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 31,~~JUNE 30, 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~~August 1, 2013.



Energen Corporation	$0.01 par value	~~72,222,501~~72,224,230 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 31,~~JUNE 30, 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	27
	Selected Business Segment Data of Energen Corporation	3637
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3839
Item 4.	Controls and Procedures	3940
PART II: OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4041
Item 6.	Exhibits	4041
SIGNATURES		4142

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


CONSOLIDATED CONDENSED STATEMENTS OF INCOME	CONSOLIDATED CONDENSED STATEMENTS OF INCOME						CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Three months ended						Six months ended
	March 31,						June 30,						June 30,
(in thousands, except per share data)	2013			2012			2013			2012			2013			2012
Operating Revenues
Oil and gas operations	$	254,994		$	223,957		$	385,543		$	399,468		$	640,537		$	623,425
Natural gas distribution	237,685			194,487			104,514			70,887			342,199			265,374
Total operating revenues	492,679			418,444			490,057			470,355			982,736			888,799
Operating Expenses
Cost of gas	95,442			59,586			47,571			13,669			143,013			73,255
Operations and maintenance	145,837			110,561			136,204			112,713			282,041			223,274
Depreciation, depletion and amortization	115,295			94,534			132,285			101,991			247,580			196,525
Asset impairment	—			21,545			—			—			—			21,545
Taxes, other than income taxes	28,772			26,235			25,650			19,523			54,422			45,758
Accretion expense	1,997			1,813			2,043			1,861			4,040			3,674
Total operating expenses	387,343			314,274			343,753			249,757			731,096			564,031
Operating Income	105,336			104,170			146,304			220,598			251,640			324,768
Other Income (Expense)
Interest expense	(16,754		)	(15,425		)	(17,306		)	(15,835		)	(34,060		)	(31,260		)
Other income	1,758			2,032			748			659			2,506			2,217
Other expense	(69		)	(113		)	(128		)	(582		)	(197		)	(221		)
Total other expense	(15,065		)	(13,506		)	(16,686		)	(15,758		)	(31,751		)	(29,264		)
Income Before Income Taxes	90,271			90,664			129,618			204,840			219,889			295,504
Income tax expense	33,579			33,258			46,551			73,553			80,130			106,811
Net Income	$	56,692		$	57,406		$	83,067		$	131,287		$	139,759		$	188,693
Diluted Earnings Per Average Common Share	$	0.78		$	0.79		$	1.15		$	1.82		$	1.93		$	2.61
Basic Earnings Per Average Common Share	$	0.79		$	0.80		$	1.15		$	1.82		$	1.94		$	2.62
Dividends Per Common Share	$	0.145		$	0.140		$	0.145		$	0.140		$	0.290		$	0.280
Diluted Average Common Shares Outstanding	72,288			72,326			72,419			72,330			72,329			72,336
Basic Average Common Shares Outstanding	72,143			72,102			72,167			72,117			72,155			72,110

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


CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME	CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME						CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Three months ended						Six months ended
	March 31,						June 30,						June 30,
(in thousands)	2013			2012			2013			2012			2013			2012
Net Income	$	56,692		$	57,406		$	83,067		$	131,287		$	139,759		$	188,693
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		)
Reclassification adjustment for commodity derivative instruments, net of tax of ($6,570) and $302	(10,720		)	493
Current period change in fair value of interest rate swap, net of tax of ($11) and ($265)	(20		)	(492		)
Reclassification adjustment for interest rate swap, net of tax of $143 and $137	266			254
Current period change in fair value of commodity derivative instruments, net of tax of $9,713, $68,741, ($6,712) and $61,243							15,847			112,158			(10,951		)	99,923
Reclassification adjustment for commodity derivative instruments, net of tax of ($1,711), ($9,682), ($8,281) and ($9,379)							(2,792		)	(15,797		)	(13,511		)	(15,303		)
Current period change in fair value of interest rate swap, net of tax of $176, ($566), $165 and ($830)							327			(1,051		)	307			(1,542		)
Reclassification adjustment for interest rate swap, net of tax of $149, $144, $292 and $280							277			267			544			520
Total cash flow hedges	(37,272		)	(11,979		)	13,659			95,577			(23,611		)	83,598
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $26 and $25	48			47
Amortization of prior service cost, net of taxes of $27 and $30	51			55
Amortization of net loss, including settlement charges, net of taxes of $920 and $412	1,709			766
Amortization of net obligation at transition, net of taxes of $26, $25, $52 and $50							47			47			95			93
Amortization of prior service cost, net of taxes of $28, $30, $55 and $59							51			55			102			110
Amortization of net loss, including settlement charges, net of taxes of $734, $413, $1,654 and $826							1,363			766			3,071			1,533
Total pension and postretirement plans	1,808			868			1,461			868			3,268			1,736
Comprehensive Income	$	21,228		$	46,295		$	98,187		$	227,732		$	119,416		$	274,027

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


CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands)	March 31, 2013		December 31, 2012		June 30, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	20,303	$	9,704	$	3,793	$	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 $5,296 at June 30, 2013, and $6,549 at December 31, 2012					226,255		277,900
Inventories
Storage gas inventory	9,264		32,205		21,231		32,205
Materials and supplies	25,283		28,291		19,835		28,291
Liquified natural gas in storage	3,109		3,498		3,092		3,498
Regulatory asset	24,135		45,515		10,915		45,515
Income tax receivable	1,883		6,664		996		6,664
Assets held for sale					130,743		—
Deferred income taxes	27,278		8,520		21,701		8,520
Prepayments and other	12,084		12,823		8,338		12,823
Total current assets	364,846		425,120		446,899		425,120
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,712,635		6,439,127		6,757,512		6,439,127
Less accumulated depreciation, depletion and amortization	1,858,960		1,765,241		1,805,307		1,765,241
Oil and gas properties, net	4,853,675		4,673,886		4,952,205		4,673,886
Utility plant	1,435,924		1,416,590		1,454,659		1,416,590
Less accumulated depreciation	583,625		573,947		588,459		573,947
Utility plant, net	852,299		842,643		866,200		842,643
Other property, net	25,218		25,107		31,535		25,107
Total property, plant and equipment, net	5,731,192		5,541,636		5,849,940		5,541,636
Other Assets
Regulatory asset	109,002		110,566		107,189		110,566
Other postretirement assets	1,732		1,404		1,962		1,404
Long-term derivative instruments	26,199		40,577		39,006		40,577
Deferred charges and other	60,207		56,587		60,167		56,587
Total other assets	197,140		209,134		208,324		209,134
TOTAL ASSETS	$	6,293,178	$	6,175,890	$	6,505,163	$	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 31, 2013			December 31, 2012			June 30, 2013			December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	75,000		$	50,000		$	100,000		$	50,000
Notes payable to banks	712,000			643,000			800,000			643,000
Accounts payable	285,920			257,579			273,531			257,579
Accrued taxes	38,666			30,076			58,540			30,076
Customers' deposits	25,231			24,705			24,403			24,705
Amounts due customers	10,580			19,718			10,956			19,718
Accrued wages and benefits	17,587			24,984			19,904			24,984
Regulatory liability	41,886			45,116			27,581			45,116
Royalty payable	38,771			34,426			41,417			34,426
Liabilities related to assets held for sale							7,917			—
Other	27,344			30,178			32,187			30,178
Total current liabilities	1,272,985			1,159,782			1,396,436			1,159,782
Long-term debt	1,078,529			1,103,528			1,053,542			1,103,528
Deferred Credits and Other Liabilities
Asset retirement obligation	120,599			118,023			119,029			118,023
Pension and other postretirement liabilities	106,515			110,282			109,086			110,282
Regulatory liability	68,812			80,404			68,934			80,404
Long-term derivative instruments	9,705			11,305			470			11,305
Deferred income taxes	931,628			905,601			963,727			905,601
Other	12,981			10,275			12,462			10,275
Total deferred credits and other liabilities	1,250,240			1,235,890			1,273,708			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, 75,086,901 shares issued at June 30, 2013, and 75,067,760 shares issued at December 31, 2012							751			751
Premium on capital stock	493,928			492,108			496,339			492,108
Capital surplus	2,802			2,802			2,802			2,802
Retained earnings	2,360,274			2,314,055			2,432,869			2,314,055
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	8,834			46,352			21,890			46,352
Pension and postretirement plans	(50,699		)	(52,507		)	(49,239		)	(52,507		)
Interest rate swap	(1,910		)	(2,156		)	(1,305		)	(2,156		)
Deferred compensation plan	3,416			2,774			3,445			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: 2,971,254 shares at June 30, 2013, and 2,998,620 shares at December 31, 2012							(126,075		)	(127,489		)
Total shareholders' equity	2,691,424			2,676,690			2,781,477			2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,293,178		$	6,175,890		$	6,505,163		$	6,175,890

