UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DCD.C. 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 ~~SEPTEMBER 30, 2013~~MARCH 31, 2014



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/~~(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~~Number of shares outstanding of each of the ~~issuers’~~registrant’s classes of common stock as of ~~November~~May 1, ~~2013~~2014.



Energen Corporation	$0.01 par value	~~72,685,415~~72,781,704 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 ~~SEPTEMBER 30, 2013~~MARCH 31, 2014

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	3027
	Selected Business Segment Data of Energen Corporation	4036
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	4238
Item 4.	Controls and Procedures	4339
PART II: OTHER INFORMATION
Item 1.	Legal Proceedings	4440
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4440
Item 6.	Exhibits	4440
SIGNATURES		4541

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


ENERGEN CORPORATION													ENERGEN CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF INCOME	CONSOLIDATED CONDENSED STATEMENTS OF INCOME												CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended						Three months ended
	September 30,						September 30,						March 31,
(in thousands, except per share data)	2013			2012			2013			2012			2014			2013
Operating Revenues
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339		$	297,278		$	236,331
Natural gas distribution	48,368			61,809			390,567			327,183			263,900			237,685
Total operating revenues	320,406			276,429			1,265,917			1,126,522			561,178			474,016
Operating Expenses
Cost of gas	20,435			20,924			163,448			94,179			128,114			95,442
Operations and maintenance	141,271			123,730			413,401			336,568			155,072			140,712
Depreciation, depletion and amortization	136,123			96,634			365,355			276,465			135,697			105,828
Taxes, other than income taxes	24,858			19,572			77,955			64,314			35,853			28,157
Accretion expense	1,771			1,605			5,187			4,691			1,843			1,687
Total operating expenses	324,458			262,465			1,025,346			776,217			456,579			371,826
Operating Income (Loss)	(4,052		)	13,964			240,571			350,305
Operating Income													104,599			102,190
Other Income (Expense)
Interest expense	(17,689		)	(17,195		)	(51,751		)	(48,447		)	(17,640		)	(16,752		)
Other income	13,062			1,488			15,578			3,678			1,384			1,734
Other expense	(434		)	(84		)	(631		)	(305		)	(54		)	(69		)
Total other expense	(5,061		)	(15,791		)	(36,804		)	(45,074		)	(16,310		)	(15,087		)
Income (Loss) From Continuing Operations Before Income Taxes	(9,113		)	(1,827		)	203,767			305,231
Income tax expense (benefit)	(3,627		)	(322		)	73,897			110,508
Income (Loss) From Continuing Operations	(5,486		)	(1,505		)	129,870			194,723
Discontinued Operations, net of taxes
Income From Continuing Operations Before Income Taxes													88,289			87,103
Income tax expense													32,797			32,409
Income From Continuing Operations													55,492			54,694
Discontinued Operations, net of tax
Income (loss) from discontinued operations	1,866			3,551			6,269			(3,984		)	(1,126		)	1,998
Loss on disposal of discontinued operations	(15,678		)	—			(15,678		)	—			(1,050		)	—
Income (Loss) From Discontinued Operations	(13,812		)	3,551			(9,409		)	(3,984		)	(2,176		)	1,998
Net Income (Loss)	$	(19,298	)	$	2,046		$	120,461		$	190,739
Net Income													$	53,316		$	56,692

Diluted Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.69
Continuing operations													$	0.76		$	0.75
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.05		)	(0.03		)	0.03
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Net Income													$	0.73		$	0.78
Basic Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.70
Continuing operations													$	0.76		$	0.76
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.06		)	(0.03		)	0.03
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Net Income													$	0.73		$	0.79
Dividends Per Common Share	$	0.145		$	0.140		$	0.435		$	0.420		$	0.150		$	0.145
Diluted Average Common Shares Outstanding	72,346			72,316			72,272			72,301			73,045			72,288
Basic Average Common Shares Outstanding	72,346			72,130			72,220			72,121			72,629			72,143

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

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
Three months ended Nine months ended
September 30, September 30,
(in thousands) 2013 2012 2013 2012
Net Income (Loss) $ (19,298 ) $ 2,046
$ 120,461
$ 190,739
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of commodity derivative instruments, net of tax of $42, ($30,622), ($6,669) and $30,621 69
(49,962 ) (10,882 ) 49,961
Reclassification adjustment for commodity derivative instruments, net of tax of ($3,205), ($4,924), ($11,486) and ($14,303) (5,229 ) (8,034 ) (18,740 ) (23,337 )
Current period change in fair value of interest rate swap, net of tax of ($188), ($375), ($23) and ($1,205) (350 ) (697 ) (42 ) (2,240 )
Reclassification adjustment for interest rate swap, net of tax of $156, $142, $449 and $422 290
263
833
783
Total cash flow hedges (5,220 ) (58,430 ) (28,831 ) 25,167
Pension and postretirement plans:

Amortization of net obligation at transition, net of taxes of $26, $25, $77 and $75 48
47
143
140
Amortization of prior service cost, net of taxes of $28, $30, $82 and $89 51
55
153
166
Amortization of net loss, including settlement charges, net of taxes of $729, $413, $2,383 and $1,238 1,354
766
4,425
2,300
Current period change in fair value of pension and postretirement plans, net of taxes of $2,238, ($4,073), $2,238 and ($4,073) 4,157
(7,564 ) 4,157
(7,564 )
Total pension and postretirement plans 5,610
(6,696 ) 8,878
(4,958 )
Comprehensive Income (Loss) $ (18,908 ) $ (63,080 ) $ 100,508
$ 210,948



ENERGEN CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three months ended
	March 31,
(in thousands)	2014			2013
Net Income	$	53,316		$	56,692
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of derivative commodity instruments, net of tax of $1 and ($16,424), respectively	2			(26,798		)
Reclassification adjustment for derivative commodity instruments, net of tax of ($1,541) and ($6,570), respectively	(2,513		)	(10,720		)
Current period change in fair value of interest rate swap, net of tax of ($62) and ($11), respectively	(115		)	(20		)
Reclassification adjustment for interest rate swap, net of tax of $157 and $143, respectively	289			266
Total cash flow hedges	(2,337		)	(37,272		)
Pension and postretirement plans:
Amortization of net obligation at transition, net of tax of $3 and $26, respectively	6			48
Amortization of prior service cost, net of tax of $26 and $27, respectively	48			51
Amortization of net loss, including settlement charges, net of tax of $2,994 and $920, respectively	5,559			1,709
Total pension and postretirement plans	5,613			1,808
Comprehensive Income	$	56,592		$	21,228

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


ENERGEN CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands)	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	12,413	$	9,704	$	35,343	$	5,555
Accounts receivable, net of allowance for doubtful accounts of $6,070 at September 30, 2013, and $6,549 at December 31, 2012	200,043		277,900
Accounts receivable, net of allowance for doubtful accounts of $5,684 and $5,694 at March 31, 2014 and December 31, 2013, respectively					299,118		257,545
Inventories
Storage gas inventory	39,507		32,205		19,444		32,095
Materials and supplies	19,187		28,291		16,071		16,601
Liquified natural gas in storage	2,990		3,498		1,381		3,634
Regulatory asset	11,213		45,515
Regulatory assets					1,283		2,756
Income tax receivable	7,653		6,664		848		5,765
Assets held for sale	183,862		—		1,871		51,104
Deferred income taxes	42,722		8,520		53,843		41,299
Prepayments and other	12,996		12,823		9,827		10,877
Total current assets	532,586		425,120		439,029		427,231
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,655,343		6,439,127		7,130,801		6,864,375
Less accumulated depreciation, depletion and amortization	1,657,682		1,765,241		1,898,950		1,776,802
Oil and gas properties, net	4,997,661		4,673,886		5,231,851		5,087,573
Utility plant	1,471,174		1,416,590		1,503,696		1,491,433
Less accumulated depreciation	594,604		573,947		615,519		605,924
Utility plant, net	876,570		842,643		888,177		885,509
Other property, net	29,733		25,107		33,690		30,556
Total property, plant and equipment, net	5,903,964		5,541,636		6,153,718		6,003,638
Other Assets
Regulatory asset	89,004		110,566
Regulatory assets					82,570		84,890
Other postretirement assets	17,417		1,404		35,769		35,351
Long-term derivative instruments	12,786		40,577		2,638		5,439
Deferred charges and other	59,115		56,587		66,666		65,663
Total other assets	178,322		209,134		187,643		191,343
TOTAL ASSETS	$	6,614,872	$	6,175,890	$	6,780,390	$	6,622,212

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


ENERGEN CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands, except share and per share data)	September 30, 2013			December 31, 2012			March 31, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	125,000		$	50,000		$	60,000		$	60,000
Notes payable to banks	901,000			643,000			575,000			539,000
Accounts payable	256,109			257,579			300,069			250,756
Accrued taxes	51,878			30,076			55,534			36,228
Customers’ deposits	20,531			24,705
Customer deposits							21,654			21,692
Amounts due customers	19,974			19,718			6,397			16,990
Accrued wages and benefits	25,896			24,984			17,758			33,884
Regulatory liability	40,168			45,116
Regulatory liabilities							80,698			49,006
Royalty payable	49,976			34,426			61,344			51,519
Liabilities related to assets held for sale	23,945			—			3,410			18,545
Other	26,812			30,178			28,620			32,273
Total current liabilities	1,541,289			1,159,782			1,210,484			1,109,893
Long-term debt	1,028,509			1,103,528			1,328,442			1,343,464
Deferred Credits and Other Liabilities
Asset retirement obligation	106,604			118,023
Pension and other postretirement liabilities	90,893			110,282
Regulatory liability	81,414			80,404
Asset retirement obligations							110,729			108,533
Pension liabilities							72,465			67,675
Regulatory liabilities							83,240			94,125
Long-term derivative instruments	1,961			11,305			1,011			398
Deferred income taxes	979,898			905,601			1,037,898			1,013,245
Other	14,638			10,275			24,994			26,860
Total deferred credits and other liabilities	1,275,408			1,235,890			1,330,337			1,310,836
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	—			—
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, 75,485,159 shares issued at September 30, 2013, and 75,067,760 shares issued at December 31, 2012	755			751
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,651,310 shares and 75,574,156 shares issued at March 31, 2014 and December 31, 2013, respectively							757			756
Premium on capital stock	514,784			492,108			528,632			520,909
Capital surplus	2,802			2,802			2,802			2,802
Retained earnings	2,403,062			2,314,055			2,519,025			2,476,616
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	16,730			46,352			10,851			13,362
Pension and postretirement plans	(43,629		)	(52,507		)	(26,632		)	(32,245		)
Interest rate swap	(1,365		)	(2,156		)	(1,010		)	(1,184		)
Deferred compensation plan	3,319			2,774			3,241			3,259
Treasury stock, at cost: 2,977,920 shares at September 30, 2013, and 2,998,620 shares at December 31, 2012	(126,792		)	(127,489		)
Treasury stock, at cost: 2,965,849 shares and 2,967,999 shares at March 31, 2014 and December 31, 2013, respectively							(126,539		)	(126,256		)
Total shareholders’ equity	2,769,666			2,676,690			2,911,127			2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,614,872		$	6,175,890		$	6,780,390		$	6,622,212

