Energen 10Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______________ TO _______________



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

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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



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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of July 27, 2011.



Energen Corporation	$0.01 par value	72,078,908 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 JUNE 30, 2011

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 Balance Sheets of Energen Corporation	4
	(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation	6
	(d) Condensed Statements of Income of Alabama Gas Corporation	7
	(e) Condensed Balance Sheets of Alabama Gas Corporation	8
	(f) Condensed Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Condensed Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
	Selected Business Segment Data of Energen Corporation	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	39
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6.	Exhibits	40
SIGNATURES		41

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Six months ended
	June 30,						June 30,
(in thousands, except per share data)	2011			2010			2011			2010
Operating Revenues
Oil and gas operations	$	244,090		$	234,586		$	460,882		$	472,200
Natural gas distribution	86,309			99,139			355,881			436,439
Total operating revenues	330,399			333,725			816,763			908,639
Operating Expenses
Cost of gas	32,419			43,234			164,168			240,390
Operations and maintenance	103,232			109,945			207,014			201,647
Depreciation, depletion and amortization	65,629			62,476			126,757			124,211
Taxes, other than income taxes	21,095			18,256			49,270			48,893
Accretion expense	1,689			1,521			3,338			3,007
Total operating expenses	224,064			235,432			550,547			618,148
Operating Income	106,335			98,293			266,216			290,491
Other Income (Expense)
Interest expense	(9,463		)	(9,844		)	(18,867		)	(19,804		)
Other income	779			385			2,009			723
Other expense	(113		)	(1,346		)	(276		)	(870		)
Total other expense	(8,797		)	(10,805		)	(17,134		)	(19,951		)
Income Before Income Taxes	97,538			87,488			249,082			270,540
Income tax expense	34,213			31,945			91,489			98,287
Net Income	$	63,325		$	55,543		$	157,593		$	172,253
Diluted Earnings Per Average Common Share	$	0.87		$	0.77		$	2.18		$	2.39
Basic Earnings Per Average Common Share	$	0.88		$	0.77		$	2.19		$	2.40
Dividends Per Common Share	$	0.135		$	0.130		$	0.270		$	0.260
Diluted Average Common Shares Outstanding	72,420			72,089			72,364			72,069
Basic Average Common Shares Outstanding	72,065			71,844			72,033			71,830

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



CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands)	June 30, 2011		December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	15,432	$	22,659
Accounts receivable, net of allowance for doubtful accounts of $13,558 at June 30, 2011, and $15,048 at December 31, 2010	164,031		286,849
Inventories
Storage gas inventory	34,632		36,706
Materials and supplies	27,038		19,045
Liquified natural gas in storage	3,693		3,551
Regulatory asset	32,563		28,286
Income tax receivable	5,264		44,489
Deferred income taxes	49,930		32,732
Prepayments and other	10,353		11,966
Total current assets	342,936		486,283
Property, Plant and Equipment
Oil and gas properties, successful efforts method	4,461,460		4,080,779
Less accumulated depreciation, depletion and amortization	1,256,178		1,161,635
Oil and gas properties, net	3,205,282		2,919,144
Utility plant	1,322,695		1,292,611
Less accumulated depreciation	523,051		509,989
Utility plant, net	799,644		782,622
Other property, net	23,117		17,461
Total property, plant and equipment, net	4,028,043		3,719,227
Other Assets
Regulatory asset	89,465		105,365
Pension and other postretirement assets	11,947		13,907
Long-term derivative instruments	1,002		—
Deferred charges and other	38,001		38,778
Total other assets	140,415		158,050
TOTAL ASSETS	$	4,511,394	$	4,363,560

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



CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands, except share and per share data)	June 30, 2011			December 31, 2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	5,000		$	5,000
Notes payable to banks	302,000			305,000
Accounts payable	263,142			268,214
Accrued taxes	42,783			52,845
Customers' deposits	21,471			20,459
Amounts due customers	10,407			20,161
Accrued wages and benefits	27,985			25,203
Regulatory liability	65,024			75,703
Royalty payable	23,228			19,221
Other	23,275			26,805
Total current liabilities	784,315			818,611
Long-term debt	404,980			405,254
Deferred Credits and Other Liabilities
Asset retirement obligation	102,120			97,415
Pension and other postretirement liabilities	34,248			36,551
Regulatory liability	92,951			110,447
Long-term derivative instruments	128,505			112,936
Deferred income taxes	697,540			615,084
Other	9,297			13,219
Total deferred credits and other liabilities	1,064,661			985,652
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,989,460 shares issued at June 30, 2011, and 74,786,376 shares issued at December 31, 2010	750			748
Premium on capital stock	480,559			468,934
Capital surplus	2,802			2,802
Retained earnings	2,018,318			1,880,183
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges, net	(90,738		)	(43,667		)
Pension and postretirement plans	(29,365		)	(30,730		)
Deferred compensation plan	3,468			3,288
Treasury stock, at cost; 3,036,997 shares at June 30, 2011, and 3,024,847 shares at December 31, 2010	(128,356		)	(127,515		)
Total shareholders' equity	2,257,438			2,154,043
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,511,394		$	4,363,560

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



CONSOLIDATED CONDENSED STATEMENS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)