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


CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS	CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS						CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)

Three months ended March 31, (in thousands)	2013			2012
Six months ended June 30, (in thousands)							2013			2012
Operating Activities
Net income	$	56,692		$	57,406		$	139,759		$	188,693
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	115,295			94,534			247,580			196,525
Asset impairment	—			21,545			—			21,545
Accretion expense	1,997			1,813			4,040			3,674
Deferred income taxes	29,028			23,182			57,442			55,060
Bad debt expense (recovery)	218			(258		)
Bad debt expense							457			13
Exploratory expense	541			1,076			937			1,360
Change in derivative fair value	37,977			47,221			(19,143		)	(80,221		)
(Gain) loss on sale of assets	(656		)	47
Gain on sale of assets							(105		)	(167		)
Other, net	11,078			4,261			20,557			11,543
Net change in:
Accounts receivable	(35,312		)	20,063			(3,359		)	62,635
Inventories	26,338			1,473			19,550			(1,416		)
Accounts payable	9,670			7,327			12,971			(26,782		)
Amounts due customers, including gas supply pass-through	10,254			(31,926		)	26,797			(46,066		)
Income tax receivable	4,781			5,852			5,668			4,401
Pension and other postretirement benefit contributions	(10,334		)	(3,176		)	(10,753		)	(4,116		)
Other current assets and liabilities	3,886			(19,460		)	37,396			39,186
Net cash provided by operating activities	261,453			230,980			539,794			425,867
Investing Activities
Additions to property, plant and equipment	(297,301		)	(276,791		)	(666,377		)	(574,360		)
Acquisitions, net of cash acquired	(13,146		)	(68,176		)	(17,183		)	(76,894		)
Proceeds from sale of assets	1,370			13,766			2,382			2,117
Other, net	(362		)	(375		)	(759		)	(504		)
Net cash used in investing activities	(309,439		)	(331,576		)	(681,937		)	(649,641		)
Financing Activities
Payment of dividends on common stock	(10,473		)	(10,095		)	(20,945		)	(20,193		)
Issuance of common stock	—			604			108			633
Payment of long-term debt	(10		)	(25		)	(10		)	(123		)
Net change in short-term debt	69,000			150,000			157,000			295,000
Tax benefit on stock compensation	68			227			79			260
Other	—			(38		)	—			(38		)
Net cash provided by financing activities	58,585			140,673			136,232			275,539
Net change in cash and cash equivalents	10,599			40,077			(5,911		)	51,765
Cash and cash equivalents at beginning of period	9,704			9,541			9,704			9,541
Cash and Cash Equivalents at End of Period	$	20,303		$	49,618		$	3,793		$	61,306

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						Three months ended						Six months ended
	March 31,						June 30,						June 30,
(in thousands)	2013			2012			2013			2012			2013			2012
Operating Revenues	$	237,685		$	194,487		$	104,514		$	70,887		$	342,199		$	265,374
Operating Expenses
Cost of gas	95,442			59,586			47,571			13,669			143,013			73,255
Operations and maintenance	38,017			34,066			36,005			36,169			74,022			70,235
Depreciation and amortization	10,729			10,446			10,873			10,533			21,602			20,979
Income taxes
Current	25,921			25,440			(1,778		)	(2,631		)	24,143			22,809
Deferred	3,020			3,198			1,335			2,969			4,355			6,167
Taxes, other than income taxes	14,204			11,829			7,846			6,068			22,050			17,897
Total operating expenses	187,333			144,565			101,852			66,777			289,185			211,342
Operating Income	50,352			49,922			2,662			4,110			53,014			54,032
Other Income (Expense)
Allowance for funds used during construction	219			134			227			131			446			265
Other income	750			986			361			340			1,111			1,138
Other expense	(69		)	(62		)	(121		)	(296		)	(190		)	(170		)
Total other income	900			1,058			467			175			1,367			1,233
Interest Expense
Interest on long-term debt	3,378			3,424			3,377			3,423			6,755			6,848
Other interest expense	652			638			456			536			1,108			1,173
Total interest expense	4,030			4,062			3,833			3,959			7,863			8,021
Net Income	$	47,222		$	46,918
Net Income (Loss)							$	(704	)	$	326		$	46,518		$	47,244

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


CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands)	March 31, 2013			December 31, 2012			June 30, 2013			December 31, 2012
ASSETS
Property, Plant and Equipment
Utility plant	$	1,435,924		$	1,416,590		$	1,454,659		$	1,416,590
Less accumulated depreciation	583,625			573,947			588,459			573,947
Utility plant, net	852,299			842,643			866,200			842,643
Other property, net	41			42			41			42
Current Assets
Cash and cash equivalents	17,260			5,559			565			5,559
Accounts receivable
Gas	99,657			94,011			47,757			94,011
Other	5,698			5,117			8,122			5,117
Affiliated companies	4,620			5,742			3,364			5,742
Allowance for doubtful accounts	(4,600		)	(5,700		)	(4,600		)	(5,700		)
Inventories
Storage gas inventory	9,264			32,205			21,231			32,205
Materials and supplies	5,541			5,528			5,396			5,528
Liquified natural gas in storage	3,109			3,498			3,092			3,498
Regulatory asset	24,135			45,515			10,915			45,515
Income tax receivable	—			2,762			—			2,762
Assets held for sale							3,011			—
Deferred income taxes	18,669			18,799			20,712			18,799
Prepayments and other	3,674			4,451			1,645			4,451
Total current assets	187,027			217,487			121,210			217,487
Other Assets
Regulatory asset	109,002			110,566			107,189			110,566
Pension and other postretirement assets	1,103			848			1,259			848
Deferred charges and other	11,098			11,290			10,905			11,290
Total other assets	121,203			122,704			119,353			122,704
TOTAL ASSETS	$	1,160,570		$	1,182,876		$	1,106,804		$	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 31, 2013		December 31, 2012		June 30, 2013		December 31, 2012
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—	$	—	$	—
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 June 30, 2013 and December 31, 2012					20		20
Premium on capital stock	31,682		31,682		31,682		31,682
Capital surplus	2,802		2,802		2,802		2,802
Retained earnings	364,783		325,999		353,641		325,999
Total common shareholder's equity	399,287		360,503		388,145		360,503
Long-term debt	250,018		250,028		250,018		250,028
Total capitalization	649,305		610,531		638,163		610,531
Current Liabilities
Notes payable to banks	30,000		77,000		—		77,000
Accounts payable	38,264		51,741		43,982		51,741
Accrued taxes	47,068		24,186		40,005		24,186
Customers' deposits	25,231		24,705		24,403		24,705
Amounts due customers	10,580		19,718		10,956		19,718
Accrued wages and benefits	6,184		6,703		4,768		6,703
Regulatory liability	41,886		45,116		27,581		45,116
Other	9,535		9,018		9,493		9,018
Total current liabilities	208,748		258,187		161,188		258,187
Deferred Credits and Other Liabilities
Deferred income taxes	192,271		189,381		195,649		189,381
Pension and other postretirement liabilities	39,914		43,611		41,348		43,611
Regulatory liability	68,812		80,404		68,934		80,404
Other	1,520		762		1,522		762
Total deferred credits and other liabilities	302,517		314,158		307,453		314,158
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,160,570	$	1,182,876	$	1,106,804	$	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
Six months ended June 30, (in thousands)							2013			2012
Operating Activities
Net income	$	47,222		$	46,918		$	46,518		$	47,244
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,729			10,446			21,602			20,979
Deferred income taxes	3,020			3,198			4,355			6,167
Bad debt expense (recovery)	217			(258		)
Bad debt expense							450			8
Other, net	3,685			(2,564		)	7,083			432
Net change in:
Accounts receivable	(23,409		)	14,706			8,179			30,036
Inventories	23,317			5,985			11,512			7,474
Accounts payable	(11,306		)	(20,364		)	(6,828		)	(24,516		)
Amounts due customers, including gas supply pass-through	10,254			(31,926		)	26,797			(46,066		)
Income tax receivable	2,762			8,374			2,762			7,858
Pension and other postretirement benefit contributions	(5,365		)	(681		)	(5,600		)	(1,363		)
Other current assets and liabilities	24,183			11,425			16,863			9,008
Net cash provided by operating activities	85,309			45,259			133,693			57,261
Investing Activities
Additions to property, plant and equipment	(19,046		)	(14,245		)	(44,679		)	(32,786		)
Other, net	886			(767		)	1,878			2,596
Net cash used in investing activities	(18,160		)	(15,012		)	(42,801		)	(30,190		)
Financing Activities
Dividends	(8,438		)	(8,027		)	(18,876		)	(18,104		)
Payment of long-term debt	(10		)	(25		)	(10		)	(123		)
Net increases in advances from affiliates							—			14,304
Net change in short-term debt	(47,000		)	10,000			(77,000		)	(15,000		)
Other	—			(38		)	—			(38		)
Net cash provided by (used in) financing activities	(55,448		)	1,910
Net cash used in financing activities							(95,886		)	(18,961		)
Net change in cash and cash equivalents	11,701			32,157			(4,994		)	8,110
Cash and cash equivalents at beginning of period	5,559			7,817			5,559			7,817
Cash and Cash Equivalents at End of Period	$	17,260		$	39,974		$	565		$	15,927