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


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

Nine months ended September 30, (in thousands)	2013			2012
Three months ended March 31, (in thousands)							2014			2013
Operating Activities
Net income	$	120,461		$	190,739		$	53,316		$	56,692
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	392,854			300,863			137,449			115,295
Asset impairment	24,612			21,545
Accretion expense	6,131			5,581			2,095			1,997
Deferred income taxes	51,682			80,724			10,531			29,028
Bad debt expense	1,203			370			461			218
Exploratory expense	8,759			11,420			1,277			541
Change in derivative fair value	53,581			(34,469		)	39,555			37,977
Gain on sale of assets	(10,980		)	(420		)
Stock based compensation expense	11,759			6,820
(Gain) loss on sale of assets							995			(656		)
Stock-based compensation expense							5,228			3,063
Other, net	25,455			10,779			15,716			7,839
Net change in:
Accounts receivable	50,767			57,334			(50,857		)	(35,312		)
Inventories	1,169			62			15,434			26,338
Accounts payable	(74,183		)	(12,562		)	30,842			9,670
Amounts due customers, including gas supply pass-through	36,891			(52,466		)	27,098			10,254
Income tax receivable	(989		)	1,817			4,917			4,781
Pension and other postretirement benefit contributions	(11,332		)	(5,056		)	(3,880		)	(10,334		)
Other current assets and liabilities	40,176			20,038			6,774			4,062
Net cash provided by operating activities	728,016			603,119			296,951			261,453
Investing Activities
Additions to property, plant and equipment	(961,798		)	(898,202		)	(282,334		)	(297,301		)
Acquisitions, net of cash acquired	(21,400		)	(104,200		)	(6,537		)	(13,146		)
Proceeds from sale of assets	16,220			2,420			8,019			1,370
Purchase of short-term investments							(84,000		)	—
Sale of short-term investments							84,000			—
Other, net	(1,210		)	(746		)	(122		)	(362		)
Net cash used in investing activities	(968,188		)	(1,000,728		)	(280,974		)	(309,439		)
Financing Activities
Payment of dividends on common stock	(31,454		)	(30,292		)	(10,907		)	(10,473		)
Issuance of common stock	13,680			1,164			3,060			—
Payment of long-term debt	(55		)	(1,143		)
Reduction of long-term debt							(15,028		)	(10		)
Net change in short-term debt	258,000			465,000			36,000			69,000
Tax benefit on stock compensation	2,710			514			686			68
Other	—			(38		)
Net cash provided by financing activities	242,881			435,205			13,811			58,585
Net change in cash and cash equivalents	2,709			37,596			29,788			10,599
Cash and cash equivalents at beginning of period	9,704			9,541			5,555			9,704
Cash and Cash Equivalents at End of Period	$	12,413		$	47,137
Cash and cash equivalents at end of period							$	35,343		$	20,303

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


ALABAMA GAS CORPORATION
CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Nine months ended						Three months ended
	September 30,						September 30,						March 31,
(in thousands)	2013			2012			2013			2012			2014			2013
Operating Revenues	$	48,368		$	61,809		$	390,567		$	327,183		$	263,900		$	237,685
Operating Expenses
Cost of gas	20,435			20,924			163,448			94,179			128,114			95,442
Operations and maintenance	33,650			37,235			107,672			107,470			36,224			38,017
Depreciation and amortization	11,063			10,572			32,665			31,551			11,325			10,729
Income taxes
Current	(7,703		)	(9,242		)	16,440			13,567			25,217			25,921
Deferred	2,093			3,264			6,448			9,431			1,267			3,020
Taxes, other than income taxes	5,764			5,821			27,814			23,718			15,886			14,204
Total operating expenses	65,302			68,574			354,487			279,916			218,033			187,333
Operating Income (Loss)	(16,934		)	(6,765		)	36,080			47,267
Operating Income													45,867			50,352
Other Income (Expense)
Allowance for funds used during construction	184			187			630			452			73			219
Other income	12,092			787			13,203			1,925			1,508			750
Other expense	(434		)	(84		)	(623		)	(254		)	(455		)	(69		)
Total other income	11,842			890			13,210			2,123			1,126			900
Interest Expense
Interest on long-term debt	3,377			3,423			10,133			10,270			3,376			3,378
Other interest expense	492			741			1,600			1,915			589			652
Total interest expense	3,869			4,164			11,733			12,185			3,965			4,030
Net Income (Loss)	$	(8,961	)	$	(10,039	)	$	37,557		$	37,205
Net Income													$	43,028		$	47,222

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


ALABAMA GAS CORPORATION
CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands)	September 30, 2013			December 31, 2012			March 31, 2014			December 31, 2013
ASSETS
Property, Plant and Equipment
Utility plant	$	1,471,174		$	1,416,590		$	1,503,696		$	1,491,433
Less accumulated depreciation	594,604			573,947			615,519			605,924
Utility plant, net	876,570			842,643			888,177			885,509
Other property, net	41			42			40			41
Current Assets
Cash and cash equivalents	8,541			5,559
Cash							34,069			3,032
Accounts receivable
Gas	39,962			94,011			109,601			103,301
Other	4,655			5,117			5,104			5,447
Affiliated companies	6,579			5,742			3,967			4,662
Allowance for doubtful accounts	(5,300		)	(5,700		)	(5,000		)	(5,000		)
Inventories
Storage gas inventory	39,507			32,205			19,444			32,095
Materials and supplies	5,401			5,528			5,188			5,471
Liquified natural gas in storage	2,990			3,498			1,381			3,634
Regulatory asset	11,213			45,515
Regulatory assets							1,283			2,756
Income tax receivable	1,601			2,762			—			3,644
Deferred income taxes	22,314			18,799			19,820			20,049
Prepayments and other	6,595			4,451			3,768			4,654
Total current assets	144,058			217,487			198,625			183,745
Other Assets
Regulatory asset	89,004			110,566
Pension and other postretirement assets	13,399			848
Regulatory assets							82,570			84,890
Other postretirement assets							26,813			26,457
Deferred charges and other	10,994			11,290			17,117			17,433
Total other assets	113,397			122,704			126,500			128,780
TOTAL ASSETS	$	1,134,066		$	1,182,876		$	1,213,342		$	1,198,075

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


ALABAMA GAS CORPORATION
CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands, except share data)	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
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 September 30, 2013 and December 31, 2012	20		20
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at March 31, 2014 and December 31, 2013					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	330,234		325,999		382,309		350,076
Total common shareholder’s equity	364,738		360,503		416,813		384,580
Long-term debt	249,973		250,028		249,895		249,923
Total capitalization	614,711		610,531		666,708		634,503
Current Liabilities
Notes payable to banks	49,000		77,000		—		50,000
Accounts payable	32,997		51,741		52,938		48,653
Accrued taxes	28,635		24,186		47,247		28,027
Customers’ deposits	20,531		24,705
Customer deposits					21,654		21,692
Amounts due customers	19,974		19,718		6,397		16,990
Accrued wages and benefits	8,154		6,703		6,343		7,682
Regulatory liability	40,168		45,116
Regulatory liabilities					80,698		49,006
Other	9,293		9,018		10,155		10,113
Total current liabilities	208,752		258,187		225,432		232,163
Deferred Credits and Other Liabilities
Deferred income taxes	199,372		189,381		206,669		205,631
Pension and other postretirement liabilities	28,371		43,611
Regulatory liability	81,414		80,404
Pension liabilities					19,982		20,191
Regulatory liabilities					83,240		94,125
Other	1,446		762		11,311		11,462
Total deferred credits and other liabilities	310,603		314,158		321,202		331,409
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,134,066	$	1,182,876	$	1,213,342	$	1,198,075

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


ALABAMA GAS CORPORATION
CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)

Nine months ended September 30, (in thousands)	2013			2012
Three months ended March 31, (in thousands)							2014			2013
Operating Activities
Net income	$	37,557		$	37,205		$	43,028		$	47,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	32,665			31,551			11,325			10,729
Deferred income taxes	6,448			9,431			1,267			3,020
Bad debt expense	1,120			364			466			217
Gain on sale of assets	10,889			—			(612		)	—
Other, net	1,524			4,681			1,902			3,685
Net change in:
Accounts receivable	19,801			29,539			(20,830		)	(23,409		)
Inventories	(6,667		)	5,975			15,187			23,317
Accounts payable	(16,181		)	(17,222		)	6,242			(11,306		)
Amounts due customers, including gas supply pass-through	36,891			(52,466		)	27,098			10,254
Income tax receivable	1,161			6,002			3,644			2,762
Pension and other postretirement benefit contributions	(5,848		)	(2,044		)	(1,590		)	(5,365		)
Other current assets and liabilities	(112		)	(9,795		)	18,769			24,183
Net cash provided by operating activities	119,248			43,221			105,896			85,309
Investing Activities
Additions to property, plant and equipment	(67,085		)	(49,746		)	(15,465		)	(19,046		)
Proceeds from sale of assets	13,838			—			706			—
Other, net	(1,642		)	2,490			723			886
Net cash used in investing activities	(54,889		)	(47,256		)	(14,036		)	(18,160		)
Financing Activities
Dividends	(33,322		)	(28,182		)
Payment of long-term debt	(55		)	(143		)
Net increases in advances from affiliates	—			24,867
Payment of dividends on common stock							(10,795		)	(8,438		)
Reduction of long-term debt							(28		)	(10		)
Net change in short-term debt	(28,000		)	10,000			(50,000		)	(47,000		)
Other	—			(38		)
Net cash provided by (used in) financing activities	(61,377		)	6,504
Net cash used in financing activities							(60,823		)	(55,448		)
Net change in cash and cash equivalents	2,982			2,469			31,037			11,701
Cash and cash equivalents at beginning of period	5,559			7,817			3,032			5,559
Cash and Cash Equivalents at End of Period	$	8,541		$	10,286
Cash and cash equivalents at end of period							$	34,069		$	17,260

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~~2013, ~~2011~~2012 and ~~2010~~2011, included in the ~~2012~~2013 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the nine months ended September 30, 2012 resulted in an increase of ~~$1.9 million~~ ~~and a decrease of~~ ~~$0.8 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 had no impact on 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. ~~The Company’s~~Alagasco’s current RSE order ~~had an original~~has a term extending through ~~December 31, 2014. At its meeting on November 5, 2013,~~September 30, 2018 and will continue beyond September 30, 2018, unless the APSC ~~voted~~enters an order to ~~make certain RSE~~the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, ~~effective~~if any. Effective January 1, 2014, ~~which are described as follows. The term of the order is extended through September 30, 2018.~~ Alagasco’s allowed range of return on average common equity ~~will be~~is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a ~~performance based~~performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus ~~1.75 percent~~ ~~and from a 2007 base year, adjusted for inflation using the Index Range. Alagasco expects these modifications to be included in a final written order in the fourth quarter of 2013.~~

~~Alagasco’s current allowed range of return on average common equity is~~ ~~13.15 percent~~ to ~~13.65 percent~~ ~~through December 31, 2013.~~ Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ~~and nine months~~ ended ~~September 30,~~March 31, 2014 and 2013, Alagasco had a net ~~$4.3 million~~pre-tax ~~and a net~~ ~~$10.6 million~~ ~~pre-tax, respectively, reduction~~reductions in revenues ~~to bring the return on average common equity to midpoint within the allowed range~~ of ~~return. Additionally, during the three months~~$16.2 million and ~~nine months ended September 30, 2013, Alagasco had a~~ ~~$10.9~~$2.4 million, ~~reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net~~ ~~$1.3 million~~ ~~and a net~~ ~~$6.3 million~~ ~~pre-tax,~~ respectively, ~~reduction in revenues~~ to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a ~~$7.8~~an $8.5 million decrease, $10.3 million increase and a ~~$13.0~~$7.8 million ~~annual~~ increase in revenues became effective January 1, 2014, December 1, ~~2012~~2013 and ~~2011~~2012, respectively.

