(14,224		)	(49		)	(17,605		)	(2,008		)
Total	$	48,368		$	61,809		$	390,567		$	327,183
Gas delivery volumes (MMcf)
Residential	1,384			1,378			15,379			11,601
Commercial and industrial	1,272			1,246			7,434			6,137
Transportation	11,237			11,252			34,733			34,835
Total	13,893			13,876			57,546			52,573
Other data
Depreciation and amortization	$	11,063		$	10,572		$	32,665		$	31,551
Capital expenditures	$	20,980		$	18,813		$	67,790		$	51,786
Operating income (loss)	$	(22,544	)	$	(12,743	)	$	58,968		$	70,265

Natural Gas Distribution
Operating revenues
Residential	$	162,739		$	130,509
Commercial and industrial	57,599			46,756
Transportation	18,240			15,598
Other	(893		)	1,624
Total	$	237,685		$	194,487
Gas delivery volumes (MMcf)
Residential	10,382			8,238
Commercial and industrial	4,207			3,442
Transportation	12,790			12,036
Total	27,379			23,716
Other data
Depreciation and amortization	$	10,729		$	10,446
Capital expenditures	$	19,697		$	14,943
Operating income	$	79,293		$	78,560

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energen Resources'’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company'’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the ~~cash flow~~ hedge, as well as its risk management objective and strategy for undertaking the hedge. As of ~~March~~September 3130, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015.

A failure to meet sales volume targets at Energen Resources or gas supply targets at Alagasco due to miscalculations, weather events, natural disasters, accidents, mechanical failure, criminal act or otherwise could leave the Company or Alagasco exposed to its counterparties in commodity hedging contracts and result in material adverse financial losses.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for details related to the Company'’s hedging activities.

The Company’s interest rate exposure as of ~~March~~September 3130, 2013, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at ~~March~~September 3130, 2013 was 1.3736 percent. The Company'’s interest rate exposure on long-term debt as of ~~March 31~~September 30, 2013, was minimal since approximately 91 percent of long-term debt obligations were at fixed rates.

3842

ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

(a)

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) ~~Our~~During ~~chief executive officer and chief financial officer of Energen Corporation have concluded that during~~ the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Alabama Gas Corporation

(a) Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures ~~are~~were not effective at that reasonable assurance level. due to the existence of a material weakness in our internal control over

~~(b) Our chief executive officer and chief~~ financial ~~officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial~~ reporting ~~that~~which ~~materially~~is ~~affected~~described ~~or are reasonably likely to materially affect our internal control over financial reporting~~below.

39A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Alabama Gas Corporation’s principal accounting officer failed to operate within the Company’s code of conduct and engaged in an override of internal controls during the second and third quarters of 2013. This officer requested that two vendors delay submission of invoices and bypassed controls for the timely accrual of liabilities and operating expenses for services rendered. Management has determined that the impact of this override resulted in an immaterial understatement of expenses for the quarter ended June 30, 2013 of approximately $76,000. Since the override was identified by management prior to preparation of financial statements for the quarter ended September 30, 2013, it did not result in misstatement for that quarter. However, an override of internal controls by a member of senior management could result in misstatements impacting all accounts and disclosures that would result in a material misstatement of the financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

The principal accounting officer who overrode the control has separated from Alabama Gas Corporation and a successor has been elected by the Alabama Gas Corporation Board of Directors. The importance of timely invoicing has been reviewed with the Alabama Gas Corporation officers and with the two vendors involved.


(b)	As described above in (a) there were changes in our internal control over financial reporting during the most recent fiscal quarter covered by this report.

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. See Note 8, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plansor Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
January 1, 2013 through January 31, 2013	—		$	—	—	8,992,700
July 1, 2013 through July 31, 2013	29	*	$	53.32	—	8,992,700
February 1, 2013 through February 28, 2013	—		—		—	8,992,700
August 1, 2013 through August 31, 2013	6,751	*	65.31		—	8,992,700
March 1, 2013 through March 31, 2013	1,556	*	45.56		—	8,992,700
September 1, 2013 through September 30, 2013	5,418	*	73.96		—	8,992,700
Total	112,~~556~~198		$	4569.5612	—	8,992,700

* Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company'’s common stock. The resolutions do not have an expiration date.

ITEM 6. EXHIBITS

31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101	-	The financial statements and notes thereto from Energen Corporation'’s Quarterly Report on Form 10-Q for the
		quarter ended March 31, 2013 are formatted in XBRL
		quarter ended September 30, 2013 are formatted in XBRL

4044

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ENERGEN CORPORATIONALABAMA GAS CORPORATION
May 9, 2013	By	/s/ J. T. McManus, II
November 8, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
May 9, 2013	By	/s/ Charles W. Porter, Jr.
November 8, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
May 9, 2013	By	/s/ Russell E. Lynch, Jr.
November 8, 2013	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
May 9, 2013	By	/s/ William D. Marshall
November 8, 2013	By	/s/ Leonarda M. DiChiara
		William D. Marshall
		Leonarda M. DiChiara
		Vice President and Controller of Alabama Gas Corporation

4145

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