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.

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~~six months ended ~~March 31,~~June 30, 2012 resulted in ~~a decrease~~decreases of $~~3.9~~3.7 million and $~~4.5~~4.6 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’s~~The Company’s current ~~extension is for~~RSE order has a ~~seven-year period~~term extending through December 31, 2014. ~~RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing,~~At its March 2013 monthly meeting, the APSC ~~votes~~announced the schedule for a series of public informal proceedings to ~~modify or discontinue~~review the Company’s RSE ~~methodology.~~mechanism. The Company expects discussion topics to include allowed range of return on equity, the timing of term renewal and the term length of renewal. The public proceedings are scheduled to occur beginning September 5, 2013.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. 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 six months ended ~~March 31,~~June 30, 2013, Alagasco had a net $~~2.4~~3.8 million pre-tax 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. During the three months and six months ended June 30, 2012, Alagasco had a net $5.0 million pre-tax 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 limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. 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 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.

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 all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. 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~~twelve of its active counterparties at ~~March 31,~~June 30, 2013. The ~~two~~three largest counterparty net ~~loss~~gain positions at ~~March 31,~~June 30, 2013, ~~Morgan Stanley Capital Group, Inc~~Macquarie Bank Limited, BP Corporation North America Inc. and ~~Barclays Bank PLC,~~J Aron & Company, constituted approximately $~~24.7~~16.5 million, $11.7 million and $~~5.1~~11.5 million, respectively, of Energen Resources’ total net ~~loss~~gain on fair value of derivatives. At June 30, 2013, Energen Resources was in a net ~~gain~~loss 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 BP Corporation North America Inc., constituted~~Morgan Stanley Capital Group for approximately $~~10.3~~11.4 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 31,~~June 30, 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 Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of 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 NYMEX oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to ~~March 31, 2013~~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 31, 2013									June 30, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total			Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	51,277			$	—	$	51,277		$	72,679			$	—	$	72,679
Long-term asset derivative instruments	25,921				—		25,921			42,105				—		42,105
Total derivative assets	77,198				—		77,198			114,784				—		114,784
Accounts receivable	(36,245		)	*	—		(36,245		)	(26,598		)	*	—		(26,598		)
Long-term asset derivative instruments	(6,594		)	*	—		(6,594		)	(3,099		)	*	—		(3,099		)
Accounts payable	(11,983		)		—		(11,983		)	(12,506		)		—		(12,506		)
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		)	*	—		(4,342		)
Long-term asset derivative instruments	6,872				—		6,872
Total derivative assets	2,530				—		2,530
Accounts payable	(20,816		)		—		(20,816		)
Long-term liability derivative instruments	(1,074		)		—		(1,074		)
Total derivative liabilities	(21,890		)		—		(21,890		)	(42,203		)		—		(42,203		)
Total derivatives not designated	(19,360		)		—		(19,360		)	$	72,581			$	—	$	72,581
Total derivatives	$	(4,259	)		$	—	$	(4,259	)



(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 $~~5.4~~13.4 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 31,~~June 30, 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 months ended March 31, 2013			Three months ended March 31, 2012			Location on Statement of Income	Three months ended June 30, 2013		Three months ended June 30, 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 recognized in OCI on derivatives (effective portion), net of tax of $9.7 million and $68.7 million								—	$	15,847	$	112,158
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	17,824		$	1,872		Operating revenues	$	3,112	$	21,143
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(534	)	$	(2,666	)
Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)								Operating revenues	$	1,392	$	4,336



(in thousands)	Location on Statement of Income	Six months ended June 30, 2013			Six months ended June 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6.7) million and $61.2 million	—	$	(10,951	)	$	99,923
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	20,935		$	23,013
Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	858		$	1,669

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 months ended March 31, 2013			Three months ended March 31, 2012			Location on Statement of Income	Three months ended June 30, 2013		Three months ended June 30, 2012
Loss recognized in income on derivatives	Operating revenues	$	(31,501	)	$	(44,005	)
Gain recognized in income on derivatives								Operating revenues	$	53,078	$	123,448



(in thousands)	Location on Statement of Income	Six months ended June 30, 2013		Six months ended June 30, 2012
Gain recognized in income on derivatives	Operating revenues	$	21,577	$	79,443

As of ~~March 31,~~June 30, 2013, $~~1.6~~14.6 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,~~June 30, 2013, the Company had ~~4.2~~27.3 billion cubic feet (Bcf), 51.8 Bcf and ~~9.7~~6.0 Bcf of natural gas hedges which expire during 2013, 2014 and ~~2014,~~2015, respectively, that ~~did not meet the definition of a cash flow hedge but~~ are considered ~~by the Company to be economic hedges.~~mark-to-market transactions. The Company had ~~10.5~~8.5 million barrels (MMBbl), ~~8.2~~9.8 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.~~mark-to-market transactions. The Company had ~~1.6~~23.2 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that ~~did not meet the definition of a cash flow hedge but~~ are considered bymark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $5.9 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 ~~be economic hedges.~~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 Contract