~~RSE currently limits the utility’s~~ The equity upon which a return iswill be permitted to 55cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. ~~Currently, under the~~

The inflation-based ~~CCM~~Cost Control Mechanism (CCM), established by the APSC, ~~if the percentage change in~~allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense ~~on an aggregate basis~~(Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75 percent (Index Range). If rate year O&M expense falls within ~~a range of~~ ~~0.75~~ ~~points above or below~~ the ~~percentage change in the September~~ Index Range, ~~on a rate year basis,~~ no adjustment is required. If ~~the change in~~rate year O&M expense ~~on an aggregate basis~~ exceeds the Index Range, three-quarters of the difference is returned to ~~customers.~~customers through future rate adjustments. To the extent ~~the change~~that rate year O&M 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, 2013 and 2012.~~

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, ~~that~~which 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

~~Charges to~~ the ESR are subject to certain limitations which may disallow deferred treatment and which ~~proscribe~~prescribe 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~~expects to be able to recover 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, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids 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.~~ Such instruments may include over-the-counter (OTC) swaps and basis ~~hedges~~swaps typically executed with investment and commercial banks and energy-trading firms. ~~Hedge~~Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with ~~seven~~two of its active counterparties and in a net loss position with the remaining ~~six~~twelve at ~~September 30, 2013~~March 31, 2014. The largest counterparty net ~~loss~~gain position at ~~September 30, 2013~~March 31, 2014, ~~Morgan Stanley Capital Group,~~Macquarie Bank Limited, constituted approximately ~~$19.8~~$3.0 million of Energen Resources’ total net loss on fair value of derivatives. ~~At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately~~ ~~$10.0 million~~.

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~~ ~~September 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.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. 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 iswas recognized in accumulated 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 iswas required to be recognized in operating revenues immediately. All other derivative transactions not ~~previously qualified for~~designated as cash flow hedge accounting are ~~still considered by management to represent valid economic hedges and are~~ accounted for as mark-to-market ~~transactions. These derivatives are recorded at fair value~~transactions with gains or losses recognized in operating revenues in the period of change.

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

income until the forecasted transactions actually occur. ~~Any subsequent~~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 derivative commodity ~~contracts by business segment~~instruments on the balance sheets:


(in thousands)	September 30, 2013									March 31, 2014
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	53,082			$	—	$	53,082		$	17,522
Long-term asset derivative instruments	18,346				—		18,346			4,989
Total derivative assets	71,428				—		71,428			22,511
Accounts receivable	(40,789		)	*	—		(40,789		)	(14,165		)	*
Long-term asset derivative instruments	(5,560		)	*	—		(5,560		)	(2,351		)	*
Accounts payable	(31,928		)		—		(31,928		)	(52,602		)
Long-term liability derivative instruments	(1,379		)		—		(1,379		)	(802		)
Total derivative liabilities	(79,656		)		—		(79,656		)	(69,920		)
Total derivatives not designated	$	(8,228	)		$	—	$	(8,228	)	$	(47,409	)


(in thousands)	December 31, 2012										December 31, 2013
	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	$	87,514			$	—		$	87,514		$	36,224
Long-term asset derivative instruments	37,954				—			37,954			7,992
Total derivative assets	125,468				—			125,468			44,216
Accounts receivable	(37,326		)	*	—			(37,326		)	(18,761		)	*
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)	(2,553		)	*
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		)	(30,302		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)	(51,616		)
Total derivatives not designated	23,163				(2,593		)	20,570			$	(7,400	)
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 $~~10.3~~6.7 million and a net $~~28.4~~8.2 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~~accumulated other comprehensive income as of ~~September 30, 2013~~March 31, 2014, and December 31, ~~2012~~2013, 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
September 30, 2013 Three months
ended
September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622) — $ 69
$ (49,962 )
Gain reclassified from accumulated OCI into income (effective portion) Operating revenues $ 8,455
$ 15,998
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing) Operating revenues $ (22 ) $ (3,042 )

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



(in thousands)	Location on Statements of Income	Three months ended March 31, 2014		Three months ended March 31, 2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2	$	(26,798	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054	$	17,824
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—	$	(534	)

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 September 30, 2013			Three months ended September 30, 2012			Location on Statements of Income	Three months ended March 31, 2014			Three months ended March 31, 2013
Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)	Operating revenues	$	(57,446	)	$	(31,501	)

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

As of ~~September 30, 2013~~March 31, 2014, $~~13.1~~10.9 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of ~~September 30, 2013~~March 31, 2014, the Company had ~~13.5~~7.4 ~~billion cubic feet (Bcf),~~ ~~51.8~~ ~~Bcf~~million barrels (MMBbl) and ~~6.0~~7.3 ~~Bcf~~MMBbl of ~~natural gas hedges~~oil swaps which expire during ~~2013,~~ 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had ~~4.4~~44.9 ~~million barrels (MMBbl),~~ ~~9.8~~ ~~MMBbl~~billion cubic feet (Bcf) and ~~5.8~~12.0 ~~MMBbl~~Bcf of ~~oil~~natural gas and ~~oil~~natural gas basis ~~hedges~~swaps which expire during ~~2013,~~ 2014 and 2015, ~~respectively, that are considered mark-to-market transactions. The Company had~~ ~~11.9~~ ~~million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014,~~ respectively, that are considered mark-to-market transactions. During 2013, the Company ~~discontinued~~had a discontinuance of hedge accounting ~~and reclassified gains of~~ ~~$6.7 million~~ ~~after-tax from other comprehensive income into operating revenues~~ when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being ~~held for sale.~~sold. This discontinuance of hedge accounting resulted in $2.6 million after-tax losses being recognized into operating revenues during the three months ended March 31, 2014.

As of March 31, 2014, Energen Resources entered into the following transactions for the remainder of ~~2013~~2014 and subsequent years:

Production Period Total Hedged Volumes
Average Contract
Price

Description
Natural Gas
2013 3.0 Bcf $4.82 Mcf NYMEX Swaps
8.9 Bcf $4.51 Mcf Basin Specific Swaps - San Juan
1.6 Bcf $3.64 Mcf Basin Specific Swaps - Permian
2014 10.6 Bcf $4.55 Mcf NYMEX Swaps
31.4 Bcf $4.60 Mcf Basin Specific Swaps - San Juan
9.7 Bcf $3.81 Mcf Basin Specific Swaps - Permian
2015 6.0 Bcf $4.07 Mcf Basin Specific Swaps - San Juan
Oil
2013 2,434 MBbl $91.44 Bbl NYMEX Swaps
2014 9,796 MBbl $92.64 Bbl NYMEX Swaps
2015 5,760 MBbl $88.85 Bbl NYMEX Swaps
Oil Basis Differential
2013 907 MBbl $(2.99) Bbl WTS/WTI Basis Swaps*
1,070 MBbl $(1.00) Bbl WTI/WTI Basis Swaps**
Natural Gas Liquids
2013 12.0 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



Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
Natural Gas
2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	12.0	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
Natural Gas Basis Differential
2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps

As of ~~September 30, 2013~~March 31, 2014, 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:


	September 30, 2013								March 31, 2014
(in thousands)	Level 2*			Level 3*		Total			Level 2*			Level 3*			Total
Current assets	$	(12,712	)	$	25,005	$	12,293		$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	6,828			5,958		12,786			1,192			1,446			2,638
Current liabilities	(40,970		)	9,042		(31,928		)	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)	(802		)	—			(802		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)	$	(48,787	)	$	1,378		$	(47,409	)


	December 31, 2012									December 31, 2013
(in thousands)	Level 2*			Level 3*			Total			Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792		$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	18,899			21,678			40,577			4,383			1,056			5,439
Current liabilities	(2,593		)	—			(2,593		)	(28,414		)	(1,888		)	(30,302		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176
Net derivative asset (liability)										$	(25,689	)	$	18,289		$	(7,400	)

~~As of~~ ~~September 30, 2013, Alagasco had~~ no ~~derivative instruments. As of~~ ~~December 31, 2012, Alagasco had~~ ~~$2.6 million~~ ~~of derivative instruments which were classified as Level 2 fair values and 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 $2218 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $2218 million associated with open Level 3 mark-to-market

derivative contracts. ~~Cash flow~~Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

Three months ended Three months ended
(in thousands) September 30, 2013 September 30, 2012
Balance at beginning of period $ 51,131
$ 103,456
Realized gains 10,852
18,737
Unrealized losses relating to instruments held at the reporting date* (10,947 ) (46,983 )
Settlements during period (9,830 ) (17,929 )
Balance at end of period $ 41,206
$ 57,281


	Nine months ended			Nine months ended			Three months ended			Three months ended
(in thousands)	September 30, 2013			September 30, 2012			March 31, 2014			March 31, 2013
Balance at beginning of period	$	89,019		$	65,801		$	18,289		$	89,019
Realized gains	41,952			51,858
Realized gains (losses)							(3,019		)	27,107
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)	(16,835		)	(63,482		)
Settlements during period	(40,930		)	(51,050		)	2,943			(26,185		)
Balance at end of period	$	41,206		$	57,281		$	1,378		$	26,459