Six months ended June 30, (in thousands)	2011			2010
Operating Activities
Net income	$	157,593		$	172,253
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	126,757			124,211
Accretion expense	3,338			3,007
Deferred income taxes	75,409			37,499
Bad debt expense	2,673			(237		)
Exploratory expense	216			19,416
Change in derivative fair value	(314		)	(1,746		)
Gain on sale of assets	(5,926		)	(491		)
Other, net	8,543			15,241
Net change in:
Accounts receivable	43,066			97,040
Inventories	(6,061		)	5,703
Accounts payable	(20,434		)	(50,581		)
Amounts due customers including gas supply pass-through	8,513			29,311
Income tax receivable	39,225			(13,062		)
Pension and other postretirement benefit contributions	(4,061		)	(39,737		)
Other current assets and liabilities	12,589			2,686
Net cash provided by operating activities	441,126			400,513
Investing Activities
Additions to property, plant and equipment	(378,640		)	(171,185		)
Acquisitions, net of cash acquired	(60,937		)	(5,580		)
Proceeds from sale of assets	7,306			549
Purchase of short-term investments	—			(154,880		)
Other, net	(413		)	(702		)
Net cash used in investing activities	(432,684		)	(331,798		)
Financing Activities
Payment of dividends on common stock	(19,458		)	(18,687		)
Issuance of common stock	6,202			586
Payment of long-term debt	(293		)	(519		)
Net change in short-term debt	(3,000		)	—
Tax benefit on stock compensation	880			708
Net cash used in financing activities	(15,669		)	(17,912		)
Net change in cash and cash equivalents	(7,227		)	50,803
Cash and cash equivalents at beginning of period	22,659			75,844
Cash and Cash Equivalents at End of Period	$	15,432		$	126,647

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



CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2011			2010			2011			2010
Operating Revenues	$	86,309		$	99,139		$	355,881		$	436,439
Operating Expenses
Cost of gas	32,419			43,234			164,168			240,390
Operations and maintenance	36,212			33,501			73,534			64,904
Depreciation and amortization	9,846			11,890			19,626			24,929
Income taxes
Current	(8,701		)	(4,201		)	12,870			20,454
Deferred	6,562			3,977			12,962			7,270
Taxes, other than income taxes	6,669			7,376			22,331			27,823
Total operating expenses	83,007			95,777			305,491			385,770
Operating Income	3,302			3,362			50,390			50,669
Other Income (Expense)
Allowance for funds used during construction	234			148			392			270
Other income	374			241			993			452
Other expense	(112		)	(595		)	(185		)	(495		)
Total other income (expense)	496			(206		)	1,200			227
Interest Charges
Interest on long-term debt	3,039			2,964			6,081			5,932
Other interest expense	497			532			1,072			1,058
Total interest charges	3,536			3,496			7,153			6,990
Net Income (Loss)	$	262		$	(340	)	$	44,437		$	43,906

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



CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands)	June 30, 2011			December 31, 2010
ASSETS
Property, Plant and Equipment
Utility plant	$	1,322,695		$	1,292,611
Less accumulated depreciation	523,051			509,989
Utility plant, net	799,644			782,622
Other property, net	43			43
Current Assets
Cash and cash equivalents	13,739			16,910
Accounts receivable
Gas	52,084			136,800
Other	11,268			10,229
Affiliated companies	2,140			698
Allowance for doubtful accounts	(12,700		)	(14,200		)
Inventories
Storage gas inventory	34,632			36,706
Materials and supplies	4,160			4,147
Liquified natural gas in storage	3,693			3,551
Regulatory asset	32,563			28,286
Income tax receivable	2,077			10,315
Deferred income taxes	25,759			27,302
Prepayments and other	1,771			4,223
Total current assets	171,186			264,967
Other Assets
Regulatory asset	89,465			105,365
Pension and other postretirement assets	7,800			9,201
Deferred charges and other	4,833			5,399
Total other assets	102,098			119,965
TOTAL ASSETS	$	1,072,971		$	1,167,597

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



CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands, except share data)	June 30, 2011		December 31, 2010
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at June 30, 2011 and December 31, 2010	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	322,554		292,815
Total common shareholder's equity	357,058		327,319
Long-term debt	200,500		200,793
Total capitalization	557,558		528,112
Current Liabilities
Long-term debt due within one year	5,000		5,000
Notes payable to banks	—		70,000
Accounts payable	71,504		83,515
Accrued taxes	35,872		48,476
Customers' deposits	21,471		20,459
Amounts due customers	10,407		20,161
Accrued wages and benefits	10,345		11,851
Regulatory liability	65,024		75,703
Other	10,154		11,822
Total current liabilities	229,777		346,987
Deferred Credits and Other Liabilities
Deferred income taxes	170,004		141,780
Pension and other postretirement liabilities	4,190		4,733
Regulatory liability	92,951		110,447
Long-term derivative instruments	17,657		32,461
Other	834		3,077
Total deferred credits and other liabilities	285,636		292,498
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,072,971	$	1,167,597

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



CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)

Six months ended June 30, (in thousands)	2011			2010
Operating Activities
Net income	$	44,437		$	43,906
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,626			24,929
Deferred income taxes	12,962			7,270
Bad debt expense	2,660			(225		)
Other, net	1,620			3,516
Net change in:
Accounts receivable	31,975			50,953
Inventories	1,919			11,468
Accounts payable	(17,284		)	(18,070		)
Amounts due customers including gas supply pass-through	8,513			29,311
Income tax receivable	8,238			1,513
Pension and other postretirement benefit contributions	(1,406		)	(24,286		)
Other current assets and liabilities	4,491			9,743
Net cash provided by operating activities	117,751			140,028
Investing Activities
Additions to property, plant and equipment	(34,386		)	(36,586		)
Other, net	(1,545		)	(1,229		)
Net cash used in investing activities	(35,931		)	(37,815		)
Financing Activities
Dividends	(14,698		)	(18,684		)
Payment of long-term debt	(293		)	(519		)
Net decreases in advances from affiliates	—			(24,962		)
Net change in short-term debt	(70,000		)	—
Net cash used in financing activities	(84,991		)	(44,165		)
Net change in cash and cash equivalents	(3,171		)	58,048
Cash and cash equivalents at beginning of period	16,910			9,460
Cash and Cash Equivalents at End of Period	$	13,739		$	67,508

The accompanying notes are an integral part of these 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, 2010, 2009 and 2008, included in the 2010 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 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 consisted of normal recurring items.

During the first quarter of 2010, Alagasco identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010, in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the prior quarterly and year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010, and determined that the amount was not material to these periods. The Company corrected this error in the first quarter of 2010.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period ended December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2011, Alagasco had a net $2.2 million pre-tax and a net $5.4 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months and six months ended June 30, 2010, Alagasco had a $1.8 million pre-tax and a $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $1.3 million annual decrease and a $10.2 million annual increase in revenues became effective December 1, 2010 and 2009, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2010 and 2009.