Price

Description

Total Hedged Volumes

Average Contract

Price

Description

Natural Gas

2013

9.4

Bcf

$4.83 Mcf

NYMEX Swaps

6.2

Bcf

$4.83 Mcf

NYMEX Swaps

24.4

Bcf

$4.56 Mcf

Basin Specific Swaps - San Juan

17.9

Bcf

$4.51 Mcf

Basin Specific Swaps - San Juan

3.4

Bcf

$3.45 Mcf

Basin Specific Swaps - Permian

3.1

Bcf

$3.64 Mcf

Basin Specific Swaps - Permian

2014

10.6

Bcf

$4.55 Mcf

NYMEX Swaps

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

9.7

Bcf

$3.81 Mcf

Basin Specific Swaps - Permian

2015

6.0

Bcf

$4.07 Mcf

Basin Specific Swaps - San Juan

Oil

2013

6,752

MBbl

$90.99 Bbl

NYMEX Swaps

4,603

MBbl

$91.07 Bbl

NYMEX Swaps

2014

9,796

MBbl

$92.64 Bbl

NYMEX Swaps

9,796

MBbl

$92.64 Bbl

NYMEX Swaps

2015

720

MBbl

$90.10 Bbl

NYMEX Swaps

720

MBbl

$90.10 Bbl

NYMEX Swaps

Oil Basis Differential

2013

2,701

MBbl

$(3.02) Bbl

WTS/WTI Basis Swaps*

1,811

MBbl

$(3.00) Bbl

WTS/WTI Basis Swaps*

2,995

MBbl

$(1.00) Bbl

WTI/WTI Basis Swaps**

2,053

MBbl

$(1.00) Bbl

WTI/WTI Basis Swaps**

Natural Gas Liquids

2013

33.9

MMGal

$1.02 Gal

Liquids Swaps

23.4

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 31,~~June 30, 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									June 30, 2013
(in thousands)	Level 2*			Level 3*			Total			Level 2*			Level 3*		Total
Current assets	$	(12,452	)	$	23,142		$	10,690		$	8,108		$	37,973	$	46,081
Noncurrent assets	12,194			14,005			26,199			25,977			13,029		39,006
Current liabilities	(24,834		)	(7,965		)	(32,799		)	(12,635		)	129		(12,506		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)
Net derivative asset										$	21,450		$	51,131	$	72,581



	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 31,~~June 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are 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 $2826 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~~9.8 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			Three months ended			Three months ended
(in thousands)	March 31, 2013			March 31, 2012			June 30, 2013			June 30, 2012
Balance at beginning of period	$	89,019		$	65,801		$	26,459		$	104,923
Realized gains	27,107			13,181			6,183			20,553
Unrealized gains (losses) relating to instruments held at the reporting date*	(63,482		)	39,767			23,404			(2,725		)
Settlements during period	(26,185		)	(13,826		)	(4,915		)	(19,295		)
Balance at end of period	$	26,459		$	104,923		$	51,131		$	103,456



	Six months ended			Six months ended
(in thousands)	June 30, 2013			June 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	32,368			34,379
Unrealized gains (losses) relating to instruments held at the reporting date*	(39,156		)	36,397
Settlements during period	(31,100		)	(33,121		)
Balance at end of period	$	51,131		$	103,456

*Includes $~~12.4~~8.5 million ~~in mark-to-market losses~~ and $~~3.8~~2.7 million in mark-to-market gains for the three months and six months ended ~~March 31,~~June 30, 2013, respectively. Includes $5.4 millionand ~~2012.~~$7.0 million in mark-to-market gains for the three months and six months ended June 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 31, 2013			Valuation Technique*	Unobservable Input*	Range	Fair Value as of June 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	14,529		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf	$	19,172		Discounted Cash Flow	Forward Basis	($0.18 - $0.23) Mcf
2014	$	16,066		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf	$	27,196		Discounted Cash Flow	Forward Basis	($0.16 - $0.20) Mcf
2015							$	611		Discounted Cash Flow	Forward Basis	($0.18) Mcf
Natural Gas Basis - Permian
2013	$	(1,854	)	Discounted Cash Flow	Forward Basis	($0.12) Mcf	$	537		Discounted Cash Flow	Forward Basis	($0.18) Mcf
2014	$	(2,731	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf	$	623		Discounted Cash Flow	Forward Basis	($0.16 - $0.17) Mcf
Oil Basis - WTS/WTI
2013	$	(6,209	)	Discounted Cash Flow	Forward Basis	($0.66) Bbl	$	(4,990	)	Discounted Cash Flow	Forward Basis	($0.25) Bbl
Oil Basis - WTI/WTI
2013	$	(2,207	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.28) Bbl	$	(1,568	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.32) Bbl
Natural Gas Liquids
2013	$	8,865		Discounted Cash Flow	Forward Price	$0.75 - $0.83 Gal	$	9,550		Discounted Cash Flow	Forward Price	$0.65 - $0.72 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													June 30, 2013
								Gross Amounts Not Offset in the Balance Sheets													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		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	$	79,728	$	(42,839	)	$	36,889	$	—	$	—	$	36,889	$	114,784	$	(29,697	)	$	85,087	$	—	$	—	$	85,087
Derivative liabilities	$	83,987	$	(42,839	)	$	41,148	$	—	$	—	$	41,148	$	42,203	$	(29,697	)	$	12,506	$	—	$	—	$	12,506



	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					Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2013					March 31, 2012					June 30, 2013					June 30, 2012
	Net			Per Share		Net			Per Share		Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount		Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	56,692	72,143	$	0.79	$	57,406	72,102	$	0.80	$	83,067	72,167	$	1.15	$	131,287	72,117	$	1.82
Effect of dilutive securities
Stock options			144					216					225					205
Non-vested restricted stock			1					8					16					8
Performance share awards													11					—
Diluted EPS	$	56,692	72,288	$	0.78	$	57,406	72,326	$	0.79	$	83,067	72,419	$	1.15	$	131,287	72,330	$	1.82



	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2013					June 30, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	139,759	72,155	$	1.94	$	188,693	72,110	$	2.62
Effect of dilutive securities
Stock options			164					218
Non-vested restricted stock			10					8
Diluted EPS	$	139,759	72,329	$	1.93	$	188,693	72,336	$	2.61

For the three months and six months ended ~~March 31,~~June 30, 2013 ~~and 2012~~ the Company had ~~988,087~~315,809 and ~~849,583~~686,849 options, respectively, that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and six months ended June 30, 2012, the Company had 856,843 and 849,583 options, respectively, that were excluded from the computation of diluted EPS. For the three months ended June 30, 2013, the Company had no performance share awards that were excluded from the computation of diluted EPS. For the six months ended ~~March 31,~~June 30, 2013, the Company had 161,249 performance share awards that were excluded from

the computation of diluted EPS. For the three months and six months ended ~~March 31,~~June 30, 2012, the Company had no performance share awards that were excluded from the computation of diluted EPS. For the three and six months ended ~~March 31,~~June 30, 2013 and 2012, the Company had no ~~options or~~ shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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						Three months ended						Six months ended
	March 31,						June 30,						June 30,
(in thousands)	2013			2012			2013			2012			2013			2012
Operating revenues
Operating revenues from continuing operations
Oil and gas operations	$	254,994		$	223,957		$	385,543		$	399,468		$	640,537		$	623,425
Natural gas distribution	237,685			194,487			104,514			70,887			342,199			265,374
Total	$	492,679		$	418,444		$	490,057		$	470,355		$	982,736		$	888,799
Operating income (loss)
Operating income (loss) from continuing operations
Oil and gas operations	$	26,327		$	26,005		$	144,031		$	216,406		$	170,358		$	242,411
Natural gas distribution	79,293			78,560			2,219			4,448			81,512			83,008
Eliminations and corporate expenses	(284		)	(395		)	54			(256		)	(230		)	(651		)
Total	$	105,336		$	104,170		$	146,304		$	220,598		$	251,640		$	324,768
Other income (expense)
Oil and gas operations	$	(11,993	)	$	(10,558	)	$	(13,411	)	$	(12,004	)	$	(25,404	)	$	(22,562	)
Natural gas distribution	(3,130		)	(3,004		)	(3,366		)	(3,784		)	(6,496		)	(6,788		)
Eliminations and other	58			56			91			30			149			86
Total	$	(15,065	)	$	(13,506	)	$	(16,686	)	$	(15,758	)	$	(31,751	)	$	(29,264	)
Income before income taxes	$	90,271		$	90,664		$	129,618		$	204,840		$	219,889		$	295,504


(in thousands)	March 31, 2013		December 31, 2012		June 30, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,100,983	$	4,975,170	$	5,364,154	$	4,975,170
Natural gas distribution	1,155,950		1,177,134		1,103,440		1,177,134
Eliminations and other	36,245		23,586		37,569		23,586
Total	$	6,293,178	$	6,175,890	$	6,505,163	$	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 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 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 that payment of earned performance share awards be made in the

form of Company common stock. The Company estimated fair value of performance share awards based on the quoted market price of the Company's common stock and adjusted each period for the expected payout ratio. 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

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 $~~20.05~~20.59 as of ~~March 31,~~June 30, 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 months ended March 31, 2013, Energen Resources awarded 33,796 Petrotech units, none of which included a market condition, with a fair value of $~~50.45~~50.84 as of ~~March 31,~~June 30, 2013. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $~~70.39~~71.94 as of ~~March 31,~~June 30, 2013. These awards have a three-year vesting period.