*Includes $~~0.8~~13.2 million and ~~$4.7~~$12.4 million ~~in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes~~ ~~$7.9 million~~ ~~and~~ ~~$4.5 million~~ in mark-to-market losses for the three months ended March 31, 2014 and ~~nine months ended September 30, 2012,~~2013, 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 September 30, 2013 Valuation Technique* Unobservable Input* Range
Natural Gas Basis - San Juan
2013 $ 9,499
Discounted Cash Flow Forward Basis ($0.12 - $0.14) Mcf
2014 $ 27,678
Discounted Cash Flow Forward Basis ($0.13 - $0.15) Mcf
2015 $ 1,201
Discounted Cash Flow Forward Basis ($0.20) Mcf
Natural Gas Basis - Permian
2013 $ 286
Discounted Cash Flow Forward Basis ($0.14) Mcf
2014 $ 825
Discounted Cash Flow Forward Basis ($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013 $ (1,897 ) Discounted Cash Flow Forward Basis ($1.06) Bbl
Oil Basis - WTI/WTI
2013 $ (641 ) Discounted Cash Flow Forward Basis ($0.41 - $0.50) Bbl
Natural Gas Liquids
2013 $ 4,255
Discounted Cash Flow Forward Price $0.74 - $0.81 Gal



(in thousands)	Fair Value as of March 31, 2014			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
Natural Gas Basis - Permian
2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf

*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:


	September 30, 2013													March 31, 2014
								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	$	71,428	$	(46,349	)	$	25,079	$	—	$	—	$	25,079	$	22,511	$	(16,516	)	$	5,995	$	—	$	—	$	5,995
Derivative liabilities	$	79,656	$	(46,349	)	$	33,307	$	—	$	—	$	33,307	$	69,920	$	(16,516	)	$	53,404	$	—	$	—	$	53,404


	December 31, 2012													December 31, 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	$	149,504	$	(44,135	)	$	105,369	$	—	$	—	$	105,369	$	44,215	$	(21,313	)	$	22,902	$	—	$	—	$	22,902
Derivative liabilities	$	56,328	$	(44,135	)	$	12,193	$	—	$	—	$	12,193	$	51,615	$	(21,313	)	$	30,302	$	—	$	—	$	30,302

1816

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

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

Non-vested restricted stock —
3

Diluted EPS $ (19,298 ) 72,346
$ (0.27 ) $ 2,046
72,316
$ 0.03

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


	Nine months ended					Nine months ended					Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2013					September 30, 2012					March 31, 2014					March 31, 2013
	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	$	120,461	72,220	$	1.67	$	190,739	72,121	$	2.64	$	53,316	72,629	$	0.73	$	56,692	72,143	$	0.79
Effect of dilutive securities
Stock options			41					177					296					144
Non-vested restricted stock			10					3					44					1
Performance share awards			1					—					76					—
Diluted EPS	$	120,461	72,272	$	1.67	$	190,739	72,301	$	2.64	$	53,316	73,045	$	0.73	$	56,692	72,288	$	0.78

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


	Three months ended September 30,		Nine months ended September 30,		Three months ended March 31,
(in thousands)	2013	2012	2013	2012	2014	2013
Stock options	—	850	875	850	111,554	988,087
Performance share awards	—	—	79	—	68,250	161,249

5. SEGMENT INFORMATION

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


	Three months ended						Nine months ended						Three months ended
	September 30,						September 30,						March 31,
(in thousands)	2013			2012			2013			2012			2014			2013
Operating revenues from continuing operations
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339		$	297,278		$	236,331
Natural gas distribution	48,368			61,809			390,567			327,183			263,900			237,685
Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522		$	561,178		$	474,016
Operating income (loss) from continuing operations
Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897		$	33,548		$	23,181
Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265			72,351			79,293
Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)	(1,300		)	(284		)
Total	$	(4,052	)	$	13,964		$	240,571		$	350,305		$	104,599		$	102,190
Other income (expense)
Other income (expense) from continuing operations
Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)	$	(13,819	)	$	(12,031	)
Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)	(2,839		)	(3,130		)
Eliminations and other	175			186			405			390			348			74
Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)	$	(16,310	)	$	(15,087	)
Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231
Income from continuing operations before income taxes													$	88,289		$	87,103


(in thousands)	September 30, 2013		December 31, 2012		March 31, 2014		December 31, 2013
Identifiable assets
Oil and gas operations	$	5,444,672	$	4,975,170	$	5,521,883	$	5,379,135
Natural gas distribution	1,127,487		1,177,134		1,209,375		1,193,413
Eliminations and other	42,713		23,586		49,132		49,664
Total	$	6,614,872	$	6,175,890	$	6,780,390	$	6,622,212

6. STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options and 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 iswas 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~~107,868 non-qualified option shares during the first quarter of ~~2013~~2014 with a grant-date fair value of $~~16.66~~27.57.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted ~~stock.~~stock units. In January ~~2013,~~2014, the Company awarded ~~46,121~~41,664 ~~shares of~~ restricted stock ~~were awarded~~units with a ~~grant date~~grant-date fair value of $~~48.36~~70.68. 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 provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued ~~in a~~using the Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted ~~84,311~~287 performance share awards during the first quarter of ~~2013~~2014 with a two year vesting period and a grant-date fair value of $~~59.19~~118.99. The Company also

granted ~~80,395~~63,842 performance share awards during the first quarter of ~~2013~~2014 with a three year award period and a grant-date fair value of $~~60.81~~93.13.

Stock Appreciation Rights Plan

The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company common 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~~62,749 awards during the first quarter of ~~2013.~~2014. These awards had a fair value of $~~39.10~~35.04 as of ~~September 30, 2013~~March 31, 2014.

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.~~and settle in cash at completion of the vesting period. During the first quarter of ~~2013,~~2014, Energen Resources awarded ~~33,796~~28,840 Petrotech units with a fair value of $~~75.67~~79.18 as of ~~September 30, 2013~~March 31, 2014, none of which included a market condition. Also awarded were ~~52,768~~36,920 Petrotech units which included a market condition and had a fair value of $~~133.58~~115.94 as of ~~September 30, 2013~~March 31, 2014. These awards have a three~~-year~~ year vesting period. ~~During the third quarter of 2013, Energen Resources awarded~~ ~~5,854~~ ~~Petrotech units with a three-year vesting period and a fair value of~~ ~~$75.67~~ ~~as of~~ ~~September 30, 2013, and~~ ~~2,952~~ ~~Petrotech units with a seventeen-month vesting period and a fair value of~~ ~~$75.88~~ ~~as of~~ ~~September 30, 2013, none of which included a market condition.~~

Stock Repurchase Program

During the three months ~~and nine months~~ ended ~~September 30, 2013~~March 31, 2014, the Company had ~~noncash~~non-cash purchases of approximately $~~0.8~~0.3 million ~~and~~ ~~$0.9 million, 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~~periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain ~~nonqualified~~non-qualified supplemental pension plans ~~were:~~were as follows:


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2013			2012			2013			2012			2014			2013
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	10,806		$	7,895		$	3,003		$	3,602
Interest cost	2,725			2,700			8,161			8,101			2,575			2,718
Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)	(2,848		)	(3,713		)
Actuarial loss	3,597			2,099			10,962			6,297
Actuarial loss amortization													2,256			3,690
Prior service cost amortization	123			129			367			388			118			122
Settlement charge	17			—			161			—			7,262			144
Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992		$	12,366		$	6,563

~~There are~~The Company anticipates required contributions of approximately no$0.5 million ~~required contributions~~during 2014 to the qualified pension ~~plans during 2013.~~plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. 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~~3.0 million to the qualified pension plans in January ~~2013. No additional discretionary contributions are expected to be made to the pension plans during 2013.~~2014. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months ~~and nine months~~ended ~~ending~~ ~~September 30, 2013~~March 31, 2014, the Company made benefit payments aggregating $~~0.2 million~~33,000 ~~and~~ ~~$1.1 million, respectively,~~ to retirees from the ~~nonqualified~~non-qualified supplemental retirement plans and expects to make additional benefit payments of approximately $~~36,000~~0.2 million through the remainder of ~~2013.~~2014. In the first quarter of 2014, the Company incurred a settlement charge of $17.1 million for the payment of lump sums from the qualified defined benefit pension plans, of which $6.9 million was expensed and $10.2 million was recognized as a pension asset in regulatory assets at Alagasco. Also in the first quarter of 2014, the Company incurred a settlement charge of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. 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~~non-qualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension ~~and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of~~ ~~$64,000~~ ~~for the payment of lump sums from the nonqualified supplemental retirement plans, of which~~ ~~$18,000~~ ~~was expensed and~~ ~~$46,000~~ ~~was recognized as a pension and postretirement~~ asset in regulatory assets at Alagasco.

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2013			2012			2013			2012			2014			2013
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	1,333		$	1,390		$	170		$	444
Interest cost	869			1,062			2,605			3,186			754			869
Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)	(1,412		)	(1,242		)
Actuarial loss	—			9			—			27
Transition amortization	324			479			973			1,438
Net periodic expense	$	395		$	904		$	1,184		$	2,713
Actuarial gain amortization													(520		)	—
Transition obligation amortization													27			324
Net periodic (income) expense													$	(981	)	$	395

~~For the~~ ~~three months and nine months~~ ~~ended~~ ~~September 30, 2013, the Company made~~There are no required contributions ~~aggregating~~ ~~$0.4 million~~ ~~and~~ ~~$1.2 million~~ ~~to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately~~ ~~$0.4 million~~ to the postretirement benefit plans ~~through the remainder of 2013.~~during 2014.

8. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for ~~third party~~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 ~~7.5~~6.4 million barrels of oil equivalent (MMBOE) through 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 ~~$14 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 $~~185~~150 million through September 2024. During ~~both~~ the ~~nine~~three months ~~ending~~ended ~~September 30, 2013~~March 31, 2014 and ~~2012,~~2013, Alagasco recognized approximately $~~36.8~~13.4 million and $14.4 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 ~~146~~123 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 ~~September 30, 2013~~March 31, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through ~~October~~December 2014 ~~and~~with an aggregate purchase price of ~~$0.8 million~~ ~~with a~~and market value of $~~0.8 million~~.

~~Income Taxes:~~ The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately ~~$35 million~~ ~~and would result in an additional deferred tax liability of~~ ~~$13~~0.3 million.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal ~~proceedings.~~proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. 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~~there is uncertainty in the valuation of pending claims and ~~its affiliates conduct business in jurisdictions in which the magnitude and frequency~~prediction 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~~On December 17, 2013, an incident occurred at a Housing Authority apartment complex in ~~progress currently,~~Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the ~~Company~~National Transportation Safety Board which is investigating the incident. Alagasco has ~~accrued~~been named as a ~~provision for estimated liability.~~defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

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

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 $~~1.8~~2.1 million of which $~~1.6~~1.9 million has been incurred and $0.2 million has been reserved.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

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),~~EPA, Alagasco and the current site owner.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the ~~EPA’s investigation of a site which it refers to as the 35~~35thth Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 3535thth Avenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a ~~potentially responsible party (PRP)~~PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a ~~PRP,~~PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and ~~an opportunity~~is considering whether to ~~discuss~~enter into such a tolling arrangement. Alagasco has not been provided information at this ~~designation further with EPA. Alagasco is unable~~time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of ~~September 30, 2013.~~March 31, 2014.