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

mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) negative individual large commercial and industrial customer budget revenue variances that exceed $250,000 during the rate year, if such losses caused Alagasco's year-end return on average common equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010, order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) negative individual large commercial and industrial customer budget variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to negative individual large commercial and industrial customer revenue variances can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010, order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR. In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $4.4 million and $3.8 million as of June 30, 2011 and December 31, 2010, respectively, as more fully described in Note 9, Commitments and Contingencies.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters 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 with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with ten of its active counterparties and in a net gain position with the remaining one at June 30, 2011. The four largest counterparty positions at June 30, 2011, Morgan Stanley Capital Group, Inc.,

Citibank, N.A., J Aron & Company and Shell Energy North America (US), L.P., constituted approximately $57.9 million, $36.2 million, $20.8 million and $20.2 million, respectively, of Energen Resources’ net loss on fair value of derivatives. Barclays Bank PLC was the only counterparty in a gain position of $6.7 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 June 30, 2011, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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



(in thousands)	June 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	49,182			$	—		$	49,182
Long-term asset derivative instruments	10,427			*	—			10,427
Total derivative assets	59,609				—			59,609
Accounts receivable	(37,177		)	*	—			(37,177		)
Accounts payable	(54,926		)		—			(54,926		)
Long-term liability derivative instruments	(120,273		)		—			(120,273		)
Total derivative liabilities	(212,376		)		—			(212,376		)
Total derivatives designated	(152,767		)		—			(152,767		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(68		)		(32,159		)	(32,227		)
Long-term liability derivative instruments	—				(17,657		)	(17,657		)
Total derivative liabilities	(68		)		(49,816		)	(49,884		)
Total derivatives not designated	(68		)		(49,816		)	(49,884		)
Total derivatives	$	(152,835	)		$	(49,816	)	$	(202,651	)



(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 $55.6 million and a net $26.8 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of June 30, 2011, and December 31, 2010, respectively.

Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet with a corresponding regulatory asset or liability. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco's APSC-approved tariff.

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



(in thousands)	Location on Income Statement	Three months ended June 30, 2011			Three months ended June 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $30.3 million and $26.3 million	—	$	49,449		$	42,917
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	(5,770	)	$	56,666
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(740	)	$	175



(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($29.1) million and $60.3 million	—	$	(47,425	)	$	98,385
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	1,821		$	93,390
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(2,391	)	$	1,879

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:



(in thousands)	Location on Income Statement	Three months ended June 30, 2011			Three months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(1	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2011			Six months ended June 30, 2010
Loss recognized in income on derivative	Operating revenues	$	(1	)	$	(4	)

As of June 30, 2011, $22.6 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of June 30, 2011, the Company had 7 thousand barrels (MBbl) of oil hedges which expire during 2011 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:



Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	7.1 Bcf	$6.47 Mcf	NYMEX Swaps
	19.4 Bcf	$5.65 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	6.0 Bcf	$5.34 Mcf	Basin Specific Swaps
Oil
2011	2,242 MBbl	$80.47 Bbl	NYMEX Swaps
2012	3,881 MBbl	$83.53 Bbl	NYMEX Swaps
2013	3,296 MBbl	$85.97 Bbl	NYMEX Swaps
2014	2,818 MBbl	$87.92 Bbl	NYMEX Swaps
Oil Basis Differential
2011	1,103 MBbl	*	Basis Swaps
2012	753 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	21.1 MMGal	$0.90 Gal	Liquids Swaps
2012	39.9 MMGal	$0.86 Gal	Liquids Swaps
2013	35.2 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:



Production Period	Total Hedged Volumes	Description
2011	6.0 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

As of June 30, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and December 31, 2013, respectively.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:


Level 1 -	Unadjusted quoted prices in active markets for identical assets or liabilities;


Level 2 -	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;


Level 3 -	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to New York Mercantile Exchange (NYMEX) natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and liquids swaps.

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



	June 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(7,773	)	$	19,778		$	12,005
Noncurrent assets	78			$	924		$	1,002
Current liabilities	(81,752		)	(5,401		)	(87,153		)
Noncurrent liabilities	(126,650		)	(1,855		)	(128,505		)
Net derivative asset (liability)	$	(216,097	)	$	13,446		$	(202,651	)



	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

Alagasco had $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2011, and December 31, 2010.

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)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	16,927		$	114,440
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	7,720			9,215
Settlements during period	(12,405		)	(31,535		)
Balance at end of period	$	13,446		$	91,817



	Six months ended			Six months ended
(in thousands)	June 30, 2011			June 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,204			(303		)
Unrealized gains (losses) relating to instruments held at the reporting date	(3,554		)	75,886
Settlements during period	(26,959		)	(48,283		)
Balance at end of period	$	13,446		$	91,817

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)



	Three months ended					Three months ended
(in thousands, except per share amounts)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	63,325	72,065	$	0.88	$	55,543	71,844	$	0.77
Effect of dilutive securities
Stock options			347					228
Non-vested restricted stock			8					17
Diluted EPS	$	63,325	72,420	$	0.87	$	55,543	72,089	$	0.77



	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2011					June 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	157,593	72,033	$	2.19	$	172,253	71,830	$	2.40
Effect of dilutive securities
Stock options			324					223
Non-vested restricted stock			7					16
Diluted EPS	$	157,593	72,364	$	2.18	$	172,253	72,069	$	2.39

For the three months and six months ended June 30, 2011, the Company had no options that were excluded from the computation of diluted EPS. For the three months and six months ended June 30, 2010, the Company had 472,560 options that were excluded

from the computation of diluted EPS. For the three months and six months ended June 30, 2011 and 2010, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

5. SEGMENT INFORMATION

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



	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	244,090		$	234,586		$	460,882		$	472,200
Natural gas distribution	86,309			99,139			355,881			436,439
Total	$	330,399		$	333,725		$	816,763		$	908,639
Operating income (loss)
Oil and gas operations	$	105,418		$	95,456		$	190,477		$	212,741
Natural gas distribution	1,163			3,138			76,222			78,393
Eliminations and corporate expenses	(246		)	(301		)	(483		)	(643		)
Total	$	106,335		$	98,293		$	266,216		$	290,491
Other income (expense)
Oil and gas operations	$	(5,822	)	$	(6,555	)	$	(11,269	)	$	(12,426	)
Natural gas distribution	(3,040		)	(3,702		)	(5,953		)	(6,763		)
Eliminations and other	65			(548		)	88			(762		)
Total	$	(8,797	)	$	(10,805	)	$	(17,134	)	$	(19,951	)
Income before income taxes	$	97,538		$	87,488		$	249,082		$	270,540



(in thousands)	June 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,404,189	$	3,160,601
Natural gas distribution	1,070,831		1,166,899
Eliminations and other	36,374		36,060
Total	$	4,511,394	$	4,363,560

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:



	Three months ended
	June 30,
(in thousands)	2011		2010
Net income	$	63,325	$	55,543
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $30.3 million and $26.3 million	49,449		42,917
Reclassification adjustment for derivative instruments, net of tax of $2.5 million and ($21.6) million	4,037		(35,241		)
Pension and postretirement plans, net of tax of $0.4 million and $0.3 million	683		630
Comprehensive income	$	117,494	$	63,849



	Six months ended
	June 30,
(in thousands)	2011			2010
Net income	$	157,593		$	172,253
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($29.1) million and $60.3 million	(47,425		)	98,385
Reclassification adjustment for derivative instruments, net of tax of $0.2 million and ($36.2) million	354			(59,066		)
Pension and postretirement plans, net of tax of $0.7 million and $0.7 million	1,365			1,258
Comprehensive income	$	111,887		$	212,830



(in thousands)	June 30, 2011			December 31, 2010
Unrealized loss on hedges, net of tax of ($55.6) million and ($26.8) million	$	(90,738	)	$	(43,667	)
Pension and postretirement plans, net of tax of ($15.8) million and ($16.5) million	(29,365		)	(30,730		)
Accumulated other comprehensive loss	$	(120,103	)	$	(74,397	)

7. STOCK COMPENSATION

Stock Incentive Plan

The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. On April 27, 2011, the Company amended the Stock Incentive Plan to increase the number of shares authorized for issuance by 3,000,000 shares. This increase resulted in 3,794,326 shares being available for future issuances. Options granted under the Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 293,978 non-qualified option shares during the first quarter of 2011 with a grant-date fair value of $19.65.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 189,984 awards during the first quarter of 2011. These awards had a fair value of $20.86 as of June 30, 2011.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During 2011, Energen Resources awarded 5,076 Petrotech units with a three-year vesting period. These awards had a fair value of $55.17 as of June 30, 2011.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2011, the Company had noncash purchases of approximately $26,000 and $0.4 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.

8. EMPLOYEE BENEFIT PLANS

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	4,586		$	4,287
Interest cost	2,740			2,841			5,480			5,683
Expected long-term return on assets	(3,868		)	(3,229		)	(7,736		)	(6,458		)
Actuarial loss	1,609			1,443			3,218			2,887
Prior service cost amortization	124			124			248			248
Net periodic expense	$	2,898		$	3,323		$	5,796		$	6,647

The Company anticipates required contributions of approximately $7.2 million during 2011 to the pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. It is not anticipated that the funded status of the pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2011. For the three months and six months ending June 30, 2011, the Company made benefit payments aggregating $36,000 and $2.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $71,000 through the remainder of 2011.

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	885		$	1,032
Interest cost	1,111			1,208			2,222			2,417
Expected long-term return on assets	(1,104		)	(996		)	(2,209		)	(1,993		)
Transition amortization	479			479			958			958
Net periodic expense	$	928		$	1,207		$	1,856		$	2,414

For the three months and six months ended June 30, 2011, the Company made contributions aggregating $0.9 million and $1.9 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.9 million to postretirement benefit plan assets through the remainder of 2011. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

9. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $126 million through September 2024. During the six months ending June 30, 2011 and 2010, Alagasco recognized approximately $25.8 million and $26.8 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 222 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 June 30, 2011, the fixed price purchases under these guarantees had a maximum term outstanding through March 2012 and an aggregate purchase price of $2.0 million with a market value of $2.0 million.

Income Taxes: Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco will be allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During the quarter, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above. These benefits were partially offset by $1.9 million of income tax expense for additional unrecognized tax benefit liabilities. The Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

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

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. Remediation of the Huntsville, Alabama, manufactured gas plant site, as discussed below, may also result in unanticipated costs.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (EPA) identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have entered into a Consent Order, developed an action plan for the site and as of June 30, 2011, had substantially completed the action plan. Based on information available at this time, Alagasco estimates that it may incur costs associated with the site of approximately $4.7 million, including costs previously incurred. During the three months and six months ended June 30, 2011, the Company incurred costs of $2.0 million and $3.0 million, respectively, associated with the site. As of June 30, 2011, the Company has accrued a contingent liability of $0.8 million in addition to the costs previously incurred. The action plan provided for excavation of affected soil and sediment only. If it is determined that further work is appropriate, then actual costs will likely exceed the estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

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 $20 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 Department's findings and the ONRR Order. 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 June 30, 2011.

10. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, approximates $443.4 million and has a carrying value of $410.5 million at June 30, 2011. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $213.9 million and has a carrying value of $205.5 million at June 30, 2011. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At June 30, 2011, and December 31, 2010, Alagasco’s finance receivable totaled $9.6 million and $8.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $361,000 as of June 30, 2011.