Stock Repurchase Program

During the three months and six months ended ~~March 31,~~June 30, 2013, the Company had noncash purchases of approximately $~~71,000~~28,000 and $98,000, 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 ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	3,602		$	2,632		$	7,204		$	5,264
Interest cost	2,718			2,700			2,718			2,700			5,436			5,400
Expected long-term return on assets	(3,713		)	(3,563		)	(3,713		)	(3,563		)	(7,426		)	(7,126		)
Actuarial loss	3,690			2,099			3,675			2,099			7,365			4,198
Prior service cost amortization	122			129			122			129			245			259
Settlement charge	144			—			—			—			144			—
Net periodic expense	$	6,563		$	3,997		$	6,404		$	3,997		$	12,968		$	7,995

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 by the Company during 2013. For the three months and six months ~~months~~ ending ~~March 31,~~June 30, 2013, the Company made benefit payments aggregating $~~0.9~~23,757 and $1.0 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $~~2.9~~0.2 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.

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


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2013			2012			2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	444		$	463		$	888		$	927
Interest cost	869			1,062			869			1,062			1,737			2,124
Expected long-term return on assets	(1,242		)	(1,109		)	(1,242		)	(1,109		)	(2,484		)	(2,219		)
Actuarial loss	—			9			—			9			—			18
Transition amortization	324			479			324			479			648			959
Net periodic expense	$	395		$	904		$	395		$	904		$	789		$	1,809

For the three months and six months ~~months~~ ended ~~March 31,~~June 30, 2013, the Company made contributions aggregating $~~0.5~~0.4 million and $0.8 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $~~1.1~~0.8 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 ~~29.6~~8.2 million barrels of oil equivalent (MMBOE) through ~~November 2021.~~September 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 $1916 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 $9483 million through September 2024. During the ~~three~~six months ending ~~March 31,~~June 30, 2013 and 2012, Alagasco recognized approximately $~~14.4~~26 million and $~~14.3~~25.9 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~~155 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 31,~~June 30, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through ~~January~~March 2014 and an aggregate purchase price of $~~1.1~~1.0 million with a market value of $~~1.2~~1.0 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.

~~On November 2, 2011,~~ Energen Resources ~~spudded~~previously disclosed an adverse judgment relating to the ownership of the company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. ~~During~~Upon a Motion to Reconsider, the ~~drilling phase, Chesapeake Exploration, LLC, notified~~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 that it believed it was the owner of the lease from which~~Resources' superior title to the Cadenhead Well ~~was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a~~ ~~fifty percent~~ ~~working interest in the Cadenhead Well. The Cadenhead Well produced approximately~~ 63 ~~net MBOE in 2012~~ and ~~is expected to produce approximately~~ 34 ~~net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect,~~its associated oil and ~~plans to vigorously pursue all available avenues of appeal.~~gas leases.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

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 $1.7 million of which $1.0 million has been incurred and $0.7 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 from the 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 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

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 31,~~June 30, 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 $~~1,216.9~~1,187.9 million and $1,255.8 million and ~~has~~had a carrying value of $1,154.0 million and $1,154.0 million at ~~March 31,~~June 30, 2013 and December 31, 2012, respectively. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, ~~approximates~~was approximately $~~271.3~~257.2 million and $284.7 million and ~~has~~had a carrying value of $250.0 million ~~and~~at both ~~$250.0 million~~ at ~~March 31,~~June 30, 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 $~~2.9~~2.0 million and a $3.3 million liability at ~~March 31,~~June 30, 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.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At ~~March 31,~~June 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $~~10.4~~10.6 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 6084 months ~~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~~0.7 million and $0.5 million as of ~~March 31,~~June 30, 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	$	470
Provision	116		225
Allowance for credit losses as of March 31, 2013	$	586
Allowance for credit losses as of June 30, 2013			$	695

10. REGULATORY ASSETS AND LIABILITIES

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


(in thousands)	March 31, 2013				December 31, 2012				June 30, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	253	$	89,316	$	170	$	90,708	$	253	$	87,630	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		16,884		—		16,536		—		17,231		—		16,536
Risk management activities	—		—		2,593		—		—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,802		—		3,322		—		2,328		—		3,322
Gas supply adjustment	23,857		—		42,726		—		10,637		—		42,726		—
Other	25		—		26		—		25		—		26		—
Total regulatory assets	$	24,135	$	109,002	$	45,515	$	110,566	$	10,915	$	107,189	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	2,262	$	—	$	1,740	$	—	$	5,209	$	—	$	1,740	$	—
Unbilled service margin	22,108		—		25,078		—		6,016		—		25,078		—
Postretirement liabilities	—		1,487		—		1,237		—		1,738		—		1,237
Refundable negative salvage	17,483		41,352		18,265		53,467		16,323		40,952		18,265		53,467
Asset retirement obligation	—		25,211		—		24,930		—		25,491		—		24,930
Other	33		762		33		770		33		753		33		770
Total regulatory liabilities	$	41,886	$	68,812	$	45,116	$	80,404	$	27,581	$	68,934	$	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~~six months ended ~~March 31,~~June 30, 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		$	118,023
Liabilities incurred	901			1,914
Liabilities settled	(322		)	(448		)
Accretion expense	1,997			4,040
Balance as of March 31, 2013	$	120,599
Reclassification associated with held for sale properties*				(4,500		)
Balance as of June 30, 2013				$	119,029

* Asset retirement obligation associated with Black Warrior Basin properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

The 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 $~~25.2~~25.5 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of ~~March 31,~~June 30, 2013 and December 31, 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $~~2.8~~2.3 million and $3.3 million as of ~~March 31,~~June 30, 2013 and December 31, 2012, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

12. ACQUISITION AND DISPOSITION OF PROPERTIES

In June 2013, Energen Resources classified its Black Warrior Basin properties in Alabama as held-for-sale and began marketing these coalbed methane assets. At December 31, 2012, proved reserves associated with Energen's Black Warrior Basin properties totaled 97 Bcf of natural gas. The Company anticipates the sale being completed within the next twelve-months and using the proceeds from the sale to repay short-term obligations.

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, Alabama, and has been in service since the 1940's. The property is being classified as held-for sale and has a sales price isof approximately $14 million ~~and the~~. 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.