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 ~~September 30, 2013~~March 31, 2014.

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, was approximately $~~1,188.2~~1,421.2 million and $~~1,255.8~~1,420.7 million and ~~both~~ had a carrying value of $~~1,154.0~~1,388.9 million and $1,403.9 million at ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $~~262.8~~263.5 million and $~~284.7~~258.8 million and ~~both~~ had a carrying value of $~~250.0~~249.9 million at ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively. The fair values 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,~~At March 31, 2014, the Company ~~entered into~~had interest rate swap agreements ~~for~~with a notional of $200 million ~~of the Senior Term Loans.~~. The ~~swap agreements~~interest rate swaps exchange a variable interest rate for a fixed interest rate of ~~2.4175~~2.6675 ~~percent on~~ ~~$200 million~~ ~~of the principal amount outstanding.~~percent. The fair value of the Company’s interest rate swap was a $~~2.1~~1.6 million and a $~~3.3~~1.8 million liability at ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, 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 ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, Alagasco’s finance receivable totaled $~~10.8~~10.5 million and $~~10.7~~10.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 ~~months~~.months. Financing is available only to qualified customers who meet ~~credit worthiness~~creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. ~~Uncollected~~The remaining finance ~~receivables are~~receivable is written off approximately 1512 months after ~~the account has been final billed.~~being assigned to a third-party collection agency. Alagasco had finance receivables past due 90 days or more of $~~0.7~~0.3 million and $~~0.5~~0.4 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, 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
Allowance for credit losses as of December 31, 2013			$	423
Provision	191		(124		)
Allowance for credit losses as of September 30, 2013	$	661
Allowance for credit losses as of March 31, 2014			$	299

10. EXPLORATORY COSTS

The Company capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, the Company continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in oil and gas properties in the balance sheets. If the exploratory well is determined to be impaired, the impaired costs are charged to operations and maintenance expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:



	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
Additions pending determination of proved reserves	164,842			95,861
Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
Capitalized exploratory well costs at end of period	$	109,968		$	106,175

The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:



	Three months ended		Three months ended
(in thousands)	March 31, 2014		March 31, 2013
Exploratory wells in progress	$	62,280	$	21,676
Capitalized exploratory well costs capitalized for a period of one year or less	46,460		83,301
Capitalized exploratory well costs for a period greater than one year	1,228		1,198
Total capitalized exploratory well costs	$	109,968	$	106,175

At March 31, 2014, the Company had 45 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are primarily located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

2422

~~10.~~11. REGULATORY ASSETS AND LIABILITIES

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


(in thousands)	September 30, 2013				December 31, 2012				March 31, 2014				December 31, 2013
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension assets	$	263	$	69,249	$	170	$	90,708	$	1,258	$	56,133	$	325	$	58,243
Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
Risk management activities	—		—		2,593		—
Accretion and depreciation of asset retirement obligations									—		18,436		—		18,046
Rate recovery of asset removal costs, net	—		2,176		—		3,322		—		4,001		—		4,601
Enhanced stability reserve									—		4,000		—		4,000
Gas supply adjustment	10,925		—		42,726		—		—		—		2,406		—
Other	25		—		26		—		25		—		25		—
Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566	$	1,283	$	82,570	$	2,756	$	84,890
Regulatory liabilities:
RSE adjustment	$	6,573	$	—	$	1,740	$	—	$	16,193	$	—	$	4,690	$	—
Unbilled service margin	6,351		—		25,078		—		28,251		—		28,504		—
Postretirement liabilities	—		13,951		—		1,237		—		25,826		—		26,197
Gas supply adjustment									23,782		—		—		—
Refundable negative salvage	16,321		40,946		18,265		53,467		12,439		28,846		15,779		39,663
Gain on sale of property	10,890		—		—		—
Asset retirement obligation	—		25,772		—		24,930		—		27,840		—		27,528
Other	33		745		33		770		33		728		33		737
Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404	$	80,698	$	83,240	$	49,006	$	94,125

~~11.~~12. 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~~lives 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 ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

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

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



(in thousands)
Balance as of December 31, 2013	$	108,533
Liabilities incurred	766
Liabilities settled	(413		)
Accretion expense	1,843
Balance as of March 31, 2014	$	110,729

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 $~~25.8~~27.8 million and $~~24.9~~27.5 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $~~2.2~~4.0 million and $~~3.3~~4.6 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, 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.~~

13. ACQUISITION AND DISPOSITION OF PROPERTIES

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

~~13.~~During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.

14. 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	)
Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
Balance as of December 31, 2013										$	12,178		$	(32,245	)	$	(20,067	)
Other comprehensive loss before reclassifications										(113		)	—			(113		)
Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)	(2,224		)	5,613			3,389
Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)	(2,337		)	5,613			3,276
Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)
Balance as of March 31, 2014										$	9,841		$	(26,632	)	$	(16,791	)

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


	Three months ended			Nine months ended				Three months ended			Three months ended
	September 30, 2013			September 30, 2013				March 31, 2014			March 31, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	8,433		$	30,226		Operating revenues
Derivative commodity instruments								$	4,054		$	17,290		Operating revenues
Interest rate swap	(446		)	(1,282		)	Interest expense	(446		)	(409		)	Interest expense
Total cash flow hedges	7,987			28,944				3,608			16,881
Income tax expense	(3,048		)	(11,037		)		(1,384		)	(6,427		)
Net of tax	4,939			17,907				2,224			10,454
Pension and postretirement plans:
Transition obligation	(74		)	(220		)	Operations and maintenance	(10		)	(74		)	Operations and maintenance
Prior service cost	(78		)	(235		)	Operations and maintenance	(74		)	(78		)	Operations and maintenance
Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance	(1,290		)	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges								(7,262		)	—			Operations and maintenance
Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset	—			(375		)	Regulatory asset
Total pension and postretirement plans	(2,234		)	(7,263		)		(8,636		)	(2,781		)
Income tax expense	783			2,542
Income tax benefit								3,023			973
Net of tax	(1,451		)	(4,721		)		(5,613		)	(1,808		)
Total reclassifications for the period	$	3,488		$	13,186			$	(3,389	)	$	8,646

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

2624

~~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).

15. DISCONTINUED OPERATIONS

In ~~October 2013,~~March 2014, Energen Resources completed the sale ofon its ~~Black Warrior Basin coalbed methane~~North Louisiana/East Texas natural gas and oil properties ~~in Alabama~~ for ~~$160~~$30.3 million (subject to closing adjustments). ~~The Company will record a pre-tax gain on the sale of approximately~~ ~~$35 million~~ ~~in the fourth quarter of 2013.~~ The sale had an effective date of ~~July~~December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 ~~Bcf of natural gas.~~

During the third quarter of 2013, Energen Resources classified ~~its North Louisiana/East Texas~~these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued ~~operations and began marketing these assets.~~operations. Energen Resources recognized a non-cash impairment writedown on these properties in the ~~third~~first quarter of ~~2013~~2014 of ~~$24.6~~$1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on ~~expected future discounted cash flows.~~an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and ~~nine months ended September 30, 2013.~~fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. ~~This nonrecurring~~The impairment ~~writedown is~~writedowns are classified as Level 3 fair value. ~~The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations.~~ At December 31, ~~2012,~~2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 2023 Bcf of natural gas and 5191 MBbl of oil.

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

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

(in thousands) September 30, 2013
Black Warrior Basin North Louisiana/East Texas

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

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



(in thousands)	March 31, 2014
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	—		$	1,670		$	1,670
Inventories	—			68			68
Other property, net	—			133			133
Total assets held-for-sale	—			1,871			1,871
Accounts payable	(2,172		)	(10		)	(2,182		)
Royalty payable	—			(1,221		)	(1,221		)
Other current liabilities	—			(7		)	(7		)
Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)

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

2825


	Three months ended					Nine months ended						Three months ended
	September 30,											March 31,
(in thousands, except per share data)	2013			2012		2013			2012			2014			2013

Oil and gas revenues	$	18,258		$	18,895	$	55,483		$	57,601		$	4,821		$	18,663
Pretax income (loss) from discontinued operations	$	2,971		$	5,526	$	9,980		$	(6,028	)	$	(2,078	)	$	3,168
Income tax expense (benefit)	1,105			1,975		3,711			(2,044		)	(952		)	1,170
Income (Loss) From Discontinued Operations	$	1,866		$	3,551	$	6,269		$	(3,984	)	$	(1,126	)	$	1,998
Loss on disposal of discontinued operations	$	(24,612	)	$	—	$	(24,612	)	$	—		$	(1,667	)	$	—
Income tax benefit	(8,934		)	—		(8,934		)	—			(617		)	—
Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—	$	(15,678	)	$	—		$	(1,050	)	$	—
Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551	$	(9,409	)	$	(3,984	)	$	(2,176	)	$	1,998
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.05	)	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—			(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.05	)	$	(0.03	)	$	0.03
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.06	)	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—			(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.06	)	$	(0.03	)	$	0.03

16. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

17. SUBSEQUENT EVENTS

Due to the sale of Alagasco discussed above, the Company has separated its qualified defined benefit plans and the postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco. These separate plans will be remeasured effective April 30, 2014.

2926

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

RESULTS OF OPERATIONS

~~Energen had a~~Energen’s net ~~loss totaling~~income totaled $~~19.3~~53.3 million ($~~0.27~~0.73 per diluted share) for the three months ended ~~September 30, 2013~~March 31, 2014 compared with net income of $~~2.0~~56.7 million ($~~0.03~~0.78 per diluted share) for the same period in the prior year. In the ~~third~~first quarter of ~~2013,~~2014, Energen’s ~~loss~~income from continuing operations totaled $~~5.5~~55.5 million ($~~0.08~~0.76 per diluted share) and compared with ~~loss~~income from continuing operations of $~~1.5~~54.7 million ($~~0.02~~0.75 per diluted share) in the same period a year ago. Loss from discontinued operations for the current-quarter period was $~~13.8~~2.2 million as compared with income of $~~3.6~~2.0 million from the prior-year ~~third~~first quarter. Energen Resources Corporation, Energen’s oil and gas subsidiary, had a net ~~loss~~income for the three months ended ~~September 30, 2013~~March 31, 2014, of ~~$10.2~~$10.0 million as compared with a net ~~gain~~income of ~~$12.4~~$8.8 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of ~~$3.6~~$12.2 million in the current quarter as compared with ~~$8.8~~income of $6.8 million in the same quarter last year. This ~~decrease~~increase in net income from continuing operations was primarily the result of higher oil, natural gas liquids and natural gas production volumes (approximately $30 million after-tax), increased oil and natural gas commodity prices (approximately $5 million after-tax) and a year-over-year after-tax $4.4 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $21.5 million non-cash mark-to-market loss on derivatives for the first quarter of 2014 and an after-tax $26 million non-cash mark-to-market loss on derivatives for the first quarter of 2013). Negatively affecting net income was the impact of higher depreciation, depletion and amortization (DD&A) expense (approximately ~~$24 million after-tax), increased lease operating expense excluding production taxes (approximately $7~~$19 million after-tax), higher ~~administrative~~exploration expense (approximately $7 million after-tax), increased production taxes (approximately ~~$3 million after-tax), decreased natural gas liquids commodity prices (approximately $1~~$4 million after-tax), and a year-over-year after-tax $10 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $39.7 million non-cash mark-to-market loss on derivatives for the third quarter of 2013 and an after-tax $29.7 million non-cash mark-to-market loss on derivatives for the third quarter of 2012). Positively affecting net income was the impact of higher ~~natural gas, oil and natural gas liquids production volumes~~administrative expense (approximately ~~$31 million after-tax) and increased natural gas and oil commodity prices (approximately $16~~$3 million after-tax). Energen’s natural gas utility, Alagasco, reported a net ~~loss~~income of $~~9.0~~43.0 million in the ~~third~~first quarter of ~~2013~~2014 compared to net ~~loss~~income of $~~10.0~~47.2 million in the same period last year.