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, 2010	$	447
Provision	80
Allowance for credit losses as of June 30, 2011	$	527

11. REGULATORY ASSETS AND LIABILITIES

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



(in thousands)	June 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	58,469	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		8,898		—		8,681
Risk management activities	32,159		17,657		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		4,395		—		3,794
Other	209		46		223		145
Total regulatory assets	$	32,563	$	89,465	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	7,696	$	—	$	4,147	$	—
Unbilled service margin	6,957		—		34,197		—
Postretirement liabilities	—		959		—		754
Gas supply adjustment	29,695		—		14,990		—
Asset removal costs, net	—		7,665		—		6,913
Refundable negative salvage	20,643		71,896		22,336		90,504
Asset retirement obligation	—		11,611		—		11,439
Other	33		820		33		837
Total regulatory liabilities	$	65,024	$	92,951	$	75,703	$	110,447

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 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 six months ended June 30, 2011, 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 of ARO as of December 31, 2010	$	97,415
Liabilities incurred	2,291
Liabilities settled	(924		)
Accretion expense	3,338
Balance of ARO as of June 30, 2011	$	102,120

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $11.6 million and $11.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of June 30, 2011, and December 31, 2010, respectively. The conditional asset retirement obligations reflect the re-estimation of removal costs associated with Alagasco’s revised depreciation rate. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

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. Regulatory liabilities for accumulated asset removal costs of $7.7 million and $6.9 million for June 30, 2011, and December 31, 2010, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of June 30, 2011, the Company recognized $20.6 million and $71.9 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010, APSC order.

13. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010, (including the effects of closing adjustments).



(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

Included in the Company’s consolidated results of operations for the six months ended June 30, 2011, are $2.0 million of operating revenues and $0.5 million in operating income resulting from the operation of the properties acquired above.

On December 9, 2010, Energen completed the asset purchase of certain liquids-rich properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010, (including the effects of closing adjustments).



(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the six months ended June 30, 2011, are $19.2 million of operating revenues and $9.6 million in operating income resulting from the operation of the properties acquired above.

14. RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. These amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the impact of the ASU.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the impact of the ASU.

In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures, as of the end of a reporting period, are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The disclosures required under this standard have been included in Note 10, Financial Instruments.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The disclosures required under this standard have been included in Note 3, Derivative Commodity Instruments.

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

RESULTS OF OPERATIONS

Energen's net income totaled $63.3 million ($0.87 per diluted share) for the three months ended June 30, 2011 compared with net income of $55.5 million ($0.77 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended June 30, 2011, of $63.1 million as compared with $56.8 million in the same quarter in the previous year primarily as a result of increased production volumes (approximately $14 million after-tax), decreased exploration expense (approximately $11 million after-tax) due to a 2010 non-cash write-off of $10 million after-tax of unproved leasehold costs associated with the deep Conasauga shale acreage and a $3.6 million after-tax gain associated with the sale of certain properties in the Permian Basin. Negatively affecting net income was the impact of lower natural gas commodity prices (approximately $15 million after-tax), increased lease operating expense excluding production taxes (approximately $4 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $3 million after-tax) and increased production taxes (approximately $2 million after-tax). Energen's natural gas utility, Alagasco, reported net income of $0.3 million in the second quarter of 2011 compared to a net loss of $0.3 million in the same period last year. This increase largely reflects the utility’s ability to earn on a higher level of equity partially offset by the timing of rate recovery under Alagasco’s rate-setting mechanisms.

For the 2011 year-to-date, Energen's net income totaled $157.6 million ($2.18 per diluted share) compared to net income of $172.3 million ($2.39 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2011, of $112.8 million as compared with $128.4 million in the previous period. Lower natural gas and oil commodity prices (approximately $35 million after-tax), increased lease operating expense excluding production taxes (approximately $6 million after-tax), higher DD&A expense (approximately $5 million after-tax), increased production taxes (approximately $4 million after-tax) and increased administrative expense (approximately $4 million after-tax) were partially offset by increased production volumes (approximately $23 million), lower exploration expense (approximately $11 million after-tax) largely due to the $10 million after-tax Conasauga shale acreage write-off in 2010 and the $3.6 million after-tax gain on the sale of properties in the Permian Basin. Alagasco’s net income of $44.4 million in the current year-to-date compared to net income of $43.9 million in the same period in the previous year primarily due to utility’s ability to earn on a higher level of equity combined with the timing of rate recovery under Alagasco’s rate-setting mechanisms.

Oil and Gas Operations

Revenues from oil and gas operations rose 4.1 percent to $244.1 million for the three months ended June 30, 2011, primarily as a result of higher production volumes partially offset by decreased realized natural gas commodity prices. In the year-to-date, revenues fell 2.4 percent to $460.9 million largely due to decreased realized natural gas and oil commodity prices partially offset by higher production volumes. During the current quarter, revenue per unit of production for natural gas decreased 19.4 percent to $5.51 per thousand cubic feet (Mcf), while oil revenue per unit of production rose 1.1 percent to $79.24 per barrel. Natural gas liquids revenue per unit of production rose 23.4 percent to an average price of $0.95 per gallon. In the year-to-date, revenue per unit of production for natural gas decreased 21.5 percent to $5.51 per Mcf, oil revenue per unit of production fell 1.5 percent to $77.55 per barrel and natural gas liquids revenue per unit of production rose 12.2 percent to an average price of $0.92 per gallon. As detailed under Selected Business Segment Data, revenues per unit of production for the three and six months reflect realized prices and derivative gains and losses.

Production for both the current quarter and year-to-date increased largely due to higher volumes related to the September 2010 and December 2010 purchases of certain Permian Basin liquids-rich properties and field development partially offset by normal production declines. Natural gas production in the second quarter rose 1 percent to 17.8 billion cubic feet (Bcf), oil volumes increased 19.3 percent to 1,501 thousand barrels (MBbl) and natural gas liquids production rose 18.9 percent to 22.6 million gallons (MMgal). For the year-to-date, natural gas production increased slightly to 35.1 Bcf, while oil volumes rose 17.2 percent to 2,865 MBbl. Natural gas liquids production increased 11.9 percent to 42.3 MMgal. Natural gas comprised approximately 60 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax gain of $5.8 million in both the second quarter of 2011 and year-to-date primarily from the sale of certain properties in the Permian Basin. Energen Resources recorded no property sales in the second quarter of 2010. In the first quarter of 2010, Energen Resources recorded a pre-tax gain of $0.6 million largely from the sale of certain property in the Black Warrior Basin.

Operations and maintenance (O&M) expense decreased $9.4 million for the quarter and $3.1 million in the year-to-date. Lease operating expense (excluding production taxes) increased $6 million for the quarter largely due to increased workover and repair expense (approximately $2 million), the September and December 2010 acquisitions of Permian Basin liquids-rich properties (approximately $1.9 million), higher marketing and transportation costs (approximately $1.1 million), additional nonoperated costs (approximately $0.4 million) and higher gathering system expense ($0.4 million). In the year-to-date, lease operating expense (excluding production taxes) increased $9.1 million primarily due to the 2010 acquisitions (approximately $2.9 million), increased workover and repair expense (approximately $1.7 million), additional ad valorem taxes (approximately $1 million), higher gathering system expense (approximately $0.9 million), higher marketing and transportation costs (approximately $0.8 million) and increased chemical expense (approximately $0.7 million). Administrative expense increased $2.1 million for the three months ended June 30, 2011 largely due to the Company’s performance-based compensation plans (approximately $1.1 million) and increased labor costs (approximately $1 million). For the six months ended June 30, 2011, administrative expense rose $5.8 million primarily due to higher costs related to the Company’s performance-based compensation plans (approximately $3.8 million) and increased labor costs (approximately $1.6 million). Exploration expense fell $17.5 million in the second quarter of 2011 and $18 million year-to-date. In the second quarter of 2010, Energen Resources recorded a non-cash write-off of $16.1 million pre-tax of unproved leasehold associated with the deep Conasauga shale acreage.

Energen Resources' DD&A expense for the quarter rose $5.2 million and increased $7.8 million year-to-date. The average depletion rate for the current quarter was $10.96 per barrel of oil equivalent (BOE) as compared to $10.69 per BOE in the same period a year ago. For the six months ended June 30, 2011, the average depletion rate was $10.82 per BOE as compared to $10.61 per BOE in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $1.3 million and $2 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from the acquisition of properties and an increase in development costs. Higher production volumes contributed approximately $3.8 million and $5.7 million to the increase in DD&A expense for the quarter and year-to-date.

Energen Resources' expense for taxes other than income taxes was $3.5 million and $5.9 million higher in the three months and six months ended June 30, 2011, largely due to production-related taxes. In the current quarter and year-to-date, higher commodity market prices contributed approximately $2.7 million and $4.7 million, respectively, to the increase in production-related taxes. Also increasing production-related taxes were higher natural gas, oil and natural gas liquid production volumes which contributed approximately $0.8 million and $1.2 million, respectively, for the quarter and year-to-date. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $12.8 million for the quarter largely due to a decline in gas costs and lower customer usage combined with adjustments from the utility’s rate setting mechanisms. During the second quarter of 2011, Alagasco had a $2.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the second quarter of 2010, Alagasco had a $1.8 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the current quarter, weather was 29.9 percent warmer than the same quarter last year. Residential sales volumes fell 16.9 percent and commercial and industrial customer sales volumes decreased 10.3 percent. Transportation volumes increased 2.1 percent in period comparisons. Revenues for the year-to-date fell $80.6 million primarily due to decreased customer usage and lower gas costs partially offset by adjustments for rate-setting purposes. In the current year-to-date, Alagasco had reduction in revenues of $5.4 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. In the 2010 year-to-date, Alagasco had reduction in revenues of $10.6 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. Weather, for the current six months, that was 18 percent warmer compared with the same period in the prior year contributed to a 16 percent decrease in residential sales volumes and a 12.1 percent fall in commercial and industrial customer sales volumes. Transportation volumes increased 2.2 percent in period comparisons for the same reasons as described above. A decrease in gas purchase volumes and a decrease in gas costs resulted in a 25 percent decrease in cost of gas for the quarter and a 31.7 percent decrease in cost of gas year-to-date. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense increased 8.1 percent in the current quarter primarily due to higher marketing expenses (approximately $2.1 million) and increased distribution operation expenses (approximately $0.5 million). In the six months ended June 30, 2011, O&M expense rose 13.3 percent primarily due to higher marketing expenses (approximately $2.8 million), increased labor-related costs (approximately $1.4 million), and increased distribution operation expenses (approximately $1.4 million). Also significantly impacting the increase in O&M expense was the increase to bad debt expense (approximately $2.9 million) which is attributable to

the prior year correction of a $3 million error identified by Alagasco during the first quarter of 2010 in the calculation of the estimate of the allowance for doubtful accounts as of December 31, 2009. See Note 1, Basis of Presentation, in the Notes to Unaudited Condensed Financial Statements for further discussion.

A 17.2 percent decrease in depreciation expense in the current quarter and a 21.3 percent decrease year-to-date was primarily due to revised depreciation rates effective June 1, 2010, partially offset by the extension and replacement of the utility's distribution system and replacement of its support systems. The revised depreciation rates decreased depreciation expense by approximately $2.7 million and $6.8 million for the three months and six months ended June 30, 2011, respectively, from expense amounts calculated using the prior depreciation rate. 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. 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. Approved depreciation rates averaged approximately 3.1 percent and 4.2 percent in the six months ended June 30, 2011 and 2010, respectively.

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 decreased $0.4 million in the second quarter of 2011 and $0.9 million year-to-date. Income tax expense for the Company increased $2.3 million in the current quarter largely due to higher pre-tax income. During the quarter, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the Internal Revenue Service (IRS) which allowed Alagasco the full repair tax deductions as originally claimed for its gas distribution property in 2007 and 2008. These benefits were partially offset by $1.9 million of income tax expense for additional unrecognized tax benefit liabilities. For the year-to-date, income tax expense fell $6.8 million primarily due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $441.1 million as compared to $400.5 million in the prior period. Net income decreased during period comparisons primarily due to lower realized commodity prices partially offset by increased production volumes at Energen Resources. Deferred income taxes increased in the current year due to the tax effect of higher 2011 capital expenditures and the 2011 impact of bonus depreciation. The Company’s working capital needs were also influenced by accrued taxes, commodity prices and the timing of payments. During the first quarter of 2011, the income tax receivable decreased approximately $39.8 million primarily from an income tax refund associated with the 2010 impact of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs at Alagasco were additionally affected by lower 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 $432.7 million for the six months ended June 30, 2011 primarily due to additions of property, plant and equipment of $439.6 million. Energen Resources incurred on a cash basis $405.1 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $34.4 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company had a net cash use of $15.7 million for financing activities in the year-to-date primarily due to a decrease in short-term borrowings and the payment of dividends to common shareholders partially offset by the issuance of common stock through the Stock Incentive Plan.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2011, the Company expects its oil and gas capital spending to total approximately $883 million, including $20 million for certain property acquisitions in the Permian Basin, $702 million for existing properties, $93 million for exploration and $65 for unproved leasehold acquisitions. Capital investment at Energen Resources in 2012 and 2013 is expected to approximate $915 million and $890 million, respectively, for existing properties.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property

acquisitions is subject to market conditions and industry trends. Property acquisitions 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 primarily 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.

Natural Gas Distribution

Alagasco is subject to regulation by the APSC and is allowed to earn a range of return on average equity of 13.15 percent to 13.65 percent. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $20.3 million and $2.7 million for the period January through June 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $20.6 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $71.9 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over an eight year period beginning December 1, 2011. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the ESR and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC's 1998 order establishing the ESR, environmental response costs and self insurance costs above $1 million per occurrence. The refunds as of December 2010 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. Over the last five years, Alagasco’s customer count has declined at a rate of approximately 1 percent annually despite above-average levels of penetration along existing distribution lines. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with economic growth potential and pursuing the acquisition of municipally owned gas systems in Alabama. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility's customer base.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

Alagasco maintains an investment in storage gas that is expected to average approximately $37 million in 2011 but will vary depending upon the price of natural gas. During 2011, Alagasco plans to invest an estimated $76 million in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities.

Weather Event

On April 27, 2011, severe weather including a number of deadly tornados caused significant damage to several communities in Alabama served by Alagasco. These communities included Tuscaloosa, Pleasant Grove, Hueytown and parts of Birmingham. Alagasco experienced an approximate 2,400 decrease in residential customers due to the impact of these storms, however, earnings and cash flows have not been affected materially during the three months or six months ended June 30, 2011. Energen Resources was not impacted materially by the storms.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. At June 30, 2011, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with ten

of its active counterparties and in a net gain position with the remaining one at June 30, 2011. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

Alagasco also enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:



Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	7.1 Bcf	$6.47 Mcf	NYMEX Swaps
	19.4 Bcf	$5.65 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	6.0 Bcf	$5.34 Mcf	Basin Specific Swaps
2014	*10.8 Bcf	$5.07 Mcf	Basin Specific Swaps
Oil
2011	2,242 MBbl	$80.47 Bbl	NYMEX Swaps
2011	*426 MBbl	$99.75 Bbl	NYMEX Swaps
2012	3,881 MBbl	$83.53 Bbl	NYMEX Swaps
2012	*646 MBbl	$102.25 Bbl	NYMEX Swaps
2013	3,296 MBbl	$85.97 Bbl	NYMEX Swaps
2013	*411 MBbl	$103.15 Bbl	NYMEX Swaps
2014	2,818 MBbl	$87.92 Bbl	NYMEX Swaps
2014	*394 MBbl	$103.30 Bbl	NYMEX Swaps
Oil Basis Differential
2011	1,103 MBbl	**	Basis Swaps
2011	*492 MBbl	**	Basis Swaps
2012	753 MBbl	**	Basis Swaps
2012	*2,371 MBbl	**	Basis Swaps
2013	*2,768 MBbl	**	Basis Swaps
Natural Gas Liquids
2011	21.1 MMGal	$0.90 Gal	Liquids Swaps
2012	39.9 MMGal	$0.86 Gal	Liquids Swaps
2013	35.2 MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to June 30, 2011. ** Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:



Production Period	Total Hedged Volumes	Description
2011	6.0 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

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:



	June 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(7,773	)	$	19,778		$	12,005
Noncurrent assets	$	78		$	924		$	1,002
Current liabilities	(81,752		)	(5,401		)	(87,153		)
Noncurrent liabilities	(126,650		)	(1,855		)	(128,505		)
Net derivative asset (liability)	$	(216,097	)	$	13,446		$	(202,651	)



	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

As of June 30, 2011, Alagasco had $32.2 million and $17.7 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco has $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2011 and December 31, 2010.

Level 3 assets and liabilities as of June 30, 2011, 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 $42 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to derivative instruments qualifying as cash flow hedges. 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.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the six months ended June 30, 2011. The Company expects any future stock

repurchases to be funded through internally generated cash flow or through the utilization of its credit facilities. During the six months ended June 30, 2011, the Company had noncash purchases of approximately $0.7 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Credit Facilities and Working Capital

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (syndicated credit facilities) with domestic and foreign lenders. Energen obligations under the $850 million syndicated credit facility are unconditionally guaranteed by Energen Resources. These syndicated credit facilities replace the majority of the Company’s short-term credit facilities which were available to Energen and Alagasco. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of 65 percent for each of the Company and Alagasco. The Company currently has available credit facilities as follows:



(in thousands)	Current Term	Energen		Alagasco		Total
Syndicated Credit Facility	10/29/2013	$	850,000	$	150,000	$	1,000,000
Bryant Bank	11/1/2011	-		9,000		9,000
BancorpSouth Bank	5/23/2012	-		10,000		10,000
Total		$	850,000	$	169,000	$	1,019,000

Working capital requirements for Energen and Alagasco are influenced by short-term borrowings to finance recent acquisitions, the fair value of the company's derivative financial instruments, the recovery and pass-through of regulatory items and the seasonality of Alagasco's business. Energen's accounts receivable and accounts payable at June 30, 2011 include $12 million and $87.2 million, respectively, associated with its derivative financial instruments largely related to future oil and gas production. Working capital at Alagasco reflects an expected pass-through to rate payers of $29.7 million associated with the timing of recovery for the cost of gas supply and of $20.6 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates.

Energen and Alagasco rely upon excess cash flow supplemented by the syndicated credit facilities and the short-term credit facilities to fund working capital needs. The Company may also issue long-term debt and equity periodically to replace obligations under the credit facilities, enhance liquidity and provide for permanent financing.

Dividends

Energen expects to pay annual cash dividends of $0.54 per share on the Company’s common stock in 2011. 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 and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. There have been no material changes to the contractual cash obligations of the Company since December 31, 2010.

Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under IRS examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco will be allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

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 $20 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 Department's findings and the ONRR Order. 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 June 30, 2011.

Recent Accounting Standards Updates

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

FORWARD LOOKING STATEMENTS AND RISK FACTORS

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

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

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

Access to Credit Markets: 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 both lenders and the Company. Recent market volatility and credit market disruption have demonstrated that credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

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

position. In addition, the recent adoption of financial reform legislation 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.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco's risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco's actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco's position. In addition, the recent adoption of financial reform legislation could have an adverse effect on the ability of Alagasco to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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

Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. Further, the Company’s insurance retention levels are such that significant events could adversely affect Energen Resources’, Alagasco's and the Company's financial position, results of operations and cash flows. The location of 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. The occurrence of any of these events could adversely affect Alagasco's, Energen Resources’ and the Company's financial position, results of operations and cash flows.

Alagasco Service Territory: 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.

Federal, State and Local Laws and Regulations: 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.



SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended					Six months ended
	June 30,					June 30,
(in thousands, except sales price data)	2011			2010		2011			2010
Oil and Gas Operations
Operating revenues
Natural gas	$	98,037		$	120,588	$	193,636		$	246,015
Oil	118,938			98,523		222,194			192,498
Natural gas liquids	21,482			14,611		39,015			31,147
Other	5,633			864		6,037			2,540
Total	$	244,090		$	234,586	$	460,882		$	472,200
Production volumes
Natural gas (MMcf)	17,778			17,633		35,112			35,045
Oil (MBbl)	1,501			1,258		2,865			2,444
Natural gas liquids (MMgal)	22.6			19.0		42.3			37.8
Total production volumes (MMcfe)	30,012			27,897		58,350			55,106
Total production volumes (MBOE)	5,002			4,649		9,725			9,184
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	5.51		$	6.84	$	5.51		$	7.02
Oil (barrel)	$	79.24		$	78.34	$	77.55		$	78.77
Natural gas liquids (gallon)	$	0.95		$	0.77	$	0.92		$	0.82
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	5.51		$	6.84	$	5.51		$	7.02
Oil (barrel)	$	79.24		$	78.34	$	77.55		$	78.77
Natural gas liquids (gallon)	$	0.95		$	0.77	$	0.92		$	0.82
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	4.18		$	3.95	$	4.10		$	4.59
Oil (barrel)	$	96.79		$	73.36	$	92.92		$	73.91
Natural gas liquids (gallon)	$	1.12		$	0.79	$	1.07		$	0.87
Other data
Lease operating expense (LOE)
LOE and other	$	50,712		$	44,721	$	97,657		$	88,560
Production taxes	14,192			10,646		26,475			20,587
Total	$	64,904		$	55,367	$	124,132		$	109,147
Depreciation, depletion and amortization	$	55,783		$	50,586	$	107,131		$	99,282
Capital expenditures	$	259,533		$	72,352	$	399,856		$	110,915
Exploration expenditures	$	1,207		$	18,677	$	1,821		$	19,861
Operating income	$	105,418		$	95,456	$	190,477		$	212,741
Natural Gas Distribution
Operating revenues
Residential	$	51,370		$	59,676	$	239,044		$	301,082
Commercial and industrial	23,393			26,190		90,299			110,480
Transportation	11,961			11,683		28,454			29,516
Other	(415		)	1,590		(1,916		)	(4,639		)
Total	$	86,309		$	99,139	$	355,881		$	436,439



Gas delivery volumes (MMcf)
Residential	2,749		3,310		15,340		18,272
Commercial and industrial	1,662		1,853		6,662		7,580
Transportation	10,739		10,523		23,709		23,205
Total	15,150		15,686		45,711		49,057
Other data
Depreciation and amortization	$	9,846	$	11,890	$	19,626	$	24,929
Capital expenditures	$	22,297	$	21,167	$	35,837	$	37,527
Operating income	$	1,163	$	3,138	$	76,222	$	78,393

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of June 30, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014 and December 31, 2013, respectively

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 June 30, 2011, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at June 30, 2011 was 2.16 percent. All long-term debt obligations were at fixed rates.

ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation


(a)	Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.


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

Alabama Gas Corporation


(a)	Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.


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

PART II: OTHER INFORMATION

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**
April 1, 2011 through April 30, 2011	—		—		—	8,992,700
May 1, 2011 through May 31, 2011	158	*	$	62.87	—	8,992,700
June 1, 2011 through June 30, 2011	420	*	$	61.76	—	8,992,700
Total	578		$	62.06	—	8,992,700

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

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

ITEM 6. EXHIBITS



31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101*	-	The following financial statements from Energen Corporation's Quarterly Report on Form 10-Q for the quarter ended
		June 30, 2011, formatted in XBRL: (i) Consolidated Condensed Statements of Income,
		(ii) Consolidated Condensed Balance Sheets, (iii) Consolidated Condensed Statements of Cash Flows,
		(iv) the Notes to Unaudited Condensed Financial Statements.

* Pursuant to Rule 405(a)(2) of Regulation S−T, the Company will file an amendment to this Form 10−Q within 30 days, to furnish the XBRL interactive data files as Exhibit 101, as required by Rule 405 of Regulation S-T.

SIGNATURES

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



		ENERGEN CORPORATION ALABAMA GAS CORPORATION

August 1, 2011	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


August 1, 2011	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation


August 1, 2011	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation


August 1, 2011	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Energen (EGN) Inactive 10-Q2011 Q2 Quarterly report

Content analysis