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



(in thousands)	June 30, 2013
	Oil and Gas Operations			Natural Gas Distribution			Total
Accounts receivable	$	5,257		$	—		$	5,257
Inventories	286			—			286
Oil and gas properties	294,607			—			294,607
Less accumulated depreciation, depletion and amortization	(172,464		)	—			(172,464		)
Utility plant	—			7,971			7,971
Less accumulated depreciation	—			(4,960		)	(4,960		)
Other property, net	46			—			46
Total assets held-for-sale	127,732			3,011			130,743
Accounts payable	(1,573		)	—			(1,573		)
Royalty payable	(646		)	—			(646		)
Other current liabilities	(266		)	—			(266		)
Other long-term liabilities	(5,432		)	—			(5,432		)
Total liabilities held-for-sale	(7,917		)	—			(7,917		)
Total held-for-sale properties	$	119,815		$	3,011		$	122,826

During the first quarter of 2012, Energen Resources recognized a noncash 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. 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. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

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			Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(26,818		)	—			(26,818		)
Other comprehensive loss before reclassifications										(10,644		)	—			(10,644		)
Amounts reclassified from accumulated other comprehensive income (loss)	(10,454		)	1,808			(8,646		)	(12,967		)	3,268			(9,699		)
Change in accumulated other comprehensive income (loss)	(37,272		)	1,808			(35,464		)	(23,611		)	3,268			(20,343		)
Balance as of March 31, 2013	$	6,924		$	(50,699	)	$	(43,775	)
Balance as of June 30, 2013										$	20,585		$	(49,239	)	$	(28,654	)

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


	Three months ended				Three months ended			Six months ended
	March 31, 2013				June 30, 2013			June 30, 2013
(in thousands)	Amounts Reclassified			Line Item Where Presented	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	17,290		Operating revenues	$	4,503		$	21,792		Operating revenues
Interest rate swap	(409		)	Interest expense	(426		)	(836		)	Interest expense
Total cash flow hedges	16,881				4,077			20,956
Income tax expense	(6,427		)		(1,562		)	(7,989		)
Net of tax	10,454				2,515			12,967
Pension and postretirement plans:
Transition obligation	(74		)	Operations and maintenance	(74		)	(147		)	Operations and maintenance
Prior service cost	(78		)	Operations and maintenance	(78		)	(157		)	Operations and maintenance
Actuarial losses*	(2,254		)	Operations and maintenance	(2,097		)	(4,350		)	Operations and maintenance
Actuarial losses on settlement charges*	(375		)	Regulatory asset	—			(375		)	Regulatory asset
Total pension and postretirment plans	(2,781		)
Total pension and postretirement plans					(2,249		)	(5,029		)
Income tax expense	973				788			1,761
Net of tax	(1,808		)		(1,461		)	(3,268		)
Total reclassifications for the period	$	8,646			$	1,054		$	9,699

* 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.

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).

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

RESULTS OF OPERATIONS

Energen's net income totaled $~~56.7~~83.1 million ($~~0.78~~1.15 per diluted share) for the three months ended ~~March 31,~~June 30, 2013 compared with net income of $~~57.4~~131.3 million ($~~0.79~~1.82 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended ~~March 31,~~June 30, 2013, of ~~$8.8~~$83.9 million as compared with ~~$9.5~~$131.7 million in the same quarter in the previous year. This decrease in net income was primarily the result of ~~increased lease operating expense excluding production taxes (approximately $16 million after-tax),~~ higher depreciation, depletion and amortization (DD&A) expense (approximately ~~$13~~$19 million after-tax), increased lease operating expense excluding production taxes (approximately $8 million after-tax), higher administrative expense (approximately $4$5 million after-tax), increased production taxes (approximately $3 million after-tax), lower natural gas production volumes (approximately $4$2 million after-tax), decreased natural gas liquids commodity prices (approximately $2$1 million after-tax), and a year-over-year after-tax ~~$0.7~~$43 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax ~~$26~~$35.5 million non-cash mark-to-market ~~loss~~gain on derivatives for the ~~first~~second quarter of 2013 and an after-tax ~~$25.3~~$78.5 million non-cash mark-to-market ~~loss~~gain on derivatives for the ~~first~~second quarter of 2012). Positively affecting net income was the impact of higher oil and natural gas liquids production volumes (approximately ~~$20~~$25 million after-tax), and increased natural gas and oil commodity prices (approximately $4$11 million after-tax). Energen's natural gas utility, Alagasco, reported a net loss of $0.7 million in the second quarter of 2013 compared to net income of $0.3 million in the same period last year.

For the 2013 year-to-date, Energen's net income totaled $139.8 million ($1.93 per diluted share) compared to net income of $188.7 million ($2.61 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2013, of $92.6 million as compared with $141.2 million in the previous period. Higher DD&A expense (approximately $31 million after-tax), increased lease operating expense excluding production taxes (approximately $24 million after-tax), higher administrative expense (approximately $9 million after-tax), lower natural gas production volumes (approximately $5 million after-tax), decreased natural gas liquids commodity prices (approximately $3 million after-tax), increased production taxes (approximately $3 million after-tax), increased interest expense (approximately $2 million after-tax) and a year-over-year after-tax $42.7 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $9.5 million non-cash mark-to-market gain on derivatives for the six months ended June 30, 2013 and an after-tax $52.2 million non-cash mark-to-market gain on derivatives for the six months ended June 30, 2012) were partially offset by increased oil and natural gas liquids production volumes (approximately $45 million), higher natural gas and oil commodity prices (approximately $15 million after-tax) and a 2012 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~~Alagasco’s net income of $46.5 million in the current year-to-date compared to net income of $47.2 million in the ~~first quarter of 2013 compared to net income of~~ ~~$46.9 million~~same period in the ~~same period last~~previous 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.

Oil and Gas Operations

Revenues from oil and gas operations ~~rose 13.9~~declined 3.5 percent to $~~255.0~~385.5 million for the three months ended June 30, 2013 largely as a result of the non-cash mark-to-market decrease in derivatives combined with decreased realized natural gas liquids commodity prices and lower natural gas production volumes partially offset by higher oil and natural gas liquids production volumes and increased realized natural gas and oil commodity prices. Revenues from oil and gas operations rose 2.7 percent to ~~March 31,~~$640.5 million for the six months ended June 30, 2013 ~~largely~~primarily as a result of higher 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.~~prices and the non-cash mark-to-market decrease in derivatives. During the current quarter, revenue per unit of production for natural gas increased ~~8.4~~21.1 percent to ~~$4.27~~$4.30 per thousand cubic feet (Mcf), while oil revenue per unit of production rose ~~slightly~~1.7 percent to ~~$85.66~~$87.13 per barrel. Natural gas liquids revenue per unit of production fell ~~11.5~~6.7 percent to an average price of ~~$0.77~~$0.70 per gallon. In the year-to-date, revenue per unit of production for natural gas rose 14.1 percent to $4.28 per Mcf, oil revenue per unit of production increased 1.2 percent to $86.43 per barrel and natural gas liquids revenue per unit of production fell 9.9 percent to an average price of $0.73 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 and year-to-date 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~~second quarter declined ~~7.4~~4.5 percent to ~~17.7~~18.4 billion cubic feet (Bcf), oil volumes increased ~~18.6~~18.2 percent to ~~2,317~~2,595 thousand barrels (MBbl) and natural gas liquids production rose ~~6.2~~23 percent to ~~27.6~~34.2 million gallons (MMgal). For the year-to-date, natural gas production declined 5.9 percent to 36.1 Bcf, while oil volumes rose 18.4 percent to 4,912 MBbl. Natural gas liquids production increased 14.9 percent to 61.8 MMgal. Oil and natural gas liquids comprised ~~approximately~~slightly more than 50 percent of Energen Resources' production for the current ~~quarter.~~quarter and year-to-date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax ~~gain~~loss of ~~$0.7~~$0.5 million in the ~~first~~second quarter of 2013 and a pre-tax gain of $0.2 million in the year-to-date from the sale of various Permian Basin properties. Energen Resources recorded ~~no property sales~~a pre-tax gain of $0.2 million in the ~~first~~second quarter of ~~2012.~~2012 and year-to-date from the sale of various properties.