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

Oil and Gas Operations

Revenues from continuing oil and gas operations rose ~~26.8~~25.8 percent to $~~272.0~~297.3 million for the three months ended ~~September 30, 2013~~March 31, 2014 largely as a result of higher production volumes, ~~and~~ increased realized oil and natural gas ~~and oil~~ commodity prices and the non-cash mark-to-market increase in derivatives partially offset by ~~the non-cash mark-to-market decrease in derivatives combined with~~ decreased realized natural gas liquids commodity prices. ~~Revenues from continuing oil and gas operations rose 9.5 percent to~~ ~~$875.4 million~~ ~~for the nine months ended~~ ~~September 30, 2013~~ primarily as a result of significantly increased oil and natural gas liquids production volumes along with increased realized natural gas and oil commodity prices partially offset by lower natural gas production volumes, decreased realized natural gas liquids commodity prices and the non-cash mark-to-market decrease in derivatives. During the current quarter, revenue per unit of production for ~~natural gas increased 10.9~~oil rose 1.4 percent to ~~$4.06~~$86.86 per ~~thousand cubic feet (Mcf),~~barrel, while ~~oil revenue per unit of production rose 8.3 percent to $89.67 per barrel. Natural~~natural gas liquids revenue per unit of production fell ~~3.8~~2.6 percent to an average price of $0.75 per gallon. ~~In the year-to-date, revenue per unit of production for natural~~Natural gas ~~rose 13.7 percent to $4.14 per Mcf, oil~~ revenue per unit of production increased ~~3.7~~8.2 percent to ~~$87.59~~$4.51 per ~~barrel and natural gas liquids revenue per unit of production fell 7.5 percent to an average price of $0.74 per gallon.~~thousand cubic feet (Mcf). 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 from continuing operations 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 partially offset by normal production declines. ~~Natural gas production~~Oil volumes in the ~~third~~first quarter ~~rose 1.7~~increased 18.9 percent to ~~14.9 billion cubic feet (Bcf), oil volumes increased 21.5 percent to 2,764~~2,751 thousand barrels (MBbl) ~~and~~, natural gas liquids production rose ~~45.6~~37.3 percent to ~~36.7~~37.9 million gallons (MMgal)~~. For the year-to-date,~~ and natural gas production ~~declined 1.5~~in the first quarter rose 2.2 percent to ~~43.4 Bcf, while oil volumes rose 19.6 percent to 7,670 MBbl. Natural gas liquids production increased 24.7 percent to 98.5 MMgal.~~14.1 billion cubic feet (Bcf). Oil and natural gas liquids comprised approximately ~~59 percent and 58~~61 percent of Energen Resources’ production from continuing operations for the current ~~quarter and year-to-date, respectively.~~

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company reflects gains and losses on the disposition of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations for those sales that qualify for such reporting under generally accepted accounting standards. During the three months and nine months ended September 30, 2013, Energen Resources recorded in loss on disposal of discontinued operations a non-cash impairment writedown of ~~$24.6 million~~ pre-tax on certain natural gas and oil assets located in North Louisiana/East Texas. Energen Resources had no disposal of discontinued operations during the third quarter of 2012 or the year-to-date ended September 30, 2012. The Company includes gains and losses on the disposition of assets that do not qualify as discontinued operations in operating revenues. Energen Resources recorded a pre-tax loss of $37,000 in the third quarter of 2013 and a pre-tax gain of $0.1 million in the year-to-date from the sale of various Permian Basin properties. Energen Resources recorded a pre-tax gain of $0.1 million in the third quarter of 2012 and a pre-tax gain of $0.2 million year-to-date from the sale of various properties.quarter.

Operations and maintenance (O&M) expense increased ~~$21.2~~$15.1 million for the ~~quarter and $77.1 million for the year-to-date.~~quarter. Lease operating expense (excluding production taxes) generally reflects ~~year over year~~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 $11.7~~decreased $0.1 million for the quarter largely due to ~~additional~~lower ad valorem taxes (approximately $1.9 million) and decreased equipment rental expense (approximately $1.6 million) partially offset by higher workover and repair expense (approximately $5.5 million), higher water disposal costs (approximately $1.9 million), increased gathering costs (approximately $1.6 million), increased marketing and transportation costs (approximately $1.5 million), higher electrical costs (approximately $0.9 million) and additional equipment rental expense (approximately $0.9 million) partially offset by lower ad valorem taxes (approximately $2 million). In the year-to-date, lease operating expense (excluding production taxes) increased $51.4 million primarily due to increased workover and repair expense (approximately $21.5$1.4 million), additional ~~equipment rental~~other O&M expense (approximately $5.3 million), higher water disposal costs (approximately $5.3 million), increased gathering costs (approximately $3.8 million), higher marketing and transportation costs (approximately $2.9 million), increased ad valorem taxes (approximately $2.9 million), higher electrical costs (approximately $2.8 million), increased chemical and treatment costs (approximately $2.5$1.1 million) and increased ~~environmental compliance~~labor costs (approximately ~~$2.3~~$0.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was ~~$11.30~~$12.49 per barrel of oil equivalent (BOE) as compared to ~~$10.81~~$14.25 per BOE in the same period a year ago. ~~For the nine months ended September 30, 2013, the average lease operating expense (excluding production taxes) was $12.20 per BOE as compared to $10.17 per BOE in the previous period.~~ Administrative expense increased ~~$11.2~~$4.0 million for the three months ended ~~September 30, 2013~~March 31, 2014 largely due to increased costs from the Company’s benefit and performance-based compensation plans (approximately ~~$7.2~~$4.1 million), and higher labor costs (approximately ~~$2.2~~$1.7 million) ~~and increased~~partially offset by decreased legal expenses (approximately ~~$1.7~~$1.2 million). ~~For~~Exploration expense increased $11.3 million in the ~~nine months ended September 30, 2013, administrative expense rose $25.2 million~~first quarter of 2014 primarily due to ~~increased costs from the Company’s benefit~~higher delay rental payments and performance-based compensation plans (approximately $15.1 million), higher labor costs (approximately $7.2 million) and increased legal expenses (approximately $2 million). Exploration expense decreased $1.7 million in the third quarter of 2013 and rose $0.5 million year-to-date.seismic costs.

Energen Resources’ DD&A expense for the quarter rose ~~$39 million. For the year-to-date, Energen Resources’ DD&A expense increased $87.8~~$29.3 million. The average depletion rate for the current quarter was ~~$20.27~~$20.52 per BOE as compared to ~~$16.03~~$17.84 per BOE in the same period a year ago. ~~For the nine months ended September 30, 2013, the average depletion rate was $19.10 per BOE as compared to $15.49 per BOE, excluding the asset impairment, in the previous period.~~ The increase in the current quarter ~~and year-to-date~~ per unit DD&A rate, which contributed approximately ~~$25.9~~$16.1 million ~~and $62.2 million, respectively,~~ to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and ~~the impact from downward reserve revisions related to natural gas reserves at year-end.~~greater oil volumes as a percent of total production. Higher production volumes contributed approximately ~~$12.9 million and $25~~$13.1 million to the increase in DD&A expense for the ~~quarter and year-to-date, respectively.~~quarter.

Energen Resources’ expense for taxes other than income taxes was ~~$5.3 million and $9.5~~$6.0 million higher in the three months ~~and nine months~~ ended ~~September 30, 2013, respectively,~~March 31, 2014 largely due to production-related taxes. In the quarter, higher oil, natural gas liquids and ~~oil~~natural gas commodity market prices contributed approximately ~~$3.4~~$4.1 million to the increase in production-related taxes and ~~higher oil and natural gas liquids commodity~~increased production volumes contributed approximately ~~$2 million to the increase. In the year-to-date, higher net commodity market prices contributed approximately $5.6 million to the increase in production-related taxes and higher commodity~~

~~production volumes contributed approximately $4.1~~$1.9 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues ~~decreased $13.4~~increased $26.2 million for the quarter largely due to higher customer usage combined with an increase in the pass-through of gas costs partially offset by adjustments from the utility’s rate setting ~~mechanisms combined with a decrease in customer usage partially offset by a decrease in the pass-through of gas costs.~~mechanisms. During the ~~third~~first quarter of ~~2013,~~2014, Alagasco had a net ~~$4.3~~$16.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. ~~Additionally, during~~During the ~~three months and nine months ended September 30,~~first quarter of 2013, Alagasco had a ~~$10.9~~net $2.4 million ~~reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the third quarter of 2012, Alagasco had a net~~ ~~$1.3 million~~ pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the third quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes rose slightly while commercial and industrial customer sales volumes rose 2.1 percent. Transportation volumes fell slightly in period comparisons. Revenues for the year-to-date rose $63.4 million primarily due to the pass-through of gas costs along with additional customer usage partially offset by adjustments from the utility’s rate setting mechanisms. During the year-to-date 2013, Alagasco had a net ~~$10.6 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~~ ~~$6.3 million~~ ~~pre-tax to bring the return on average common equity to midpoint within the allowed range of return.~~ Weather, for the current ~~year-to-date,~~quarter, that was ~~48.1~~26.2 percent colder compared with the same period in the prior year contributed to a ~~32.6~~25.7 percent increase in residential sales volumes and a ~~21.1~~26.3 percent rise in commercial and industrial customer sales volumes. Transportation volumes decreased slightly in period comparisons. ~~Decreased~~Increased gas purchase volumes ~~partially offset by~~and higher gas costs resulted in a ~~2.3~~34.2 percent ~~decrease~~increase in cost of gas for the quarter. ~~For the year-to-date a significant increase in gas costs combined with higher gas purchase volumes resulted in a 73.6 percent increase in cost of gas.~~ 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~~cost 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 declined ~~9.6~~4.7 percent in the current quarter primarily due to lower distribution operation expenses (approximately $0.5 million) and decreased consulting and technology costs (approximately $0.5 million). In the nine months ended September 30, 2013, O&M expense increased slightly largely due to increased labor-related costs (approximately $3 million) and higher bad debt expense (approximately $0.8 million) partially offset by decreased consulting and technology expense (approximately $1 million) and lower insurance costs (approximately $0.8$1.9 million).

