Edgar Filing: ALABAMA GAS CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

¨	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 ¨

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 ¨
Alabama Gas Corporation	YES ¨	NO ¨

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

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

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


Energen Corporation	YES ¨	NO x
Alabama Gas Corporation	YES ¨	NO x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of May 3, 2010.


Energen Corporation	$0.01 par value	71,882,065 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2010

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	23

	Selected Business Segment Data of Energen Corporation	31

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	34

	PART II: OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35

Item 6.	Exhibits	35

SIGNATURES		36

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)


	Three months ended March 31,
(in thousands, except per share data)	2010			2009
Operating Revenues
Oil and gas operations	$	237,614		$	189,120
Natural gas distribution		337,300			294,986
Total operating revenues		574,914			484,106

Operating Expenses
Cost of gas		197,156			152,069
Operations and maintenance		91,702			88,387
Depreciation, depletion and amortization		61,735			54,578
Taxes, other than income taxes		30,637			26,460
Accretion expense		1,486			1,136
Total operating expenses		382,716			322,630

Operating Income		192,198			161,476

Other Income (Expense)
Interest expense		(9,960	)		(9,781	)
Other income		977			401
Other expense		(163	)		(1,886	)
Total other expense		(9,146	)		(11,266	)

Income Before Income Taxes		183,052			150,210
Income tax expense		66,342			54,628

Net Income	$	116,710		$	95,582

Diluted Earnings Per Average Common Share	$	1.62		$	1.33
Basic Earnings Per Average Common Share	$	1.63		$	1.33
Dividends Per Common Share	$	0.130		$	0.125
Diluted Average Common Shares Outstanding		72,039			71,897
Basic Average Common Shares Outstanding		71,810			71,640

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

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)


(in thousands)	March 31, 2010		December 31, 2009

ASSETS
Current Assets
Cash and cash equivalents	$	271,106	$	75,844
Accounts receivable, net of allowance for doubtful accounts of $13,847 at March 31, 2010, and $17,251 at December 31, 2009		365,972		327,163
Inventories
Storage gas inventory		18,923		42,475
Materials and supplies		19,951		17,440
Liquified natural gas in storage		2,882		3,409
Regulatory asset		39,097		33,196
Income tax receivable		1,785		4,552
Prepayments and other		10,572		11,527

Total current assets		730,288		515,606

Property, Plant and Equipment
Oil and gas properties, successful efforts method		3,411,153		3,379,128
Less accumulated depreciation, depletion and amortization		1,016,013		972,676
Oil and gas properties, net		2,395,140		2,406,452
Utility plant		1,226,240		1,211,624
Less accumulated depreciation		498,632		489,924
Utility plant, net		727,608		721,700
Other property, net		17,536		16,317

Total property, plant and equipment, net		3,140,284		3,144,469

Other Assets
Regulatory asset		114,568		102,133
Long-term derivative instruments		21,240		7,824
Deferred charges and other		34,182		33,086

Total other assets		169,990		143,043

TOTAL ASSETS	$	4,040,562	$	3,803,118

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)	March 31, 2010			December 31, 2009

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	150,000		$	150,000
Accounts payable		171,796			164,327
Accrued taxes		84,530			49,884
Customers’ deposits		21,537			20,836
Amounts due customers		-			24,106
Accrued wages and benefits		15,150			27,347
Regulatory liability		74,047			29,719
Royalty payable		21,644			19,034
Deferred income taxes		19,630			10,015
Other		28,517			25,493

Total current liabilities		586,851			520,761

Long-term debt		410,621			410,786

Deferred Credits and Other Liabilities
Asset retirement obligation		90,269			88,298
Pension and other postretirement liabilities		52,560			55,899
Regulatory liability		158,172			155,088
Long-term derivative instruments		61,116			60,446
Deferred income taxes		521,564			505,460
Other		30,044			18,137

Total deferred credits and other liabilities		913,725			883,328

Commitments and Contingencies

Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized		0			0
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,758,671 shares issued at March 31, 2010, and 74,593,431 shares issued at December 31, 2009		748			746
Premium on capital stock		465,286			461,661
Capital surplus		2,802			2,802
Retained earnings		1,734,121			1,626,753
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net		81,049			49,405
Pension and postretirement plans		(31,162	)		(31,790	)
Deferred compensation plan		4,826			3,121
Treasury stock, at cost; 3,072,917 shares at March 31, 2010, and 2,991,373 shares at December 31, 2009		(128,305	)		(124,455	)
Total shareholders’ equity		2,129,365			1,988,243

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,040,562		$	3,803,118

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

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)


Three months ended March 31, (in thousands)	2010			2009

Operating Activities
Net income	$	116,710		$	95,582
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		61,735			54,578
Accretion expense		1,486			1,136
Deferred income taxes		14,552			19,488
Bad debt expense		(2,450	)		1,203
Change in derivative fair value		(1,598	)		(348	)
Gain on sale of assets		(626	)		(395	)
Other, net		4,291			2,499
Net change in:
Accounts receivable		(2,852	)		34,261
Inventories		21,568			28,278
Accounts payable		(9,074	)		(44,422	)
Amounts due customers		32,989			(15,373	)
Income tax receivable		2,767			48,945
Other current assets and liabilities		29,739			11,502

Net cash provided by operating activities		269,237			236,934

Investing Activities
Additions to property, plant and equipment		(62,003	)		(117,060	)
Acquisitions, net of cash acquired		(3,850	)		(3,288	)
Proceeds from sale of assets		626			783
Other, net		(175	)		(890	)

Net cash used in investing activities		(65,402	)		(120,455	)

Financing Activities
Payment of dividends on common stock		(9,342	)		(8,644	)
Issuance of common stock		408			44
Payment of long-term debt		(215	)		(234	)
Net change in short-term debt		-			(62,000	)
Tax benefit on stock compensation		576			29

Net cash used in financing activities		(8,573	)		(70,805	)

Net change in cash and cash equivalents		195,262			45,674
Cash and cash equivalents at beginning of period		75,844			13,177

Cash and Cash Equivalents at End of Period	$	271,106		$	58,851

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

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)


	Three months ended March 31,
(in thousands)	2010			2009

Operating Revenues	$	337,300		$	294,986

Operating Expenses
Cost of gas		197,156			152,069
Operations and maintenance		31,403			31,056
Depreciation and amortization		13,039			12,615
Income taxes
Current		24,655			26,589
Deferred		3,293			2,769
Taxes, other than income taxes		20,447			18,407

Total operating expenses		289,993			243,505

Operating Income		47,307			51,481

Other Income (Expense)
Allowance for funds used during construction		122			210
Other income		474			184
Other expense		(163	)		(891	)

Total other expense		433			(497	)

Interest Charges
Interest on long-term debt		2,968			2,982
Other interest expense		526			526

Total interest charges		3,494			3,508

Net Income	$	44,246		$	47,476

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

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)


(in thousands)	March 31, 2010			December 31, 2009

ASSETS
Property, Plant and Equipment
Utility plant	$	1,226,240		$	1,211,624
Less accumulated depreciation		498,632			489,924

Utility plant, net		727,608			721,700

Other property, net		44			146

Current Assets
Cash and cash equivalents		89,919			9,460
Accounts receivable
Gas		148,357			137,891
Other		9,660			8,617
Allowance for doubtful accounts		(13,000	)		(16,400	)
Inventories
Storage gas inventory		18,923			42,475
Materials and supplies		4,474			4,374
Liquified natural gas in storage		2,882			3,409
Deferred income taxes		25,755			25,896
Income tax receivable		1,339			3,469
Regulatory asset		39,097			33,196
Prepayments and other		2,875			3,303

Total current assets		330,281			255,690

Other Assets
Regulatory asset		114,568			102,133
Deferred charges and other		5,546			4,997

Total other assets		120,114			107,130

TOTAL ASSETS	$	1,178,047		$	1,084,666

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

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)


(in thousands, except share data)	March 31, 2010		December 31, 2009

LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	0	$	0
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at March 31, 2010 and December 31, 2009		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		318,205		283,299

Total common shareholder’s equity		352,709		317,803
Long-term debt		206,307		206,522

Total capitalization		559,016		524,325

Current Liabilities
Accounts payable		106,598		78,154
Affiliated companies		3,338		24,962
Accrued taxes		52,095		35,314
Customers’ deposits		21,537		20,836
Amounts due customers		-		24,106
Accrued wages and benefits		6,593		11,472
Regulatory liability		74,047		29,719
Other		9,971		9,830

Total current liabilities		274,179		234,393

Deferred Credits and Other Liabilities
Deferred income taxes		115,205		121,826
Pension and other postretirement liabilities		17,930		19,054
Regulatory liability		158,172		155,088
Long-term derivative instruments		31,905		18,965
Other		21,640		11,015

Total deferred credits and other liabilities		344,852		325,948

Commitments and Contingencies

TOTAL LIABILITIES AND CAPITALIZATION	$	1,178,047	$	1,084,666

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

CONDENSED STATEMENTS OF CASH FLOWS

ALABAMA GAS CORPORATION

(Unaudited)


Three months ended March 31, (in thousands)	2010			2009

Operating Activities
Net income	$	44,246		$	47,476
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		13,039			12,615
Deferred income taxes		3,293			2,769
Bad debt expense		(2,454	)		1,204
Other, net		175			47
Net change in:
Accounts receivable		(18,165	)		12,936
Inventories		23,979			34,186
Accounts payable		13,580			(37,419	)
Amounts due customers		32,989			(15,373	)
Income tax receivable		2,130			29,984
Other current assets and liabilities		13,170			16,551
Net cash provided by operating activities		125,982			104,976

Investing Activities
Additions to property, plant and equipment		(14,311	)		(14,498	)
Other, net		(33	)		(778	)

Net cash used in investing activities		(14,344	)		(15,276	)

Financing Activities
Dividends		(9,340	)		(8,963	)
Payment of long-term debt		(215	)		(234	)
Net increases (decreases) in advances from affiliates		(21,624	)		22,962
Net change in short-term debt		-			(62,000	)

Net cash used in financing activities		(31,179	)		(48,235	)
Net change in cash and cash equivalents		80,459			41,465
Cash and cash equivalents at beginning of period		9,460			9,728

Cash and Cash Equivalents at End of Period	$	89,919		$	51,193

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, 2009, 2008 and 2007 included in the 2009 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. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

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 current and prior quarterly results, the prior year-end results, and the anticipated results of Alagasco and Energen for the year ended December 31, 2010 and determined that the amount was not material to these periods. As a result, the Company corrected this error in the current period.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through 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 equity remains 13.15 percent to 13.65 percent throughout the term of the 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 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. As of January 31 and March 31, 2010, Alagasco had a $2.6 million pre-tax and a $6.2 million pre-tax, respectively, reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. As of September 30, 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. A $10.2 million and $24.7 million annual increase in revenues became effective December 1, 2009 and 2008, respectively.

At September 30, 2009, RSE limited 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. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 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.

The APSC approved an Enhanced Stability Reserve (ESR), with a maximum funding level of $4 million, to which Alagasco may 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) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on average equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. Under the terms of the current RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. In addition to the items mentioned above, Alagasco expects to utilize the ESR 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 $2.7 million as of March 31, 2010, 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 natural gas and crude oil over-the-counter (OTC) swaps, collars 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. The following counterparties, Morgan Stanley Capital Group, Inc., Merrill Lynch Commodities, Inc. and J Aron & Company, represented approximately 33 percent, 23 percent and 19 percent, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net gain position with seven of its counterparties and a net loss with the remaining two at March 31, 2010.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of March 31, 2010, 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, but not all, 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)

March 31, 2010

Oil and Gas
Operations

Natural Gas
Distribution

Total

Derivative assets or (liabilities) designated as hedging instruments

Accounts receivable

177,525

Long-term asset derivative instruments

37,355

Total derivative assets

214,880

Accounts receivable

(32,402

)

Accounts payable

(2,676

)

(2,676

)

Long-term asset derivative instruments

(16,115

)

Long-term liability derivative instruments

(29,127

)

(29,127

)

Total derivative liabilities

(80,320

)

(80,320

)

Total derivatives designated

134,560

Derivative assets or (liabilities) not designated as hedging instruments

Accounts payable

(25

)

(38,706

)

(38,731

)

Long-term liability derivative instruments

(84

)

(31,905

)

(31,989

)

Total derivative liabilities

(109

)

(70,611

)

(70,720

)

Total derivatives not designated

(109

)

(70,611

)

(70,720

)

Total derivatives

134,451

(70,611

)

63,840


(in thousands)	December 31, 2009
	Oil and Gas Operations			Natural Gas Distribution			Total

Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	148,937		$	-		$	148,937
Long-term asset derivative instruments		16,164			-			16,164
Total derivative assets		165,101			-			165,101
Accounts receivable		(29,484	)*		-			(29,484	)
Accounts payable		(6,352	)		-			(6,352	)
Long-term asset derivative instruments		(8,340	)*		-			(8,340	)
Long-term liability derivative instruments		(41,374	)		-			(41,374	)
Total derivative liabilities		(85,550	)		-			(85,550	)
Total derivatives designated		79,551			-			79,551
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable		(10	)*		-			(10	)
Accounts payable		-			(25,750	)		(25,750	)
Long-term liability derivative instruments		(106	)		(18,965	)		(19,071	)
Total derivative liabilities		(116	)		(44,715	)		(44,831	)
Total derivatives not designated		(116	)		(44,715	)		(44,831	)
Total derivatives	$	79,435		$	(44,715	)	$	34,720

*	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 $49.7 million and a net $30.3 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of March 31, 2010 and December 31, 2009, 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 of Gain on Income Statement	Three months ended March 31, 2010		Three months ended March 31, 2009
Gain recognized in OCI on derivative (effective portion), net of tax of $49.7 million and $142.5 million	-	$	81,049	$	232,550
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	36,724	$	69,655
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	1,704	$	200

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

(in thousands)

Location of Gain (Loss) on
Income Statement

Three months ended

March 31, 2010

Three months ended

March 31, 2009

Gain (loss) recognized in income on derivative

Operating revenues

)

As of March 31, 2010, $86.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of March 31, 2010, the Company had 12 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 2010 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2010	10.9 Bcf	$8.74 Mcf	NYMEX Swaps
	29.0 Bcf	$7.22 Mcf	Basin Specific Swaps
2011	11.4 Bcf	$6.82 Mcf	NYMEX Swaps
	25.7 Bcf	$6.36 Mcf	Basin Specific Swaps
Oil
2010	2,988 MBbl	$86.30 Bbl	NYMEX Swaps
2011	3,474 MBbl	$77.01 Bbl	NYMEX Swaps
2012	3,130 MBbl	$81.55 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential


2010	1,765 MBbl	*	Basis Swaps
2011	2,076 MBbl	*	Basis Swaps
2012	672 MBbl	*	Basis Swaps
Natural Gas Liquids
2010	28.3 MMGal	$0.88 Gal	Liquids Swaps
2011	38.9 MMGal	$0.89 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 2010 and subsequent years:


Production Period	Total Hedged Volumes	Description
2010	11.1 Bcf	NYMEX Swaps
2011	10.7 Bcf	NYMEX Swaps
2012	13.4 Bcf	NYMEX Swaps

As of March 31, 2010, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2013 and December 31, 2012, 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 assumptions 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:

March 31, 2010

(in thousands)

Level 2*

Level 3*

Total

Current assets

53,374

91,749

145,123

Noncurrent assets

(2,358

)

23,598

21,240

Current liabilities

(41,332

)

(75

)

(41,407

)

Noncurrent liabilities

(60,284

)

(832

)

(61,116

)

Net derivative asset

(50,600

)

114,440

63,840


	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797	)	$	64,517		$	34,720

*	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.

As of March 31, 2010, Alagasco had $38.7 million and $31.9 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. As of December 31, 2009, Alagasco had $25.8 million and $19 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 March 31, 2010 and December 31, 2009.

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


(in thousands)	Three months ended March 31, 2010			Three months ended March 31, 2009
Balance at beginning of period	$	64,517		$	154,094
Realized gains (losses)		4			(2,175	)
Unrealized gains (losses) relating to instruments held at the reporting date		66,671			75,069
Purchases and settlements during period		(16,752	)		(35,929	)
Balance at end of period	$	114,440		$	191,059

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)


(in thousands, except per share amounts)	Three months ended March 31, 2010					Three months ended March 31, 2009
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	116,710	71,810	$	1.63	$	95,582	71,640	$	1.33
Effect of dilutive securities
Performance share awards			-					116
Stock options			214					91
Non-vested restricted stock			15					50
Diluted EPS	$	116,710	72,039	$	1.62	$	95,582	71,897	$	1.33

For the three months ended March 31, 2010 and 2009, the Company had 479,820 and 964,737, respectively, options which were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months ended March 31, 2010 and 2009, 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 March 31,
(in thousands)	2010		2009
Operating revenues
Oil and gas operations	$	237,614	$	189,120
Natural gas distribution		337,300		294,986
Total	$	574,914	$	484,106
Operating income (loss)


Oil and gas operations	$	117,285		$	81,146
Natural gas distribution		75,255			80,839
Eliminations and corporate expenses		(342	)		(509	)
Total	$	192,198		$	161,476
Other income (expense)
Oil and gas operations	$	(5,871	)	$	(7,268	)
Natural gas distribution		(3,061	)		(4,005	)
Eliminations and other		(214	)		7
Total	$	(9,146	)	$	(11,266	)
Income before income taxes	$	183,052		$	150,210


(in thousands)	March 31, 2010		December 31, 2009
Identifiable assets
Oil and gas operations	$	2,682,645	$	2,654,068
Natural gas distribution		1,178,047		1,084,666
Subtotal		3,860,692		3,738,734
Eliminations and other		179,870		64,384
Total	$	4,040,562	$	3,803,118

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:


	Three months ended March 31,
(in thousands)	2010			2009
Net income	$	116,710		$	95,582
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $34 million and $46 million		55,469			74,993
Reclassification adjustment for derivative instruments, net of tax of ($14.6) million and ($26.5) million		(23,825	)		(43,310	)
Pension and postretirement plans, net of tax of $0.3 million and $0.3 million		628			510
Comprehensive income	$	148,982		$	127,775


(in thousands)	March 31, 2010			December 31, 2009
Unrealized gain on hedges, net of tax of $49.7 million and $30.3 million	$	81,049		$	49,405
Pension and postretirement plans, net of tax of ($16.8) million and ($17.1) million		(31,162	)		(31,790	)
Accumulated other comprehensive income	$	49,887		$	17,615

7. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. 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 281,110 non-qualified option shares during the first quarter of 2010 with a grant-date fair value of $16.47.

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 171,749 awards during the first quarter of 2010. These awards had a fair value of $17.47 as of March 31, 2010.

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. In the first quarter of 2010, Energen Resources awarded 2,161 Petrotech units with a three year vesting period. These awards had a fair value of $45.13 as of March 31, 2010.

1997 Deferred Compensation Plan

During the three months ended March 31, 2010, the Company had noncash purchases of approximately $1.6 million 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 March 31,

(in thousands)	2010			2009
Service cost	$	2,144		$	1,835
Interest cost		2,841			3,016
Expected long-term return on assets		(3,229	)		(3,501	)
Actuarial loss		1,443			997
Prior service cost amortization		124			145
Net periodic expense	$	3,323		$	2,492

In March 2010 and April 2010, the Company made contributions of $2.3 million and $0.6 million, respectively to the assets of the defined benefit qualified pension plans. In May 2010, the Company made additional required contributions of approximately $4.1 million and additional discretionary contributions of approximately $27 million to the defined benefit qualified pension plans. No additional discretionary contributions are currently anticipated to be made to the pension plans during 2010. For the three months ending March 31, 2010, the Company made benefit payments aggregating $2.1 million to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $150,000 through the remainder of 2010.

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


	Three months ended March 31,

(in thousands)	2010			2009
Service cost	$	516		$	453
Interest cost		1,208			1,212
Expected long-term return on assets		(996	)		(885	)
Actuarial loss		-			57
Transition amortization		479			479
Net periodic expense	$	1,207		$	1,316

For the three months ended March 31, 2010, the Company made contributions aggregating $1.3 million to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $3.5 million to postretirement benefit plan assets through the remainder 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 $189 million through September 2024. During the three months ending March 31, 2010 and 2009, Alagasco recognized approximately $14.8 million and $13.6 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 91.7 Bcf through April 2015.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2010, the fixed price purchases under these guarantees had a maximum term outstanding through March 2011 and an aggregate purchase price of $2.2 million with a market value of $1.7 million.

Income Taxes: Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns are currently under Internal Revenue Service (IRS) examination. In April 2010, the IRS proposed certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. Although the timing of income tax audit resolutions is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million.

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

Legacy Litigation

During recent years, numerous lawsuits have been filed against oil production companies in Louisiana for restoration of oilfield properties. These suits are referred to in the industry as “legacy litigation” because they usually involve operations that were conducted on the affected properties many years earlier. Energen Resources is or has been a party to several legacy litigation lawsuits, most of which result from the operations of predecessor companies. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from legacy litigation in excess of the Company’s accrued provision for estimated liability are not considered material to the Company’s financial position.

Other

Various other 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.

A discussion of certain litigation in the state of Louisiana related to the restoration of oilfield properties is included above under Legal Matters.

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 and agreed to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $3 million to $6.1 million. At the present time, the Company cannot conclude that any amount within this range is a better estimate than any other. During the three months ended March 31, 2010, the Company incurred costs of $51,000 associated with the site. As of March 31, 2010, the Company has accrued a contingent liability of $2.7 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. If it is determined that a greater scope of work is appropriate, then actual costs will likely exceed the preliminary estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

10. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, 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, with a carrying value of $561.3 million approximates $571.6 million at March 31, 2010. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $206.3 million approximates $199.6 million at March 31, 2010. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

11. REGULATORY ASSETS AND LIABILITIES

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


	March 31, 2010				December 31, 2009

(in thousands)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	65,440	$	132	$	66,552
Accretion and depreciation for asset retirement obligation		-		14,206		-		13,566
Gas supply adjustment		-		-		7,059		-
Risk management activities		38,706		31,905		25,750		18,965
RSE adjustment		25		-		25		-
Enhanced stability reserve		-		2,706		-		2,706
Other		234		311		230		344
Total regulatory assets	$	39,097	$	114,568	$	33,196	$	102,133
Regulatory liabilities:
RSE adjustment	$	9,144	$	-	$	1,508	$	-
Unbilled service margin		22,466		-		28,178		-
Gas supply adjustment		42,404		-		-		-
Asset removal costs, net		-		139,322		-		136,799
Asset retirement obligation		-		17,988		-		17,419
Other		33		862		33		870
Total regulatory liabilities	$	74,047	$	158,172	$	29,719	$	155,088

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 three months ended March 31, 2010, 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, 2009	$	88,298
Liabilities incurred		735
Liabilities settled		(250	)
Accretion expense		1,486
Balance of ARO as of March 31, 2010	$	90,269

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exist. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $18 million and $17.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of March 31, 2010 and December 31, 2009, respectively. 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. The accumulated asset removal costs of $139.3 million and $136.8 million for March 31, 2010 and December 31, 2009, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets.

13. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

In September 2009, Energen Resources recorded a $4.9 million pre-tax gain in other operating revenues from the sale of certain oil properties in the Permian Basin. The Company received approximately $6.5 million pre-tax in cash from the sale of this property.

On June 30, 2009, Energen completed the purchase of certain oil properties in the Permian Basin from Range Resources for a cash price of $181 million. This purchase had an effective date of May 1, 2009. Energen acquired proved reserves of approximately 15.2 million barrels of oil equivalents. Of the proved reserves acquired, an estimated 24 percent are undeveloped. Approximately 76 percent of the proved reserves are oil, 16 percent are natural gas liquids and natural gas comprises the remaining 8 percent. Energen Resources used its short-term credit facilities and internally generated cash flows to finance the acquisition.

The following table summarizes the consideration paid for Range Resources and the amounts of the assets acquired and liabilities assumed recognized as of June 30, 2009 (including the effects of closing adjustments).


(in thousands)
Consideration given to Range Resources
Cash (net)	$	181,249
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	182,668
Unproved leasehold properties		3,800
Accounts receivable		4,987
Inventory and other		455
Asset retirement obligation		(6,590	)
Environmental liabilities		(3,124	)
Accounts payable		(947	)
Total identifiable net assets	$	181,249

Included in the Company’s consolidated results of operations for the three months ended March 31, 2010, is $11.6 million of operating revenues and $5.6 million in operating income resulting from operation of the properties acquired from Range Resources.

Summarized below are the consolidated results of operations for the three months ended March 31, 2009, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the period presented. The pro forma information is based on the Company’s consolidated results of operations for the three months ended March 31, 2009, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.


(in thousands)	Three months ended March 31, 2009
Operating revenues	$	492,133
Operating income	$	162,358

During the three months ended March 31, 2010, Energen Resources capitalized approximately $0.9 million of unproved leaseholds costs, approximately $86,000 of which was related to the Company’s acreage position in Alabama shales. Energen used its available cash and existing lines of credit to finance these unproved leasehold costs.

14. RECENTLY ISSUED ACCOUNTING STANDARDS

On January 1, 2010, the Company adopted an accounting standard update to improve financial reporting by companies involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This standard did not have an impact on the consolidated condensed financial statements of the Company.

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. This standard did not have an impact on the consolidated condensed financial statements of the Company.

On January 1, 2010, the Company adopted ASU No. 2010-07, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, which eliminates the requirements for SEC filers to disclose the date through which it has evaluated subsequent events. This standard did not have a material impact on the consolidated condensed financial statements of the Company.

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

RESULTS OF OPERATIONS

Energen’s net income totaled $116.7 million ($1.62 per diluted share) for the three months ended March 31, 2010 compared with net income of $95.6 million ($1.33 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended March 31, 2010, of $71.7 million as compared with $47.1 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $27 million after-tax) and increased oil and natural gas liquids production volumes (approximately $4 million after-tax) were partially offset by increased depreciation, depletion and amortization (DD&A) expense (approximately $4 million after-tax) and increased administrative expense (approximately $3 million after-tax). Energen’s natural gas utility, Alagasco, reported net income of $44.2 million in the first quarter of 2010 compared to net income of $47.5 million. This decrease largely reflects the timing of rate recovery under Alagasco’s rate-setting mechanisms, partially offset by the utility’s ability to earn on a higher level of equity.

Oil and Gas Operations

Revenues from oil and gas operations rose 25.6 percent to $237.6 million for the three months ended March 31, 2010 largely as a result of increased commodity prices along with the impact of higher oil and natural gas liquids production volumes. During the current quarter, revenue per unit of production for natural gas rose 9.9 percent to $7.20 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 49.6 percent to $79.23 per barrel. Natural gas liquids revenue per unit of production increased 6 percent to an average price of $0.88 per gallon.

Production for the current quarter rose primarily due to increased volumes related to the June 2009 purchase of certain Permian Basin oil properties, acquiring proved reserves of approximately 15.2 million barrels of oil equivalents partially offset by normal production declines. Natural gas production in the first quarter declined 1.3 percent to 17.4 billion cubic feet (Bcf), oil volumes increased 8.8 percent to 1,186 thousand barrels (MBbl) and natural gas liquids production increased 7.4 percent to 18.8 million gallons (MMgal). Natural gas comprised approximately 64 percent of Energen Resources’ production for the current quarter.

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. 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. Energen Resources recorded a pre-tax gain of $0.3 million in the first quarter of 2009 on the sale of various properties.

O&M expense increased $3.1 million for the quarter. Lease operating expense (excluding production taxes) decreased $2 million for the quarter largely due to lower nonoperated costs ($2.6 million), decreased repair and maintenance expense ($1.1 million), decreased workover expense ($0.9 million), lower ad valorem taxes (approximately $0.6 million) and decreased electrical costs ($0.3 million), partially offset by the June 2009 acquisition of Permian Basin oil properties (approximately $2.6 million) and additional transportation and marketing costs ($1.2 million). Administrative expense increased $4.1 million for the three months ended March 31, 2010 largely due to higher labor and benefit costs primarily related to the Company’s performance-based compensation plans (approximately $3.5 million) and increased legal expenses (approximately $1.1 million). Exploration expense rose $1 million in the first quarter of 2010.

Energen Resources’ DD&A expense for the quarter rose $6.7 million. The average depletion rate for the current quarter was $1.76 per thousand cubic feet equivalent (Mcfe) as compared to $1.54 per Mcfe in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $7.2 million to the increase in DD&A expense, was largely due to higher development costs along with the reserve revisions associated with lower year-end reserve pricing. Partially offsetting the increases in DD&A, Energen Resources experienced higher production in low rate areas which was offset by lower production in high rate areas resulting in a net production volume impact of approximately $0.5 million in the three months ended March 31, 2010.

Energen Resources’ expense for taxes other than income taxes was $2.1 million higher in the three months ended March 31, 2010 largely due to production-related taxes. In the current quarter, higher oil, natural gas and natural gas liquid commodity market prices and the impact of increased production volumes contributed approximately $1.9 million and $0.2 million, respectively, to the increase in production-related taxes. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues increased $42.3 million for the quarter largely due to an increase in customer usage, slightly offset by a decline in gas costs and adjustments from the utility’s rate-setting mechanisms. In the current quarter, Alagasco had an $8.8 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Weather that was 42 percent colder compared with the same quarter in the prior year contributed to a 33.7 percent increase in residential sales volumes and a 25.4 percent increase in commercial and industrial customer sales volumes. Transportation volumes rose 15.6 percent in period comparisons. A significant increase in gas purchase volumes partially offset by a decrease in gas costs resulted in a 29.7 percent increase in cost of gas for the quarter. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense rose 1.1 percent in the current quarter primarily due to increased labor-related costs (approximately $1.8 million), increased consulting and technology cost (approximately $1.2 million), higher marketing expenses (approximately $0.7 million) and increased distribution operation expenses (approximately $0.6 million). Partially offsetting these increases was a decrease to bad debt expense (approximately $3.7 million) which included the correction of a $3 million error identified by Alagasco 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 3.4 percent increase in depreciation expense in the current quarter was primarily due to extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company increased $0.2 million in the first quarter of 2010. Income tax expense for the Company increased $11.7 million in the current quarter largely due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $269.2 million as compared to $236.9 million in the prior period. Net income increased during period comparisons primarily due to higher realized commodity prices along with increased production volumes at Energen Resources. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices and the timing of payments. Working capital needs at Alagasco were additionally affected by decreased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $65.4 million for the three months ended March 31, 2010 primarily due to additions of property, plant and equipment. Energen Resources invested $51.5 million (includes approximately $12.7 million of payments associated with accrued development cost) in capital expenditures primarily related to the acquisition and development of oil and gas properties. In January 2010, Energen Resources completed purchases of certain properties for a total cash price of approximately $3.9 million. Utility capital expenditures totaled $14.3 million (excludes approximately $1.9 million of accrued capital cost) year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company used $8.6 million for net financing activities in the year-to-date primarily for the payment of dividends to common shareholders.

Oil and Gas Operations

The Company anticipates continued price volatility due to supply-and-demand factors, weather, natural disasters, changes in global economics and political unrest. Commodity price volatility will affect the Company’s revenue and associated cash flow available for investment.

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2010, the Company expects its oil and gas capital spending to total approximately $315 million, including $288 million for existing properties and a total of $3.9 million for acquisitions in the Permian and San Juan basins.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama. 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 short-term 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.

Alabama Shales

As of March 31, 2010, Energen Resources had approximately $39 million of unproved leasehold costs related to its lease position in Alabama shales of which $13 million are associated with the Chattanooga shale formation with the remainder associated with the Conasauga shale formation. In the event further efforts are unsuccessful and the Company concludes no further activity is warranted, Energen Resources would expect to record a loss associated with well costs and the non-cash write-off on capitalized unproved leasehold. Energen Resources began drilling a well during the first quarter of 2010 in order to determine economic viability of the Chattanooga shale formation with anticipated results by the summer of 2010. Energen Resources also has re-entered a Conasauga shale well in order to cost effectively evaluate its shale potential in Alabama. Results of additional testing in the well will help the Company determine the feasibility of drilling a new well in the Conasauga shale formation.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on equity of 13.15 percent to 13.65 percent. At September 30, 2009, RSE limited 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.

Over the past several years, a higher commodity price environment and reduced economic activity have contributed to the decline in the utility’s customer base and in declines in usage volume per customer. While the commodity price environment has moderated, a return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in increases in the utility’s GSA. 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.

Alagasco maintains an investment in storage gas that is expected to average approximately $34 million in 2010 but will vary depending upon the price of natural gas. During 2010, Alagasco plans to invest an estimated $80 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 short-term credit facilities.

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 natural gas and crude oil 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. The Company’s current counterparties with active positions are Morgan Stanley Capital Group, Inc., J Aron & Company, Citibank, N.A., Bank of Montreal, Merrill Lynch Commodities, Inc., BP, Barclays Bank PLC, Wachovia Bank National Association and Shell Energy North America (US), L.P. At March 31, 2010, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with seven of its counterparties and a net loss position with the remaining two at March 31, 2010. 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 2010 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2010	10.9 Bcf	$8.74 Mcf	NYMEX Swaps
	29.0 Bcf	$7.22 Mcf	Basin Specific Swaps
2011	11.4 Bcf	$6.82 Mcf	NYMEX Swaps
	25.7 Bcf	$6.36 Mcf	Basin Specific Swaps
Oil
2010	2,988 MBbl	$86.30 Bbl	NYMEX Swaps
2011	3,474 MBbl	$77.01 Bbl	NYMEX Swaps
2012	3,130 MBbl	$81.55 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential
2010	1,765 MBbl	**	Basis Swaps
2011	2,076 MBbl	**	Basis Swaps
2012	672 MBbl	**	Basis Swaps
Natural Gas Liquids
2010	28.3 MMGal	$0.88 Gal	Liquids Swaps
2011	38.9 MMGal	$0.89 Gal	Liquids Swaps
2012	*18.1 MMGal	$0.91 Gal	Liquids Swaps
* Contract entered into subsequent to March 31, 2010. **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 2010 and subsequent years:


Production Period	Total Hedged Volumes	Description
2010	11.1 Bcf	NYMEX Swaps
2010	*0.8 Bcf	NYMEX Swaps
2011	10.7 Bcf	NYMEX Swaps
2011	*3.3 Bcf	NYMEX Swaps
2012	13.4 Bcf	NYMEX Swaps
2012	*1.5 Bcf	NYMEX Swaps
* Contract entered into subsequent to March 31, 2010.

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

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

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

March 31, 2010

(in thousands)

Level 2*

Level 3*

Total

Current assets

53,374

91,749

145,123

Noncurrent assets

(2,358

)

23,598

21,240

Current liabilities

(41,332

)

(75

)

(41,407

)

Noncurrent liabilities

(60,284

)

(832

)

(61,116

)

Net derivative asset

(50,600

)

114,440

63,840


	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797	)	$	64,517		$	34,720

*	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.

As of March 31, 2010, Alagasco has $38.7 million and $31.9 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. As of December 31, 2009, Alagasco has $25.8 million and $19 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 March 31, 2010 and December 31, 2009.

Level 3 assets and liabilities as of March 31, 2010 represent approximately 3 percent of total assets and an immaterial amount of total liabilities, respectively. 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 $29.6 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 three months ended March 31, 2010. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its short-term credit facilities. During the three months ended March 31, 2010, the Company had noncash purchases of approximately $2.1 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.

Short-Term Credit Facilities

Energen and Alagasco rely upon excess cash flows supplemented by short-term credit facilities to fund working capital needs. Energen and Alagasco are subject to the risk that these facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs. These short-term credit facilities are 364-day committed bilateral agreements. The Company currently has available short-term credit facilities as follows:


(in thousands)	Current Term	Energen		Alagasco		Total
Regions Bank	4/22/2011	$	165,000	$	35,000	$	200,000
Wachovia Bank, National Association	6/30/2010		100,000		100,000		100,000
Compass Bank	7/29/2010		70,000		70,000		70,000
Citicorp USA, Inc.	4/15/2011		20,000		15,000		35,000
First Commercial	7/29/2010		-		25,000		25,000
The Northern Trust Company	10/31/2011		25,000		35,000		35,000
BancorpSouth Bank	5/26/2010		-		10,000		10,000
Total		$	380,000	$	290,000	$	475,000

Dividends

Energen expects to pay annual cash dividends of $0.52 per share on the Company’s common stock in 2010. 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. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2009.

Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns are currently under Internal Revenue Service (IRS) examination. In April 2010, the IRS proposed certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. Although the timing of income tax audit resolutions is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million.

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

Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company’s forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

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, 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 uncertainties, all of which are difficult to predict.

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. 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. Market volatility and credit market disruption have historically 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 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 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.

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.

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. The three largest oil, natural gas and natural gas liquids purchasers are expected to account for approximately 21 percent, 17 percent and 13 percent, respectively, of Energen Resources’ estimated 2010 production. Energen Resources’ other purchasers are each expected to purchase less than 8 percent of estimated 2010 production.

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 Energen Resources’, Alagasco’s and the Company’s financial position, results of operations and cash flows.

Alagasco’s 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 March 31,
(in thousands, except sales price data)	2010			2009
Oil and Gas Operations
Operating revenues
Natural gas	$	125,427		$	115,635
Oil		93,975			57,742
Natural gas liquids		16,536			14,522
Other		1,676			1,221
Total	$	237,614		$	189,120

Production volumes
Natural gas (MMcf)		17,412			17,650
Oil (MBbl)		1,186			1,090
Natural gas liquids (MMgal)		18.8			17.5
Total production volumes (MMcfe)		27,209			26,692

Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	7.20		$	6.55
Oil (barrel)	$	79.23		$	52.97
Natural gas liquids (gallon)	$	0.88		$	0.83
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	7.20		$	6.55
Oil (barrel)	$	79.23		$	52.97
Natural gas liquids (gallon)	$	0.88		$	0.83
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	5.24		$	3.98
Oil (barrel)	$	74.49		$	36.02
Natural gas liquids (gallon)	$	0.95		$	0.48

Other data
Lease operating expense (LOE)
LOE and other	$	43,839		$	45,872
Production taxes		9,941			7,841
Total	$	53,780		$	53,713
Depreciation, depletion and amortization	$	48,696		$	41,963
Capital expenditures	$	38,563		$	74,615
Exploration expenditures	$	1,184		$	150
Operating income	$	117,285		$	81,146

Natural Gas Distribution
Operating revenues
Residential	$	241,406		$	204,528
Commercial and industrial		84,290			75,376
Transportation		17,833			15,016
Other		(6,229	)		66
Total	$	337,300		$	294,986


Gas delivery volumes (MMcf)
Residential		14,962		11,191
Commercial and industrial		5,727		4,568
Transportation		12,682		10,969
Total		33,371		26,728
Other data
Depreciation and amortization	$	13,039	$	12,615
Capital expenditures	$	16,360	$	16,110
Operating income	$	75,255	$	80,839

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 natural gas and crude oil 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 March 31, 2010, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2013.

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

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

The Company’s interest rate exposure as of March 31, 2010, was minimal as 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**
January 1, 2010 through January 31, 2010	44,205	*	$	46.89	-	8,992,700
February 1, 2010 through February 28, 2010	-			-	-	8,992,700
March 1, 2010 through March 31, 2010	1,556	*	$	46.09	-	8,992,700
Total	45,761		$	46.87	-	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 Marcy 31, 2010, 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, tagged as blocks of text.

SIGNATURES

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


	ENERGEN CORPORATION ALABAMA GAS CORPORATION

May 7, 2010	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and
		President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation

May 7, 2010	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer
		and Treasurer of Energen Corporation
		and Alabama Gas Corporation

May 7, 2010	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation

May 7, 2010	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

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