Operations and maintenance (O&M) expense increased ~~$31.4~~$24 million for the ~~quarter.~~quarter and $55.4 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' ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) increased ~~$24.9~~$13.2 million for the quarter largely due to additional workover and repair expense (approximately ~~$10.7~~$4.7 million), increased ~~water disposal~~environmental compliance costs (approximately ~~$3.5~~$1.8 million), higher ad valorem taxes (approximately ~~$3.5~~$1.3 million), higher electrical costs (approximately $1.1 million), increased marketing and transportation costs (approximately $1 million), additional equipment rental ~~expense(approximately $3.4~~expense (approximately $1 million), increased gathering costs (approximately ~~$1.3~~$0.9 million) and increased chemical and treatment costs (approximately ~~$1.1~~$0.7 million). In the year-to-date, lease operating expense (excluding production taxes) increased $38.2 million primarily due to increased workover and repair expense (approximately $15.4 million), increased ad valorem taxes (approximately $4.8 million), additional equipment rental expense (approximately $4.4 million), higher water disposal costs (approximately $3.4 million), increased gathering costs (approximately $2.2 million), increased environmental compliance costs (approximately $2.1 million), higher electrical costs (approximately $2 million), increased chemical and treatment costs (approximately $1.8 million), higher marketing and transportation costs (approximately $1.2 million) and increased nonoperated expense (approximately $1 million) partially offset by decreased O&M expense (approximately $1.4 million) . On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was ~~$13.77~~$11.12 per barrel of oil equivalent (BOE) as compared to ~~$9.84~~$9.69 per BOE in the same period a year ago. For the six months ended June 30, 2013, the average lease operating expense (excluding production taxes) was $12.38 per BOE as compared to $9.76 per BOE in the previous period. Administrative expense increased ~~$6.8~~$8.2 million for the three months ended ~~March 31,~~June 30, 2013 largely due to ~~higher labor costs (approximately $2.9 million) and~~ increased costs from the Company’s benefit and performance-based compensation plans (approximately ~~$2.6~~$5.5 million) and higher labor costs (approximately $2.5 million). For the six months ended June 30, 2013, administrative expense rose $15 million primarily due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $8.1 million) and higher labor costs (approximately $5.4 million). Exploration expense ~~fell $0.3~~rose $2.5 million in the ~~first~~second quarter of ~~2013.~~2013 and $2.2 million year-to-date.

Energen Resources' DD&A expense for the quarter rose $30 million. For the year-to-date, Energen Resources' DD&A expense increased ~~$20.5~~$50 million, excluding the prior year impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of certain properties to their fair value based on expected future discounted cash flows. The average depletion rate for the current quarter was ~~$17.46~~$18.54 per BOE as compared to

~~$14.44~~ $14.90 per BOE in the same period a year ago. For the six months ended June 30, 2013, the average depletion rate was $18.03 per BOE as compared to $14.68 per BOE, excluding the asset impairment, in the ~~same period a year ago.~~previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately ~~$17.9~~$23.6 million and $41.5 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development ~~costs.~~costs and the impact from downward reserve revisions related to natural gas reserves at year-end. Higher production volumes contributed approximately ~~$2.4~~$6.1 million and $8.5 million to the increase in DD&A expense for the ~~quarter.~~quarter and year-to-date, respectively.

Energen Resources' expense for taxes other than income taxes was ~~$0.2~~$4.3 million higher in the three months ended ~~March 31,~~June 30, 2013largely due to production-related taxes. Higher natural gas and oil commodity market prices contributed approximately $3.5 million to the increase in production-related taxes and higher oil and natural gas liquids commodity production volumes contributed approximately ~~$0.4~~$0.9 million to the increase. Energen Resources' expense for taxes other than income taxes was $4.5 million higher in the six months ended June 30, 2013 largely due to production-related taxes. In the year-to-date, higher net commodity market prices contributed approximately $3.3 million to the increase in production-related taxes ~~partially offset by a decrease of~~and higher commodity production volumes contributed approximately ~~$0.2~~$1.3 million ~~primarily due~~ to ~~lower net commodity market prices.~~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 ~~$43.2~~$33.6 million for the quarter largely due to ~~higher~~the pass-through of gas costs and an increase in customer usage ~~partially offset by~~combined with adjustments from the utility’s rate setting mechanisms. During the ~~first~~second quarter of 2013, Alagasco had a net $~~2.4~~3.8 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the second quarter of 2012, Alagasco had a net $5.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the second quarter, weather that was ~~28.7~~312 percent colder than in the same quarter in the prior year contributed to ~~a 26~~an 82 percent increase in residential sales volumes and a ~~22.2~~34.9 percent rise in commercial and industrial customer sales volumes. Transportation volumes ~~increased~~ decreased 7.3 percent in period comparisons. Revenues for the year-to-date rose $76.8 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 year-to date 2013, Alagasco had a net $6.3

million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. In the 2012 year-to-date, Alagasco had a net reduction in revenues of $5.0 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 48.1 percent colder compared with the same period in the prior year contributed to a 36.9 percent increase in residential sales volumes and a 26 percent rise in commercial and industrial customer sales volumes. Transportation volumes decreased slightly in period comparisons. Higher gas costs combined with an increase in gas purchase volumes resulted in a ~~60.2~~248 percent increase in cost of gas for the ~~quarter.~~quarter and a 95.2 percent increase in cost of gas year-to-date. 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 11.6 percent~~fell slightly in the current quarter primarily due to higher labor-related costs (approximately ~~$1.9~~$1.1 million) which were offset by lower insurance costs (approximately $0.7 million) and decreased consulting and technology costs (approximately $0.5 million). In the six months ended June 30, 2013, O&M expense increased 5.4 percent largely due to increased labor-related costs (approximately $3 million), additional distribution operation expenses (approximately $1$0.6 million), and higher bad debt expense (approximately ~~$0.5~~$0.4 million) ~~and increased business development and marketing expense~~partially offset by lower insurance costs (approximately ~~$0.4~~$0.7 million).

A ~~2.7~~3.2 percent increase in depreciation expense in the current quarter and a 3 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 ~~$1.3~~$1.5 million in the ~~first~~second quarter of 2013 and $2.8 million year-to-date largely due to higher short-term borrowings. Income tax expense for the Company ~~increased $0.3~~decreased $27 million and $26.7 million in the current ~~quarter.~~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 $~~261.5~~539.8 million as compared to $~~231.0~~425.9 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 $~~309.4~~681.9 million for the ~~three~~six months ended ~~March 31,~~June 30, 2013 primarily due to additions of property, plant and equipment of ~~$310~~$684 million. Energen Resources incurred on a cash basis ~~$291~~$639 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $~~19.0~~44.7 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~~136.2 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.

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 million, including $795 million~~$1 billion, primarily all of which is for existing properties, including exploration to date of ~~$96~~$221 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.

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

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return of 13.15 percent to 13.65 percent on average common equity throughout the term of the Rate Stabilization and Equalization (RSE) order. The Company’s current RSE order has a term extending through December 31, 2014. At its March 2013 monthly meeting, the APSC announced the schedule for a series of public informal proceedings to review the Company’s RSE mechanism. The Company expects discussion topics to include allowed range of return on equity, the timing of term renewal and the term length of ~~renewals.~~renewal. The public proceedings are scheduled to occur onbeginning September 5, ~~September 25, October 9 and November 13,~~ 2013. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. 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~~$14.5 million, $14.2 million, $22.2 million and $2.7 million for the periods January through ~~March~~June 2013, January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $~~17.5~~16.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $~~41.4~~41.0 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~~June 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. The average customer count for the six months ending June 30, 2013 declined approximately 0.4 percent. 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~~six months ended ~~March 31,~~June 30, 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.

Alagasco maintains an investment in storage gas that is expected to average approximately ~~$28~~$26 million in 2013 but will vary depending upon the price of natural gas. During 2013, Alagasco plans to invest an estimated ~~$75~~$83 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 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, Alabama, and has been in service since the 1940's. The property is being classified as held-for sale and has a sales price isof approximately $14 million ~~and the~~. The sale is expected to close in August of 2013. The cash proceeds will offset the above capital expenditures for the utility and will result in an estimated $69 million net in cash capital expenditures. Effective upon closing, Alagasco plans to lease the facility from the purchaser for a period of approximately 18 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 31,~~June 30, 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~~twelve of its active counterparties and in a net ~~gain~~loss with the remaining ~~seven~~one at ~~March 31,~~June 30, 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 Contract

Price

Description

Total Hedged Volumes

Average Contract

Price

Description

Natural Gas

2013

9.4

Bcf

$4.83 Mcf

NYMEX Swaps

6.2

Bcf

$4.83 Mcf

NYMEX Swaps

24.4

Bcf

$4.56 Mcf

Basin Specific Swaps - San Juan

17.9

Bcf

$4.51 Mcf

Basin Specific Swaps - San Juan

2.5

Bcf*

$4.17 Mcf

Basin Specific Swaps - San Juan

3.1

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

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

9.7

Bcf

$3.81 Mcf

Basin Specific Swaps - Permian

2015

6.0

Bcf

$4.07 Mcf

Basin Specific Swaps - San Juan

Oil

2013

6,752

MBbl

$90.99 Bbl

NYMEX Swaps

4,603

MBbl

$91.07 Bbl

NYMEX Swaps

195

MBbl*

$101.00 Bbl

NYMEX Swaps

2014

9,796

MBbl

$92.64 Bbl

NYMEX Swaps

9,796

MBbl

$92.64 Bbl

NYMEX Swaps

2015

720

MBbl

$90.10 Bbl

NYMEX Swaps

720

MBbl

$90.10 Bbl

NYMEX Swaps

5,040

MBbl*

$88.67 Bbl

NYMEX Swaps

Oil Basis Differential

2013

2,701

MBbl

$(3.02) Bbl

WTS/WTI Basis Swaps**

1,811

MBbl

$(3.00) Bbl

WTS/WTI Basis Swaps**

2,995

MBbl

$(1.00) Bbl

WTI/WTI Basis Swaps***

2,053

MBbl

$(1.00) Bbl

WTI/WTI Basis Swaps***

Natural Gas Liquids

2013

33.9

MMGal

$1.02 Gal

Liquids Swaps

23.4

MMGal

$1.02 Gal

Liquids Swaps

* Contract entered into subsequent to March 31, 2013

* Contract entered into subsequent to June 30, 2013

**WTS - West Texas Sour/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.

3031

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									June 30, 2013
(in thousands)	Level 2*			Level 3*			Total			Level 2*			Level 3*		Total
Current assets	$	(12,452	)	$	23,142		$	10,690		$	8,108		$	37,973	$	46,081
Noncurrent assets	12,194			14,005			26,199			25,977			13,029		39,006
Current liabilities	(24,834		)	(7,965		)	(32,799		)	(12,635		)	129		(12,506		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)
Net derivative asset										$	21,450		$	51,131	$	72,581



	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 31,~~June 30, 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 $2826 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~~9.8 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.

At ~~March 31,~~June 30, 2013, the Company reported negative working capital of ~~$908.2~~$949.5 million arising from current liabilities of $~~1,273.0~~1,396.4 million exceeding current assets of $~~364.8~~446.9 million. The negative working capital is primarily due to a ~~$69~~$157 million in increase in borrowings during the ~~first quarter of~~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. Accordingly, the Company believes that it has adequate financing capacity available for its expected 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,~~June 30, 2013 include $~~10.7~~46.1 million and $~~32.8~~12.5 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~~16.3 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 31,~~June 30, 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 recognize~~recognized 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.

3233

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.

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or 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.

The 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 operations depend upon the use of third party facilities and an interruption of its ability to utilize these facilities may adversely affect its financial condition and results of operations: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Energen Resources, Alagasco and the Company.

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.

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.

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.

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 $ 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



SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended					Six months ended
	June 30,					June 30,
(in thousands, except sales price data)	2013		2012			2013		2012
Oil and Gas Operations
Operating revenues
Natural gas	$	98,572	$	68,249		$	169,644	$	143,829
Oil	262,775		306,960			424,587		431,274
Natural gas liquids	24,148		23,692			45,264		47,404
Other	48		567			1,042		918
Total	$	385,543	$	399,468		$	640,537	$	623,425
Non-cash mark-to-market gains (losses) included in operating revenues above
Natural gas	$	19,301	$	(245	)	$	14,926	$	38
Oil	36,680		118,844			28		76,924
Natural gas liquids	168		2,860			147		3,825
Total	$	56,149	$	121,459		$	15,101	$	80,787
Production volumes
Natural gas (MMcf)	18,420		19,278			36,108		38,370
Oil (MBbl)	2,595		2,195			4,912		4,148
Natural gas liquids (MMgal)	34.2		27.8			61.8		53.8
Total production volumes (MBOE)	6,480		6,069			12,401		11,824
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf)	$	4.30	$	3.55		$	4.28	$	3.75
Oil (barrel)	$	87.13	$	85.70		$	86.43	$	85.43
Natural gas liquids (gallon)	$	0.70	$	0.75		$	0.73	$	0.81
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.90	$	2.19		$	3.61	$	2.43
Oil (barrel)	$	90.62	$	85.70		$	86.77	$	91.77
Natural gas liquids (gallon)	$	0.61	$	0.71		$	0.64	$	0.83
Other data
Lease operating expense
Lease operating expense and other	$	72,027	$	58,779		$	153,573	$	115,391
Production taxes	17,606		13,205			31,969		27,367
Total	$	89,633	$	71,984		$	185,542	$	142,758
Depreciation, depletion and amortization	$	121,412	$	91,458		$	225,978	$	175,546
Asset impairment	$	—	$	—		$	—	$	21,545
Capital expenditures	$	349,879	$	293,909		$	634,932	$	634,876
Exploration expense	$	3,455	$	952		$	4,955	$	2,741
Operating income	$	144,031	$	216,406		$	170,358	$	242,411



Natural Gas Distribution
Operating revenues
Residential	$	65,551		$	40,371		$	228,291		$	170,879
Commercial and industrial	27,627			20,442			85,225			67,198
Transportation	13,824			13,661			32,064			29,259
Other	(2,488		)	(3,587		)	(3,381		)	(1,962		)
Total	$	104,514		$	70,887		$	342,199		$	265,374
Gas delivery volumes (MMcf)
Residential	3,613			1,985			13,995			10,223
Commercial and industrial	1,955			1,449			6,162			4,891
Transportation	10,706			11,547			23,496			23,583
Total	16,274			14,981			43,653			38,697
Other data
Depreciation and amortization	$	10,873		$	10,533		$	21,602		$	20,979
Capital expenditures	$	27,113		$	18,030		$	46,810		$	32,973
Operating income	$	2,219		$	4,448		$	81,512		$	83,008

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 31,~~June 30, 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 31,~~June 30, 2013, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at ~~March 31,~~June 30, 2013 was 1.37 percent. The Company's interest rate exposure on long-term debt as of ~~March 31,~~June 30, 2013, was minimal since approximately 91 percent of long-term debt obligations were at fixed rates.

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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 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)


(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 materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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 Plans
or 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
February 1, 2013 through February 28, 2013 —
—
—
8,992,700
March 1, 2013 through March 31, 2013 1,556
* 45.56
—
8,992,700
Total 1,556
$ 45.56
—
8,992,700



Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
April 1, 2013 through April 30, 2013	—		$	—	—	8,992,700
May 1, 2013 through May 31, 2013	505	*	54.57		—	8,992,700
June 1, 2013 through June 30, 2013	—		—		—	8,992,700
Total	505		$	54.57	—	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,~~June 30, 2013 are formatted in XBRL

4041

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 CORPORATION ALABAMA GAS CORPORATION

~~May 9,~~August 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,~~August 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,~~August 8, 2013	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation


~~May 9,~~August 8, 2013	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

4142