A ~~4.6~~5.6 percent increase in depreciation expense in the current quarter ~~and a 3.5 percent increase in the year-to-date~~ was primarily due to the extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company rose ~~$0.5~~$0.9 million in the ~~third~~first quarter of ~~2013 and $3.3 million year-to-date~~2014 largely due to ~~higher~~the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. The $600 million issuance includes $400 million with a floating rate of the London Interbank Offered Rate plus 1.625 percent, currently 1.778 percent at March 31, 2014 and $200 million swapped to a fixed rate at 2.6675 percent. These increases in interest expense for 2014 were partially offset by the October 2013 repayment of $50 million of 5 percent Notes, the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011 and lower short-term borrowings. ~~Other income for the Company increased $11.3 million for both the three months and nine months ended September 30, 2013 primarily due to the pre-tax gain of~~ ~~$10.9 million~~ ~~on the August 2013 sale of Alagasco’s Metro Operations Center.~~ Income tax expense for the Company ~~decreased $3.3 million and $36.6~~increased $0.4 million in the current quarter ~~and year-to-date, respectively,~~ largely due to ~~lower~~higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $~~728.0~~297.0 million as compared to $~~603.1~~261.5 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 $~~968.2~~281.0 million for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014 primarily due to additions of property, plant and equipment of ~~$983~~$289 million. Energen Resources incurred on a cash basis ~~$916~~$273 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Energen Resources had cash proceeds in the first quarter of $7.3 million primarily from the sale of the North Louisiana/East Texas properties. Utility capital expenditures on a cash basis totaled $~~67.1~~15.5 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 $~~242.9~~13.8 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders and the ~~issuance~~reduction of ~~common stock through the Company’s stock-based compensation plan.~~long-term debt for current maturities.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For ~~2013,~~2014, the Company expects its oil and gas capital spending to total approximately ~~$1.1~~$1.3 billion, primarily all of which is for existing ~~properties, including exploration to date of $321 million.~~properties. 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.~~marketplace. 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.

Discontinued Operations

In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

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

~~During~~Natural Gas Distribution

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the ~~third quarter~~assumption of ~~2013,~~$320 million in debt. This sale is expected to close during 2014. Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and as discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of ~~$24.6 million~~ ~~pre-tax~~plans to ~~adjust the carrying amount of these properties to their fair value based on expected future discounted~~use cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve-months and using the proceeds from the sale to ~~repay~~reduce long-term and short-term ~~obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/ East Texas properties totaled~~ 20 ~~Bcf of natural gas and~~ 51 ~~MBbl of oil.~~

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

~~Natural Gas Distribution~~

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. Alagasco’s current ~~allowed range of return on average common equity is~~ ~~13.15 percent~~ to ~~13.65 percent~~ ~~through December 31, 2013. The Company’s current~~ RSE order ~~had an original~~has a term extending through ~~December 31, 2014. At its meeting on November 5, 2013,~~September 30, 2018 and will continue beyond September 30, 2018, unless the APSC ~~voted~~enters an order to ~~make certain RSE~~the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, ~~effective~~if any. Effective January 1, 2014, ~~which are described as follows. The term of the order is extended through September 30, 2018.~~ Alagasco’s allowed range of return on average common equity ~~will be~~is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a ~~performance based~~performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted ~~will be~~cannot exceed 56.5 percent ~~with Alagasco allowed~~of total capitalization, subject to budget at the cap. Given existing economic conditions, Alagasco expects only modest growth in equity supporting Alagasco’s investment in its distribution system and support systems devoted to public service as annual dividends are typically paid by the utility.certain adjustments.

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 ~~$14.5~~$14.2 million, $16.3 million, $14.2 million, $22.2 million and $2.7 million for the periods January through ~~September~~March 2014, the years ended December 31, 2013, ~~January through December~~ 2012, ~~January through December~~ 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $~~16.3~~12.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $4128.8 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through 2019 through lower tariff ~~rates over a seven year period beginning January 1, 2013.~~rates. The total amount refundable to customers is subject to adjustments over the ~~entire nine~~remaining five year period for charges made to the Enhanced Stability Reserve ~~(ESR)~~ and

other ~~commission-approved~~APSC approved charges. The refunds as of ~~September 2013~~March 31, 2014 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

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

Alagasco maintains an investment in storage gas that is expected to average approximately ~~$26~~$40 million in ~~2013~~2014 but will vary depending upon the price of natural gas. During ~~2013,~~2014, Alagasco plans to invest ~~an estimated $91~~approximately $74 million in capital expenditures for the normal needs of its distribution, ~~and~~ support systems and ~~for~~ technology-related projects ~~designed~~and the construction of a service center to ~~improve customer service.~~replace the Metro Operations Center sold during 2013. 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.

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

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its ~~price~~ exposure to ~~its estimated~~price fluctuations on oil, natural gas liquids and natural gas ~~liquids~~ production. Such instruments may include over-the-counter (OTC) swaps ~~collars~~ and basis ~~hedges~~swaps typically executed with investment and commercial banks and energy-trading firms. At ~~September 30, 2013~~March 31, 2014, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with ~~seven~~two of its active counterparties and in a net loss position with the remaining ~~six~~twelve at ~~September 30, 2013~~March 31, 2014. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. ~~Hedge~~Derivative 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.

3430

Energen Resources entered into the following transactions for the remainder of ~~2013~~2014 and subsequent years:

Production Period

Total Hedged Volumes

Average Contract

Price

Description

Total Hedged Volumes

Average Contract

Price

Description

Natural Gas

2013

3.0

Bcf

$4.82 Mcf

NYMEX Swaps

8.9

Bcf

$4.51 Mcf

Basin Specific Swaps - San Juan

1.6

Bcf

$3.64 Mcf

Basin Specific Swaps - Permian

2014

10.6

Bcf

$4.55 Mcf

NYMEX Swaps

31.4

Bcf

$4.60 Mcf

Basin Specific Swaps - San Juan

9.7

Bcf

$3.81 Mcf

Basin Specific Swaps - Permian

2015

6.0

Bcf

$4.07 Mcf

Basin Specific Swaps - San Juan

Oil

2013

2,434

MBbl

$91.44 Bbl

NYMEX Swaps

2014

9,796

MBbl

$92.64 Bbl

NYMEX Swaps

7,392

MBbl

$92.65 Bbl

NYMEX Swaps

2015

5,760

MBbl

$88.85 Bbl

NYMEX Swaps

7,260

MBbl

$89.07 Bbl

NYMEX Swaps

2015

1,020

MBbl*

$90.99 Bbl

NYMEX Swaps

Oil Basis Differential

2013

907

MBbl

$(2.99) Bbl

WTS/WTI Basis Swaps*

1,070

MBbl

$(1.00) Bbl

WTI/WTI Basis Swaps**

2014

600

MBbl*

$(3.30) Bbl

WTS/WTI Basis Swaps**

2014

1,200

MBbl*

$(3.08) Bbl

WTI/WTI Basis Swaps***

Natural Gas Liquids

2013

12.0

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

2014

MBbl*

$0.93 Gal

Liquids Swaps

Natural Gas

2014

7.9

Bcf

$4.55 Mcf

NYMEX Swaps

2014

23.5

Bcf

$4.60 Mcf

Basin Specific Swaps - San Juan

2014

7.4

Bcf

$3.81 Mcf

Basin Specific Swaps - Permian

2015

12.0

Bcf

$4.05 Mcf

Basin Specific Swaps - San Juan

2015

11.0

Bcf*

$4.23 Mcf

Basin Specific Swaps - San Juan

2015

6.0

Bcf*

$4.20 Mcf

Basin Specific Swaps - Permian

Natural Gas Basis Differential

2014

4.6

Bcf

$(0.09) Mcf

San Juan Basis Swaps

2014

1.5

Bcf

$(0.17) Mcf

Permian Basis Swaps

*Contract entered into subsequent to March 31, 2014

**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.

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:


	September 30, 2013								March 31, 2014
(in thousands)	Level 2*			Level 3*		Total			Level 2*			Level 3*			Total
Current assets	$	(12,712	)	$	25,005	$	12,293		$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	6,828			5,958		12,786			1,192			1,446			2,638
Current liabilities	(40,970		)	9,042		(31,928		)	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)	(802		)	—			(802		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)	$	(48,787	)	$	1,378		$	(47,409	)

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

3531



	December 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

~~As of~~ ~~September 30, 2013, Alagasco had no derivative instruments. As of~~ ~~December 31, 2012, Alagasco had~~ ~~$2.6 million~~ of derivative instruments which were classified as Level 2 fair values and included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of ~~December 31, 2012~~.

Level 3 assets and liabilities as of ~~September 30, 2013~~March 31, 2014, 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 $2218 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $2218 million associated with open Level 3 mark-to-market derivative contracts. ~~Cash flow~~Liquidity 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. However, the Company could experience increased costs and reduced liquidity in the markets as a result of the new rules and regulations, which could reduce hedging opportunities and negatively affect the Company’s revenues and cash flows.

Credit Facilities and Working Capital

On October 30, 2012, Energen and Alagasco entered into ~~$1,250 million~~$1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. ~~Energen~~Energen’s obligations under the ~~$1,250 million~~$1.25 billion 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 ~~September 30, 2013,~~March 31, 2014, the Company reported negative working capital of $~~1,008.7~~771.5 million arising from current liabilities of $~~1,541.3~~1,210.5 million exceeding current assets of $~~532.6~~439.0 million. The negative working capital is primarily due to a $~~258~~36 million increase in borrowings during the ~~year-to-date 2013~~three months ended March 31, 2014 and a $628 million increase in borrowings during 2012 partially offset by a $104 million decrease in borrowings during 2013 under the syndicated ~~unsecured~~ credit facilities and in support of Energen’s capital projects. Generally ~~Accepted Accounting Principles~~accepted accounting principles require short-term classification ~~as short term~~ for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated ~~unsecured~~ credit facilities were entered into on October 30, 2012 and have a five-year term. ~~In addition, Energen Resources received~~ ~~$160 million~~ (subject to closing adjustments) on the sale of its Black Warrior Basin coalbed methane properties in October 2013. Accordingly, the Company believes that it has adequate financing capacity available for its expected liquidity needs.

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 ~~September 30, 2013~~March 31, 2014 include $~~12.3~~3.4 million and $~~31.9~~52.6 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 $~~16.3~~12.4 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 their syndicated ~~unsecured~~ credit facilities to fund working capital needs. Negative working capital is expected to be positively impacted from the sale of Alagasco as previously discussed.

Credit Ratings

On April ~~26, 2013,~~8, 2014, following the announced sale of Alagasco, Moody’s ~~Investor~~Investors Service ~~updated its credit opinion for Energen and Alagasco confirming~~lowered Energen’s senior unsecured credit rating ~~as investment grade~~from Baa3 to Ba1 with a negative outlook. Alagasco’s senior unsecured credit rating, ~~was~~which is investment grade with a negative outlook, has been placed under review. On December 16, 2013, Standard & Poor’s (S&P) lowered ~~one notch but remains~~its credit ratings for Energen and Alagasco from investment grade with a stable outlook to investment grade with a negative outlook. On April 9, 2014, S&P placed

Energen and ~~Alagasco’s debt ratings by Standard & Poor’s are considered investment grade~~Alagasco on CreditWatch with ~~a stable outlook.~~negative implications for Energen and positive implications for Alagasco. S&P expects to resolve the CreditWatch around the time of the close of the sale of Alagasco.

Dividends

~~Energen expects to pay annual cash dividends~~Energen’s dividend policy is under review in connection with the pending sale of ~~$0.58~~Alagasco. Dividends for the first quarter of 2014 were $0.15 per share on the Company’s common stock ~~in 2013.~~and a $0.15 per share dividend has been declared for the second quarter of 2014. Subsequent to the sale of Alagasco, the Company expects to substantially reduce the amount of its dividend payments with a focus on further development and exploration of its oil and natural gas properties. 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~~There have been no material changes to the contractual cash obligations of the Company since December 31, ~~2012.~~2013.

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 ~~September 30, 2013~~March 31, 2014.

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 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,~~16, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

~~FORWARD LOOKING~~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, natural gas liquids 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, the proposed sale of Alagasco to The Laclede Group, Inc., 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 liquids 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, natural gas liquids 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, natural gas liquids 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 natural gas operations primarily are generated from the sale of produced oil, natural gas liquids 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~~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~~third-party facilities. These facilities include ~~third party~~third-party oil and natural 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 natural 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 natural gas production activities of Energen Resources and the natural 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.

Successful completion of the Company’s pending sale of Alagasco is subject to various risks and conditions: In April 2014, the Company signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. The Company plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness. The sale of Alagasco involves various inherent risks, such as the Company’s ability to obtain regulatory approvals from the Alabama Public Service Commission and under the Hart-Scott-Rodino Antitrust Improvement Act; the timing of and conditions imposed upon the Company by regulators in connection with such approvals; and satisfaction by the parties of contractual conditions to closing.

3935


SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended						Three months ended
	September 30,						September 30,						March 31,
(in thousands, except sales price data)	2013			2012			2013			2012			2014			2013
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	62,073		$	49,422		$	196,311		$	156,308
Oil	183,950			147,710			607,975			578,167			$	217,493		$	161,551
Natural gas liquids	26,292			17,566			71,556			64,970			28,686			21,116
Natural gas													51,252			53,216
Other	(277)			(78)			(492		)	(106		)	(153)			448
Total	$	272,038		$	214,620		$	875,350		$	799,339		$	297,278		$	236,331
Non-cash mark-to-market gains (losses) included in operating revenues from continuing operations above
Natural gas	$	1,684		$	(4,159	)	$	16,610		$	(4,121	)
Non-cash mark-to-market gains (losses) (included in operating revenues from continuing operations above)													Non-cash mark-to-market gains (losses) (included in operating revenues from continuing operations above)
Oil	(63,889		)	(40,569		)	(63,861		)	36,355			$	(21,464	)	$	(36,652	)
Natural gas liquids	(1,355		)	(2,024		)	(1,208		)	1,801			287			(21		)
Natural gas													(12,504		)	(4,375		)
Total	$	(63,560	)	$	(46,752	)	$	(48,459	)	$	34,035		$	(33,681	)	$	(41,048	)
Production volumes from continuing operations
Natural gas (MMcf)	14,868			14,622			43,428			44,076
Oil (MBbl)	2,764			2,275			7,670			6,414			2,751			2,314
Natural gas liquids (MMgal)	36.7			25.2			98.5			79.0			37.9			27.6
Natural gas (MMcf)													14,124			13,818
Production volumes from continuing operations (MBOE)	6,116			5,312			17,253			15,641			6,008			5,273
Total production volumes (MBOE)	6,758			6,026			19,159			17,850			6,162			5,921
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf)	$	4.06		$	3.66		$	4.14		$	3.64
Oil (barrel)	$	89.67		$	82.76		$	87.59		$	84.47
Natural gas liquids (gallon)	$	0.75		$	0.78		$	0.74		$	0.80
Oil (per barrel)													$	86.86		$	85.65
Natural gas liquids (per gallon)													$	0.75		$	0.77
Natural gas (per Mcf)													$	4.51		$	4.17
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.39		$	2.69		$	3.51		$	2.51
Oil (barrel)	$	103.22		$	86.55		$	92.69		$	89.92
Natural gas liquids (gallon)	$	0.68		$	0.68		$	0.65		$	0.78
Oil (per barrel)													$	92.24		$	82.44
Natural gas liquids (per gallon)													$	0.74		$	0.68
Natural gas (per Mcf)													$	4.88		$	3.29
Other data from continuing operations
Lease operating expense
Lease operating expense and other	$	69,086		$	57,397		$	210,455		$	159,052		$	75,012		$	75,155
Production taxes	18,939			13,531			49,598			39,882			19,756			13,763
Total	$	88,025		$	70,928		$	260,053		$	198,934		$	94,768		$	88,918
Depreciation, depletion and amortization	$	125,060		$	86,062		$	332,690		$	244,914		$	124,372		$	95,099
Capital expenditures	$	257,759		$	323,037		$	892,691		$	957,913		$	271,696		$	285,053
Exploration expense	$	8,949		$	10,644		$	13,902		$	13,382		$	12,814		$	1,498
Operating income	$	18,607		$	26,913		$	181,948		$	280,897		$	33,548		$	23,181

4036


Natural Gas Distribution
Operating revenues
Residential	$	31,201		$	30,658		$	259,492		$	201,537		$	191,611		$	162,739
Commercial and industrial	18,194			17,695			103,419			84,889			68,992			57,599
Transportation	13,197			13,505			45,261			42,765			18,034			18,240
Other	(14,224		)	(49		)	(17,605		)	(2,008		)	(14,737		)	(893		)
Total	$	48,368		$	61,809		$	390,567		$	327,183		$	263,900		$	237,685
Gas delivery volumes (MMcf)
Residential	1,384			1,378			15,379			11,601			13,053			10,382
Commercial and industrial	1,272			1,246			7,434			6,137			5,315			4,207
Transportation	11,237			11,252			34,733			34,835			12,782			12,790
Total	13,893			13,876			57,546			52,573			31,150			27,379
Other data
Depreciation and amortization	$	11,063		$	10,572		$	32,665		$	31,551		$	11,325		$	10,729
Capital expenditures	$	20,980		$	18,813		$	67,790		$	51,786		$	13,594		$	19,697
Operating income (loss)	$	(22,544	)	$	(12,743	)	$	58,968		$	70,265
Operating income													$	72,351		$	79,293

4137

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energen Resources’ major market risk exposure is in the pricing applicable to its oil and natural gas production. Historically, prices received for oil and natural 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 the 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~~on oil, natural gas liquids 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~~swaps typically executed with ~~major energy derivative product specialists.~~investment and commercial banks and energy-trading firms. 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 hedge, as well as its risk management objective and strategy for undertaking the hedge. As of ~~September 30, 2013~~March 31, 2014, 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 ~~September 30, 2013~~March 31, 2014, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at ~~September 30, 2013~~March 31, 2014 was ~~1.36~~1.40 percent. The Company’s interest rate exposure on long-term debt as of ~~September 30, 2013~~March 31, 2014, was minimal since approximately 9186 percent of long-term debt obligations were at fixed rates.

4238

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)	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)

~~financial reporting which is described below.~~

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

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

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


(b)	~~As described above in (a)~~During the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting ~~during the most recent fiscal quarter covered by this report.~~that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

4339

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

~~Under oversight~~Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of ~~the Site Remediation Section of the Railroad Commission of Texas, the Company is currently~~these lawsuits include claims for punitive damages in ~~the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate~~ ~~$1.8 million~~ ~~of which~~ ~~$1.6 million~~ ~~has been incurred and~~ ~~$0.2 million~~ ~~has been reserved.~~

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

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

ITEM 1A. RISK FACTORS

Except as discussed below, there have been no material changes to the risk factors of the Company since December 31, 2013.

Successful completion of the Company’s pending sale of Alagasco is subject to various risks and conditions:In April 2014, the Company signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. The Company plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness. The sale of Alagasco involves various inherent risks, such as the Company’s ability to obtain regulatory approvals from the Alabama Public Service Commission and under the Hart-Scott-Rodino Antitrust Improvement Act; the timing of and conditions imposed upon the Company by regulators in connection with such approvals; and satisfaction by the parties of contractual conditions to closing.

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**
July 1, 2013 through July 31, 2013 29
* $ 53.32
—
8,992,700
August 1, 2013 through August 31, 2013 6,751
* 65.31
—
8,992,700
September 1, 2013 through September 30, 2013 5,418
* 73.96
—
8,992,700
Total 12,198
$ 69.12
—
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	Maximum Number of Shares that May Yet Be Purchased Under the Plans**
January 1, 2014 through January 31, 2014	—		$	—	—	8,992,700
February 1, 2014 through February 28, 2014	1,742	*	69.62		—	8,992,700
March 1, 2014 through March 31, 2014	2,230	*	81.03		—	8,992,700
Total	3,972		$	76.03	—	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



10	-	Stock Purchase Agreement, dated as of April 5, 2014, by and among The Laclede Group, Inc., Energen Corporation and Alabama Gas Corporation, which was filed as Exhibit 2.1 to Energen’s and Alabama Gas Corporation’s Current Report on Form 8-K filed April 7, 2014
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, 2014 are formated in XBRL
			~~quarter ended September 30, 2013 are formatted in XBRL~~

SIGNATURES

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



		ENERGEN CORPORATION ALABAMA GAS CORPORATION

~~November 8, 2013~~May 9, 2014	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


~~November 8, 2013~~May 9, 2014	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation


~~November 8, 2013~~May 9, 2014	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation


~~November 8, 2013~~May 9, 2014	By	/s/ Leonarda M. DiChiara
		Leonarda M. DiChiara
		Vice President and Controller of Alabama Gas Corporation

4541



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



(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
Oil Basis - WTI/WTI
2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
Natural Gas Liquids
2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal