Edgar Filing: ENERGEN 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, 2006

¨	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 is a large accelerated filer, an accelerated filer, or a non- accelerated filer (as defined in Rule 12b-2 of the Act).


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

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 2, 2006.


Energen Corporation	$0.01 par value	73,468,950 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, 2006

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	30

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31

Item 4.	Controls and Procedures	32

	PART II: OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 4.	Submission of Matters to a Vote of Security Holders	33

Item 6.	Exhibits	33

SIGNATURES		34

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)	2006			2005
Operating Revenues
Oil and gas operations	$	169,519		$	102,880
Natural gas distribution		318,623			258,128
Total operating revenues		488,142			361,008
Operating Expenses
Cost of gas		194,050			136,855
Operations and maintenance		74,483			60,405
Depreciation, depletion and amortization		34,297			31,425
Taxes, other than income taxes		32,679			26,550
Accretion expense		898			643
Total operating expenses		336,407			255,878
Operating Income		151,735			105,130
Other Income (Expense)
Interest expense		(13,177	)		(11,670	)
Other income		707			353
Other expense		(229	)		(268	)
Total other expense		(12,699	)		(11,585	)
Income From Continuing Operations Before Income Taxes		139,036			93,545
Income tax expense		51,535			34,603
Income From Continuing Operations		87,501			58,942
Discontinued Operations, Net of Taxes
Loss from discontinued operations		(7	)		(19	)
Gain on disposal of discontinued operations		—			123
Income (Loss) From Discontinued Operations		(7	)		104
Net Income	$	87,494		$	59,046
Diluted Earnings Per Average Common Share*
Continuing operations	$	1.18		$	0.80
Discontinued operations		—			—
Net Income	$	1.18		$	0.80
Basic Earnings Per Average Common Share*
Continuing operations	$	1.19		$	0.81
Discontinued operations		—			—
Net Income	$	1.19		$	0.81
Dividends Per Common Share*	$	0.11		$	0.10
Diluted Average Common Shares Outstanding*		74,094			73,657
Basic Average Common Shares Outstanding*		73,268			72,952

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)


(in thousands)	March 31, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	8,622	$	8,714
Accounts receivable, net of allowance for doubtful accounts of $13,470 at March 31, 2006, and $11,573 at December 31, 2005		232,840		285,765
Inventories, at average cost
Storage gas inventory		56,352		71,179
Materials and supplies		8,076		7,926
Liquified natural gas in storage		3,630		3,795
Regulatory asset		906		6,633
Deferred income taxes		40,306		72,113
Prepayments and other		24,033		22,366
Total current assets		374,765		478,491
Property, Plant and Equipment
Oil and gas properties, successful efforts method		1,973,013		1,930,291
Less accumulated depreciation, depletion and amortization		489,581		466,643
Oil and gas properties, net		1,483,432		1,463,648
Utility plant		1,013,846		999,011
Less accumulated depreciation		406,025		401,232
Utility plant, net		607,821		597,779
Other property, net		8,207		6,584
Total property, plant and equipment, net		2,099,460		2,068,011
Other Assets
Regulatory asset		33,596		33,436
Deferred charges and other		39,467		38,288
Total other assets		73,063		71,724
TOTAL ASSETS	$	2,547,288	$	2,618,226

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

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)


(in thousands, except share and per share data)	March 31, 2006			December 31, 2005
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	15,000		$	15,000
Notes payable to banks		55,000			153,000
Accounts payable		173,967			306,618
Accrued taxes		72,695			44,324
Customers’ deposits		20,877			20,767
Amounts due customers		—			6,181
Accrued wages and benefits		21,566			33,634
Regulatory liability		38,830			53,496
Other		54,378			55,289
Total current liabilities		452,313			688,309
Long-term debt		683,263			683,236
Deferred Credits and Other Liabilities
Asset retirement obligation		50,678			50,270
Accrued benefit liability		16,115			15,739
Regulatory liability		121,865			119,808
Deferred income taxes		161,427			148,040
Other		33,096			20,146
Total deferred credits and other liabilities		383,181			354,003
Commitments and Contingencies
Shareholders’ equity
Preferred stock, $0.01 par value, 5,000,000 shares authorized		—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 73,532,115 shares outstanding at March 31, 2006, and 73,493,337 shares outstanding at December 31, 2005		735			735
Premium on capital stock		404,724			394,861
Capital surplus		2,802			2,802
Retained earnings		682,726			603,314
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges		(44,425	)		(92,112	)
Minimum pension liability		(13,707	)		(13,707	)
Deferred compensation on restricted stock		(2,282	)		(2,123	)
Deferred compensation plan		11,575			11,907
Treasury stock, at cost (1,043,527 shares at March 31, 2006, and 1,066,935 shares at December 31, 2005)		(13,617	)		(12,999	)
Total shareholders’ equity		1,028,531			892,678
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,547,288		$	2,618,226

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

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)


Three months ended March 31, (in thousands)	2006			2005
Operating Activities
Net income	$	87,494		$	59,046
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		34,297			31,453
Deferred income taxes		15,961			13,492
Change in derivative fair value		2,217			16,987
Gain on sale of assets		(22	)		(307	)
Other, net		2,239			4,756
Net change in:
Accounts receivable, net		44,740			11,261
Inventories		14,842			21,915
Accounts payable		(39,424	)		(24,161	)
Amounts due customers		(14,331	)		6,582
Other current assets and liabilities		19,623			13,331
Net cash provided by operating activities		167,636			154,355
Investing Activities
Additions to property, plant and equipment		(62,473	)		(50,499	)
Acquisitions, net of cash acquired		—			(3,873	)
Proceeds from sale of assets		37			8,677
Other, net		(428	)		(325	)
Net cash used in investing activities		(62,864	)		(46,020	)
Financing Activities
Payment of dividends on common stock		(8,082	)		(7,322	)
Issuance of common stock		2,970			2,629
Purchase of treasury stock		(2,522	)		(961	)
Reduction of long-term debt		(10	)		(30	)
Proceeds from issuance of long-term debt		—			80,000
Debt issuance costs		—			(1,857	)
Net change in short-term debt		(98,000	)		(135,000	)
Other		780			—
Net cash used in financing activities		(104,864	)		(62,541	)
Net change in cash and cash equivalents		(92	)		45,794
Cash and cash equivalents at beginning of period		8,714			4,489
Cash and Cash Equivalents at End of Period	$	8,622		$	50,283

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

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)


	Three months ended March 31,
(in thousands)	2006			2005
Operating Revenues	$	318,623		$	258,128
Operating Expenses
Cost of gas		194,050			137,376
Operations and maintenance		30,879			27,826
Depreciation and amortization		10,746			10,413
Income taxes
Current		24,163			25,266
Deferred		(1,444	)		(1,467	)
Taxes, other than income taxes		19,221			16,109
Total operating expenses		277,615			215,523
Operating Income		41,008			42,605
Other Income (Expense)
Allowance for funds used during construction		223			185
Other income		473			221
Other expense		(229	)		(265	)
Total other income		467			141
Interest Charges
Interest on long-term debt		3,237			3,413
Other interest expense		869			329
Total interest charges		4,106			3,742
Net Income	$	37,369		$	39,004

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

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)


(in thousands)	March 31, 2006			December 31, 2005
ASSETS
Property, Plant and Equipment
Utility plant	$	1,013,846		$	999,011
Less accumulated depreciation		406,025			401,232
Utility plant, net		607,821			597,779
Other property, net		167			169
Current Assets
Cash and cash equivalents		6,682			7,169
Accounts receivable
Gas		167,685			194,447
Other		5,000			7,524
Affiliated companies		9,255			3,215
Allowance for doubtful accounts		(12,700	)		(10,800	)
Inventories, at average cost
Storage gas inventory		56,352			71,179
Materials and supplies		4,209			4,144
Liquified natural gas in storage		3,630			3,795
Deferred income taxes		14,281			13,284
Regulatory asset		906			6,633
Prepayments and other		11,930			11,203
Total current assets		267,230			311,793
Other Assets
Regulatory asset		33,596			33,436
Deferred charges and other		7,446			6,857
Total other assets		41,042			40,293
TOTAL ASSETS	$	916,260		$	950,034

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, 2006		December 31, 2005
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares outstanding at March 31, 2006 and December 31, 2005		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		266,702		236,957
Total common shareholder’s equity		301,206		271,461
Long-term debt		209,644		209,654
Total capitalization		510,850		481,115
Current Liabilities
Long-term debt due within one year		5,000		5,000
Notes payable to banks		26,000		55,000
Accounts payable		77,147		112,443
Accrued taxes		53,703		32,770
Customers’ deposits		20,877		20,767
Amounts due customers		—		6,181
Accrued wages and benefits		9,570		11,449
Regulatory liability		38,830		53,496
Other		9,314		8,694
Total current liabilities		240,441		305,800
Deferred Credits and Other Liabilities
Deferred income taxes		39,507		39,949
Minimum pension liability		193		—
Regulatory liability		121,865		119,808
Other		3,404		3,362
Total deferred credits and other liabilities		164,969		163,119
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	916,260	$	950,034

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)	2006			2005
Operating Activities
Net income	$	37,369		$	39,004
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10,746			10,413
Deferred income taxes		(1,444	)		(1,467	)
Other, net		925			1,700
Net change in:
Accounts receivable		23,002			13,867
Inventories		14,927			22,952
Accounts payable		(29,569	)		(29,633	)
Amounts due customers		(14,331	)		6,582
Other current assets and liabilities		19,523			24,546
Net cash provided by operating activities		61,148			87,964
Investing Activities
Additions to property, plant and equipment		(18,603	)		(14,590	)
Other, net		(358	)		(393	)
Net cash used in investing activities		(18,961	)		(14,983	)
Financing Activities
Dividends		(7,624	)		(7,318	)
Reduction of long-term debt		(10	)		(30	)
Proceeds from issuance of long-term debt		—			80,000
Debt issuance costs		—			(1,697	)
Net advances to affiliates		(6,040	)		(16,725	)
Net change in short-term debt		(29,000	)		(82,000	)
Net cash used in financing activities		(42,674	)		(27,770	)
Net change in cash and cash equivalents		(487	)		45,211
Cash and cash equivalents at beginning of period		7,169			3,467
Cash and Cash Equivalents at End of Period	$	6,682		$	48,678

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, 2005, 2004 and 2003 included in the 2005 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.

The quarterly information reflects the application of Statement of Financial Accounting Standard (SFAS) No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that gains and losses from the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations in the current and prior periods. All other 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.

2.	STOCK-BASED COMPENSATION

The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective application method for new awards effective January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123 as amended, “Accounting for Stock-Based Compensation,” prospectively for stock-based compensation effective January 1, 2003. As a result, the adoption of SFAS No. 123R did not have a significant impact to the Company since the expensing provisions were voluntarily adopted in 2003.

SFAS No. 123R requires that all share-based compensation awards be measured at fair value at the date of grant and expensed over the requisite vesting period. SFAS No. 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Prior to the adoption of SFAS No. 123R, the Company accounted for forfeitures upon occurrence. This change in method did not have a significant impact to the Company upon adoption of SFAS No. 123R.

The Company previously recognized all stock-based employee compensation expense over the stated vesting periods for each award. For awards granted prior to January 1, 2006, the Company immediately recorded any unrecognized expense on the date of an employee’s retirement. For new awards granted to retirement eligible employees effective January 1, 2006, the Company began recognizing the entire compensation expense in the period of grant. If this method of expense recognition had been applied for all awards during the three months ended March 31, 2006 and 2005, expense would have been reduced by approximately $0.5 million and $0.3 million, respectively. The Company utilized the long-form method of calculating the available pool of windfall tax benefit. For the three months ended March 31, 2006, the Company recognized a tax benefit of $0.8 million related to its stock-based compensation.

The following table illustrates the effect on net income and diluted and basic earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, superseded by SFAS No. 123R, for the three months ended March 31, 2005, to all outstanding and unvested employee share-based awards:


(in thousands, except per share data)	Three months ended March 31, 2005
Net income
As reported	$	59,046
Stock-based compensation expense included in reported net income, net of tax		1,768
Stock-based compensation expense determined under the fair value based method, net of tax		(1,442	)
Pro forma	$	59,372
Diluted earnings per average common share*
As reported	$	0.80
Pro forma	$	0.81
Basic earnings per average common share*
As reported	$	0.81
Pro forma	$	0.81

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

1997 Stock Incentive Plan and 1988 Stock Option Plan:

Performance Share Awards: The Energen 1997 Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. This criteria is considered a market condition as defined by SFAS No. 123R. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards be made in the form of Company common stock, with no portion of an award paid in cash. This amendment affected 29 participants. Prior to the amendment, payment of performance awards could be made in cash or in a combination of Company common stock or cash. The impact of this modification was not significant to the Company.

1997 Stock Incentive Plan performance share awards granted or modified after the adoption of SFAS No. 123R have been valued in a Monte Carlo model. The Monte Carol model uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. For performance share awards granted prior to the adoption of SFAS No. 123R, the Company estimated fair value based on the quoted market price of the Company’s common stock and adjusted each period for the expected payout ratio.

A summary of performance share award activity as of March 31, 2006, and transactions during the three months then ended, is presented below:


	1997 Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2005	477,720		$	40.26
Granted	111,990			43.81
Forfeitures	(847	)		43.81
Nonvested at March 31, 2006	588,863		$	39.48

The Company recorded expense of $2,067,000 and $1,975,000 for the three months ended March 31, 2006 and 2005, respectively, for performance share awards with a related deferred income tax benefit of $782,000 and $747,000, respectively. As of March 31, 2006, there was $10.8 million of total unrecognized compensation cost related to performance share awards. These awards have a weighted average requisite service period of 1.66 years from the date of grant.

Stock Options: The 1997 Stock Incentive Plan and the Energen 1988 Stock Option Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plans 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. Under the 1988 Stock Option Plan, 1,080,000 shares of Company common stock reserved for issuance have been granted. Under the 1997 Stock Incentive Plan, 5,600,000 shares of Company common stock were reserved for

issuance with 2,006,055 remaining for issuance as of March 31, 2006. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.

A summary of stock option activity as of March 31, 2006, and transactions during the three months then ended, is presented below:


	1997 Stock Incentive Plan				1988 Stock Option Plan
	Shares		Weighted Average Exercise Price		Shares	Weighted Average Exercise Price
Outstanding at December 31, 2005	613,400		$	14.04	28,000	$	9.13
Exercised	(14,140	)		14.07	—		—
Outstanding at March 31, 2006	599,260		$	14.04	28,000	$	9.13
Exercisable at March 31, 2006	516,500		$	12.79	28,000	$	9.13

The Company used the Black-Scholes pricing model to calculate the fair values of the options awarded. Option awards were granted with an exercise price equal to the market price of the Company’s stock on the date of grant. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year option life based on historical experience; an annualized volatility rate, based on historical volatility, of 32.72 percent and 34.67 percent for the years ended December 31, 2004 and 2003, respectively; a risk-free interest rate of 3.64 percent and 2.36 percent for the years ended December 31, 2004 and 2003, respectively; and a dividend yield of 1.81 percent on options without dividend equivalents for the year ended December 31, 2004. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted without dividend equivalents during the year ended December 31, 2004 was $7.11. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $6.05. There were no options granted during 2006 or 2005. The Company recorded expense of $49,000 and $116,000 during the three months ended March 31, 2006 and 2005, respectively, for options with a related deferred income tax benefit of $10,000 and $26,000, respectively.

Total intrinsic value of stock options and stock appreciation rights exercised during the first quarter of 2006 were $13,000 and $316,000, respectively. During the three months ended March 31, 2006, the Company received cash of $8,000 from the exercise of stock options and paid $316,000 in settlement of stock appreciation rights. Total intrinsic value for outstanding options as of March 31, 2006, was $13.2 million and $12.1 million for exercisable options. The fair value of options vested during the three months ended March 31, 2006 was $3.3 million. As of March 31, 2006, there was $147,000 of unrecognized compensation cost related to outstanding nonvested stock options, all of which will be recognized during 2006.

The following table summarizes options outstanding as of March 31, 2006:


1997 Stock Incentive Plan			1988 Stock Option Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life	Range of Exercise Prices		Shares	Weighted Average Remaining Contractual Life
$9.13-$9.41	98,724	2.71 years	$	9.13	28,000	1.67 years
$13.72	123,200	4.58 years		—	—	—
$11.32	69,516	5.58 years		—	—	—
$14.86	225,060	6.83 years		—	—	—
$21.38	82,760	7.83 years		—	—	—
$9.13-$21.38	599,260	5.68 years	$	9.13	28,000	1.67 years

The weighted average remaining contractual life of currently exercisable stock options is 5.34 years as of March 31, 2006.

Restricted Stock: In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. A summary of restricted stock activity as of March 31, 2006, and transactions during the three months then ended, is presented below:


	1997 Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2005	242,444		$	20.48
Granted	23,500			38.11
Vested	(68,564	)		18.25
Nonvested at March 31, 2006	197,380		$	23.35

The Company recorded expense of $737,000 and $452,000 for the months ended March 31, 2006 and 2005, respectively, related to restricted stock, with a related deferred income tax benefit of $279,000 and $171,000, respectively. As of March 31, 2006, there was $2.3 million of total unrecognized compensation cost related to nonvested restricted stock awards. These awards have a requisite service period of 1.54 years from the date of grant.

The Company typically funds options, restricted stock obligations and performance share obligations through original issue shares.

2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided 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. These awards have a three year requisite service period. Awards granted prior to January 1, 2006 were valued using the intrinsic value method. There were no awards granted in 2006 or 2005. For the three months ended March 31, 2006 and 2005, the Company recorded income of $5,000 and expense of $269,000, respectively, associated with stock appreciation rights.

2005 Petrotech Incentive Plan: The Energen Resources’ 2005 Petrotech Incentive Plan provided for the grant of restricted stock units which may include market conditions. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. Effective January 1, 2006, fair value of the restricted stock units with a market condition was calculated using a Monte Carlo approach. Restricted stock units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends. Prior to the implementation of SFAS 123R, these awards were valued using the Company’s common stock price at each period end.

For the three months ended March 31, 2006, Energen Resources awarded 26,440 performance units of which 22,905 included a market condition. Energen Resources awarded 23,460 performance units in the three months ended March 31, 2005 of which 11,730 included a market condition. The Company recognized expense of $25,000 during the three months ended March 31, 2006 related to these performance units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders’ Equity.

3. REGULATORY

All of Alagasco’s utility operations are conducted in the state of Alabama. 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 was extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco’s rate-setting methodology, RSE, without change, for a six-year period through

January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. Alagasco is on 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. Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. 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 September 30, 2005, Alagasco had a $3.3 million reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. A $15.8 million and a $12.3 million annual increase in revenues became effective December 1, 2005 and 2004, respectively. RSE limits the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 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 per customer 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. Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005.

Alagasco calculates a temperature adjustment to customers’ monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco’s earnings. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. 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.

4.	DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and 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. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s or Alagasco’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company or Alagasco in the event credit ratings are below investment grade. At March 31, 2006, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of March 31, 2006. The Company believes the creditworthiness of these counterparties is satisfactory.

Energen Resources applies SFAS No. 133 which requires all derivatives to be recognized on the balance sheet and measured 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 equity and subsequently reclassified into earnings 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. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

As of March 31, 2006, $30 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues during the next 12-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. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a $1.7 million after-tax loss for the three months ended March 31, 2006. As of March 31, 2006, all of the Company’s hedges met the definition of a cash flow hedge. The Company had $27.2 million and $56.5 million included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of March 31, 2006 and December 31, 2005, respectively. At March 31, 2006, and December 31, 2005, the Company had $52.2 million and $145.9 million, respectively, of current losses recorded in accounts payable and $24.7 million and $11.9 million, respectively, of non-current losses recorded in deferred credits and other liabilities related to derivative contracts.

Energen Resources has entered into the following transactions for the remainder of 2006 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2006	12.1 Bcf	$8.07 Mcf	NYMEX Swaps
	16.3 Bcf	$6.47 Mcf	Basin Specific Swaps
2007	8.0 Bcf	$9.48 Mcf	NYMEX Swaps
	12.0 Bcf	$8.03 Mcf	Basin Specific Swaps
Oil
2006	2,110 MBbl	$52.76 Bbl	NYMEX Swaps
2007	1,200 MBbl	$63.35 Bbl	NYMEX Swaps
2008	900 MBbl	$57.71 Bbl	NYMEX Swaps
2009	900 MBbl	$56.25 Bbl	NYMEX Swaps
Oil Basis Differential
2006	1,426 MBbl	*	Basis Swaps
2007	600 MBbl	*	Basis Swaps
Natural Gas Liquids
2006	22.7 MMGal	$0.56 Gal	Liquids Swaps
2007	10.1 MMGal	$0.80 Gal	Liquids Swaps

*	Average contract prices are not meaningful due to the varying nature of each contract.

All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in hedging the exposure to the hedged transaction’s variability in cash flows attributable to the hedged risk will be assessed and measured. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.

On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility’s cost of gas supply. As required by SFAS No. 133, 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. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” at March 31, 2006, Alagasco recognized a $1.7 million gain as an asset in prepayments and other with a corresponding current regulatory liability of $1.7 million representing the fair value of derivatives. Alagasco also recorded a $0.6 million loss as a liability in accounts payable with a corresponding current regulatory asset of $0.6 million representing the fair value of derivatives. At December 31, 2005, Alagasco recognized a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives.

5.	RECONCILIATION OF EARNINGS PER SHARE*


	Three months ended March 31, 2006					Three months ended March 31, 2005
(in thousands, except per share amounts)	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Basic EPS	$	87,494	73,268	$	1.19	$	59,046	72,952	$	0.81
Effect of Dilutive Securities
Performance share awards			359					288
Stock options			360					364
Restricted stock			107					53
Diluted EPS	$	87,494	74,094	$	1.18	$	59,046	73,657	$	0.80

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

For the three months ended March 31, 2006 and 2005, the Company had no options that were excluded from the computation of diluted EPS. For the three months ended March 31, 2006 the Company had 13,500 shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect were non-dilutive. There were no shares of non-vested restricted stock excluded from the computation of diluted EPS for the quarter ended March 31, 2005.

6.	SEGMENT INFORMATION

The Company principally is engaged in two business segments: the acquisition, development, 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)	2006			2005
Operating revenues from continuing operations
Oil and gas operations	$	169,519		$	103,401
Natural gas distribution		318,623			258,128
Eliminations and other		—			(521	)
Total	$	488,142		$	361,008
Operating income (loss) from continuing operations
Oil and gas operations	$	88,539		$	38,977
Natural gas distribution		63,727			66,404
Eliminations and corporate expenses		(531	)		(251	)
Total	$	151,735		$	105,130
Other income (expense)
Oil and gas operations	$	(9,287	)	$	(8,096	)
Natural gas distribution		(3,639	)		(3,601	)
Eliminations and other		227			112
Total	$	(12,699	)	$	(11,585	)
Income from continuing operations before income taxes	$	139,036		$	93,545


(in thousands)	March 31, 2006		December 31, 2005
Identifiable assets
Oil and gas operations	$	1,604,792	$	1,637,244
Natural gas distribution		907,005		946,819
Subtotal		2,511,797		2,584,063
Eliminations and other		35,491		34,163
Total	$	2,547,288	$	2,618,226

7.	COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:


	Three months ended March 31,
(in thousands)	2006			2005
Net Income	$	87,494		$	59,046
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of $22.2 million and ($43.6) million		36,244			(71,071	)
Reclassification adjustment for losses realized in net income, net of tax of $7 million and $6.5 million		11,443			10,628
Comprehensive Income (Loss)	$	135,181		$	(1,397	)
Accumulated other comprehensive loss consisted of the following:
(in thousands)	March 31, 2006			December 31, 2005
Unrealized loss on hedges, net of tax of ($27.2) million and ($56.5) million	$	(44,425	)	$	(92,112	)
Minimum pension liability, net of tax of ($7.4) million and ($7.4) million		(13,707	)		(13,707	)
Accumulated Other Comprehensive Loss	$	(58,132	)	$	(105,819	)

8.	LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

The Company applies SFAS No. 144, which retains the previous asset impairment requirements of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses on the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources had no property sales during the three months ended March 31, 2006. In the three months ended March 31, 2005, Energen Resources recorded a pre-tax gain of $198,000 primarily from a property sale located in the Permian Basin.

The following were the results of operations from discontinued operations:


	Three months ended March 31,
(in thousands, except per share data)	2006			2005
Oil and gas revenues	$	—		$	36
Pretax loss from discontinued operations	$	(11	)	$	(31	)
Income tax benefit		(4	)		(12	)
Loss From Discontinued Operations		(7	)		(19	)
Gain on disposal of discontinued operations		—			198
Income tax expense		—			75
Gain on Disposal of Discontinued Operations		—			123
Total Income (Loss) From Discontinued Operations	$	(7	)	$	104
Diluted Earnings Per Average Common Share*
Loss from Discontinued Operations	$	—		$	—
Gain on Disposal of Discontinued Operations		—			—
Total Income (Loss) from Discontinued Operations	$	—		$	—
Basic Earnings Per Average Common Share*
Loss from Discontinued Operations	$	—		$	—
Gain on Disposal of Discontinued Operations		—			—
Total Income (Loss) from Discontinued Operations	$	—		$	—

9.	EMPLOYEE BENEFIT PLANS

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


(in thousands)	*Plan A*						*Plan B*
	Three Months Ended March 31,						Three Months Ended March 31,
	2006			2005			2006			2005
Components of net periodic benefit cost:
Service cost	$	1,562		$	1,544		$	157		$	155
Interest cost		1,934			1,886			355			351
Expected long-term return on assets		(2,432	)		(2,199	)		(565	)		(540	)
Actuarial loss		815			687			47			31
Prior service cost amortization		11			59			94			94
Net periodic expense	$	1,890		$	1,977		$	88		$	91

The Company is not required to make pension contributions in 2006 and does not currently plan to make discretionary contributions to Plan A or Plan B assets. The Company may reevaluate discretionary contributions during 2006.

The components of net periodic post-retirement benefit expense for the Company’s post-retirement benefit plans were:


(in thousands)	*Salaried Employees*						*Union Employees*
	Three Months Ended March 31,						Three Months Ended March 31,
	2006			2005			2006			2005
Components of net periodic benefit cost:
Service cost	$	159		$	231		$	154		$	124
Interest cost		419			492			520			515
Expected long-term return on assets		(476	)		(425	)		(728	)		(658	)
Actuarial gain		(142	)		(32	)		(27	)		(36	)
Prior service cost amortization		—			—			—			1
Transition amortization		171			171			309			321
Net periodic expense	$	131		$	437		$	228		$	267

For the three months ended March 31, 2006, the Company made contributions aggregating $0.6 million to the post-retirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.5 million through the remainder of 2006.

10.

COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $230 million through October 2015. 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 168.8 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 consolidated balance sheet. 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, 2006, the fixed price purchases under these guarantees had a maximum term outstanding through December 2006 and an aggregate purchase price of $7.1 million with a market value of $6.2 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 Alabama and other 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.

Cochran County, Texas

In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources’ favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judge’s order and expects to prevail. Under the Judge’s order, Energen Resources’ potential pre-tax charge to income would be approximately $3.4 million as of March 31, 2006, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition.

Jefferson County, Alabama

In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources received notice of immediate lease termination from RGGS. As of December 31, 2005, Energen’s consolidated

balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources’ production associated with the lease was approximately 11 Bcf.

RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination.

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 and is not expected to do so in the future; however, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

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). An investigation of the sites does not indicate the present need for remediation activities. 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, results of operations or cash flows of Alagasco.

11.

REGULATORY ASSETS AND LIABILITIES

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


(in thousands)	March 31, 2006				December 31, 2005
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension asset	$	—	$	22,807	$	—	$	22,807
Accretion and depreciation for asset retirement obligation		—		10,429		—		10,183
Risk management activities		564		—		6,291		—
Other		342		360		342		446
Total regulatory assets	$	906	$	33,596	$	6,633	$	33,436
Regulatory liabilities:
Enhanced stability reserve	$	3,849	$	—	$	3,690	$	—
Gas supply adjustment		15,688		—		22,326		—
Risk management activities		1,669		—		—		—
RSE adjustment		1,271		—		2,943		—
Unbilled service margin		16,353		—		24,537		—
Asset removal costs, net		—		107,282		—		105,404
Asset retirement obligation		—		13,644		—		13,451
Other		—		939		—		953
Total regulatory liabilities	$	38,830	$	121,865	$	53,496	$	119,808

12.

ACQUISITION OF OIL AND GAS PROPERTIES

On December 15, 2005, Energen Resources completed a purchase of Permian Basin oil properties from a private company. The contract purchase price was approximately $168 million with an effective date of November 1, 2005. Approximately 80 percent of the 21.9 million barrels of proved oil reserves are undeveloped. More than 90 percent of the estimated proved reserves are oil. Energen used its available cash and existing lines of credit to finance the acquisition.

13.

STOCK DIVIDEND

On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was payable on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split. Effective April 29, 2005, the Restated Certificate of Incorporation of Energen Corporation was amended to increase the Company’s authorized common stock, par value $0.01 per share, from 75,000,000 shares to 150,000,000 shares.

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

Energen’s net income totaled $87.5 million ($1.18 per diluted share) for the three months ended March 31, 2006 and compared favorably with net income of $59 million ($0.80 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, 2006, of $49.7 million compared with $19.6 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of $49.8 million in the current quarter as compared with $19.5 million in the same quarter last year. Significantly higher commodity prices (approximately $37 million after-tax) and increased production volumes (approximately $4 million after-tax) were partially offset by increased lease operating expenses (approximately $7 million after-tax), higher production taxes (approximately $2 million after-tax) and increased depreciation, depletion and amortization (DD&A) expense (approximately $2 million after-tax). Energen’s natural gas utility, Alagasco, reported net income of $37.4 million in the first quarter of 2006 compared to net income of $39 million in the same period last year primarily reflecting a decrease in customer usage driven by the high price of natural gas 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 64.8 percent to $169.5 million for the three months ended March 31, 2006 largely as a result of increased commodity prices as well as the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas rose 64.5 percent to $7.57 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 43 percent to $45.94 per barrel. Natural gas liquids revenue per unit of production increased 13.7 percent to an average price of $0.58 per gallon.

Production increased primarily due to increased development well drilling in the San Juan Basin and volumes related to the prior year purchase of Permian Basin oil properties. Energen Resources acquired an estimated 21.9 million barrels of proved oil reserves in the Permian Basin in the fourth quarter of 2005. Negatively affecting production was a normal production decline in the Permian and Black Warrior basins. Natural gas production from continuing operations in the first quarter rose 4.4 percent to 15.3 billion cubic feet (Bcf), while oil volumes increased 12 percent to 917 thousand barrels (MBbl) and natural gas liquids production increased 5.2 percent to 16.6 million gallons (MMgal). Natural gas comprised approximately 65 percent of Energen Resources’ production for the current quarter and the year-to-date.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. Energen Resources applies SFAS No. 133 which requires all derivatives to be recognized on the balance sheet and measured 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 equity and subsequently reclassified into earnings 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. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change. For the three months ended March 31, 2006, the Company recorded a $1.7 million after-tax loss on open and closed contracts for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.

Operations and maintenance (O&M) expense increased $10.8 million for the quarter. Lease operating expenses (excluding production taxes) increased by $11.1 million for the quarter primarily due to increased workover and maintenance expenses, higher transportation costs, overall price increases related to higher commodity prices and the December 2005 acquisition of Permian Basin oil properties. Administrative expense decreased $0.1 million for the three months ended March 31, 2006. Exploration expense was lower by $0.2 million in the first quarter comparisons.

Energen Resources’ DD&A expense for the quarter rose $2.5 million. The average depletion rate for the current quarter was $0.99 per Mcfe as compared to $0.94 per Mcfe in the same period a year ago. The increase in the first quarter rate was largely due to a higher depletion rate on oil properties purchased in the Permian Basin in December 2005.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes that were $2.9 million higher this quarter largely due to increased commodity prices and production.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” Energen Resources had no property sales during the three months ended March 31, 2006. In the three months ended March 31, 2005, Energen Resources recorded a pre-tax gain of $198,000 primarily from a property sale located in the Permian Basin.

Natural Gas Distribution

Natural gas distribution revenues increased $60.5 million for the quarter largely due to a significant increase in commodity gas costs partially offset by a decrease in usage. For the quarter, weather was comparable with the same period last year. Residential sales volumes declined 10.2 percent primarily due to customer conservation related to higher gas costs. Commercial and industrial customer sales volumes decreased 6.7 percent while transportation volumes decreased 2.8 percent in period comparisons. A significant increase in gas costs partially offset by a decline in gas purchase volumes resulted in a 41.3 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 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 to certain customers’ bills designed to substantially remove the effect of departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

As discussed more fully in Note 3 to the Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend Alagasco’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to Alagasco and a hearing, the Commission votes to either modify or discontinue its operation.

O&M expense increased 11 percent in the current quarter primarily due to increased bad debt expense and distribution maintenance expenses. A 3.2 percent increase in depreciation expense in the current quarter was due to normal replacement of the utility’s distribution and 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 $1.5 million in the first quarter primarily due to an increase in short-term borrowings related to the December 2005 purchase of Permian Basin oil properties at Energen Resources and an increase in storage inventory at Alagasco. Also influencing interest expense was an increase in interest rates associated with Energen’s $100 million Floating Rate Senior Notes issued in November 2004. An increase in interest expense related to Alagasco’s issuance of $80 million of long-term debt in November 2005 was largely offset by the redemption of $56.7 million and $18 million of long-term debt by Alagasco in December 2005 and August 2005, respectively. In the current quarter, income tax expense for the Company increased $16.9 million largely due to higher pre-tax income.

Stock-Based Compensation

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company’s transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company adopted SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. The adoption of SFAS No. 123R did not have a significant impact on the financial condition or results of operations of the Company (See Note 2, Stock-Based Compensation, in the Notes to Unaudited Condensed Financial Statements).

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $167.6 million as compared to $154.4 million. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen Resources. The Company’s working capital needs were also highly influenced by throughput, changes in weather, and timing of payments. Working capital needs at Alagasco were primarily affected by increased gas costs and storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $62.9 million for the three months ended March 31, 2006 primarily due to additions of property, plant and equipment. Energen Resources invested $44.9 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $18.6 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used $104.9 million for financing activities in the year-to-date primarily due to the repayment of short-term borrowings, dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and the direct stock purchase plan as well as the employee benefit plans.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources’ oil and gas operations through the acquisition of producing properties with developmental potential while maintaining the strength of the Company’s utility foundation. For the five years ended December 31, 2005, Energen’s diluted EPS grew at an average compound rate of 19.8 percent a year. Over the long-term, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.

Over the five-year planning period ending December 31, 2010, Energen Resources plans to spend approximately $386 million for development of existing properties and $43 million for exploratory and other activities. In 2006, Energen Resources plans to invest approximately $161 million in capital expenditures primarily for development and exploratory activities. As of December 31, 2005, the estimated amount of 2006 development of previously identified proved undeveloped reserves was approximately $87 million. Approximately $9 million is estimated for 2006 exploratory exposure. Capital investment at Energen Resources in 2007 is expected to approximate $98 million for development and exploration. Of this $98 million, development of previously identified proved undeveloped reserves is estimated to be $71 million and exploratory exposure is estimated to be $6 million.

Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria which could result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years in addition to the estimates given above, for property acquisitions that meet Energen’s acquisition criteria. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment

requirements. To finance Energen Resources’ investment program, the Company expects primarily to utilize its short-term credit facilities to supplement internally generated cash flow. The Company may also periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $245 million, with an additional $140 million in process of renewal, to help finance its growth plans and operating needs. Energen Resources’ continued ability to invest in property acquisitions is subject to market conditions and industry trends.

Energen Resources currently expects production to approximate 92 Bcfe and 89 Bcfe for 2006 and 2007, respectively. The Company’s most recent estimate of production attributable to already owned proved reserves was prepared as of December 31, 2005. Production from proved reserves owned as of December 31, 2005, was estimated as 91 Bcfe and 87 Bcfe for 2006 and 2007, respectively.

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term.

Energen Resources hedges its exposure to estimated commodity 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and 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. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade. At March 31, 2006, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of March 31, 2006. The Company believes the creditworthiness of these counterparties is satisfactory. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions.

Energen Resources has entered into the following transactions for the remainder of 2006 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2006	12.1 Bcf	$8.07 Mcf	NYMEX Swaps
	16.3 Bcf	$6.47 Mcf	Basin Specific Swaps
2007	8.0 Bcf	$9.48 Mcf	NYMEX Swaps
	12.0 Bcf	$8.03 Mcf	Basin Specific Swaps
	*5.0 Bcf	$8.93 Mcf	Basin Specific Swaps
Oil
2006	2,110 MBbl	$52.76 Bbl	NYMEX Swaps
2007	1,200 MBbl	$63.35 Bbl	NYMEX Swaps
	*504 MBbl	$74.45 Bbl	NYMEX Swaps
2008	900 MBbl	$57.71 Bbl	NYMEX Swaps
2009	900 MBbl	$56.25 Bbl	NYMEX Swaps
Oil Basis Differential
2006	1,426 MBbl	**	Basis Swaps
2007	600 MBbl	**	Basis Swaps
	*504 MBbl	**	Basis Swaps
Natural Gas Liquids
2006	22.7 MMGal	$0.56 Gal	Liquids Swaps
2007	10.1 MMGal	$0.80 Gal	Liquids Swaps

*	Contracts entered into subsequent to March 31, 2006

**	Average contract prices are not meaningful due to the varying nature of each contract.

Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors.

The Company’s efforts to minimize commodity price volatility through hedging is reflected in Alagasco’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses. Sustained high prices may decrease Alagasco’s customer base and could result in a decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices.

Alagasco maintains an investment in storage gas that is expected to average approximately $73 million in 2006 but will vary depending upon the price of natural gas. During both 2006 and 2007, Alagasco plans to invest $65 million in utility capital expenditures for normal distribution and support systems. Over the Company’s five-year planning period ending December 31, 2010, Alagasco anticipates capital investments of approximately $325 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In November 2005, Alagasco issued an additional $80 million of long-term debt largely to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by future economic and business conditions and credit rating downgrades.

Dividends

Energen expects to pay annual cash dividends of $0.44 per share on the Company’s common stock in 2006. 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.

On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split.

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. The following table summarizes the Company’s significant contractual cash obligations, other than hedging contracts as of March 31, 2006.


	Payments Due before December 31,
(in thousands)	Total		2006		2007 & 2008		2009 & 2010		2011 & Thereafter
Short-term debt	$	55,000	$	55,000	$	—	$	—	$	—
Long-term debt ⁽¹⁾		699,644		15,000		110,000		150,000		424,644
Interest payments on debt ⁽²⁾		545,464		44,840		81,710		76,177		342,737
Purchase obligations ⁽³⁾		229,725		34,681		95,622		70,218		29,204
Capital lease obligations		—		—		—		—		—
Operating leases		48,738		2,883		6,827		6,322		32,706
Total contractual cash obligations	$	1,578,571	$	152,404	$	294,159	$	302,717	$	829,291

(1) Long-term cash obligations include $1.4 million of unamortized debt discounts as of March 31, 2006.

(2) Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at March 31, 2006.

(3) Certain of the Company’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $230 million through October 2015. The Company 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 168.8 Bcf through April 2015.

Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.

The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2006 for the pension plans and does not currently plan to make discretionary contributions. The Company may reevaluate discretionary payments to its pension plans during 2006. The Company expects to make discretionary payments of $1.5 million to post-retirement benefit program assets during the remainder of 2006.

Forward-Looking Statements

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 forward-looking statements do not reflect the impact of possible or pending acquisitions, 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, our 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.

Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to 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 Alagasco, Energen Resources and/or the Company.

Energen Resources Production: 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 acquisition, development 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.

Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future commodity 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, 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 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.

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. These risks or other risks such as weather events, natural disasters, accidents and criminal acts could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.

Alagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

SELECTED BUSINESS SEGMENT DATA

ENERGEN CORPORATION

(Unaudited)


	Three months ended March 31,
(in thousands, except sales price data)	2006		2005
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	116,084	$	67,600
Oil		42,142		26,305
Natural gas liquids		9,677		8,145
Other		1,616		830
Total	$	169,519	$	102,880

Production volumes from continuing operations
Natural gas (MMcf)		15,327		14,682
Oil (MBbl)		917		819
Natural gas liquids (MMgal)		16.6		15.8
Production volumes from continuing operations (MMcfe)		23,209		21,856
Total production volumes (MMcfe)		23,209		21,906
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	7.57	$	4.60
Oil (barrel)	$	45.94	$	32.12
Natural gas liquids (gallon)	$	0.58	$	0.51
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	7.57	$	5.67
Oil (barrel)	$	45.94	$	32.12
Natural gas liquids (gallon)	$	0.58	$	0.51
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	8.00	$	5.94
Oil (barrel)	$	56.54	$	45.41
Natural gas liquids (gallon)	$	0.71	$	0.65
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$	33,862	$	22,749
Production taxes		13,093		10,204

Total	$	46,955	$	32,953

Depreciation, depletion and amortization	$	23,551	$	21,012
Capital expenditures	$	44,905	$	40,485
Exploration expenditures	$	109	$	324
Operating income	$	88,539	$	38,977
Natural Gas Distribution
Operating revenues
Residential	$	218,506	$	178,154
Commercial and industrial		84,557		65,300
Transportation		12,735		13,029
Other		2,825		1,645

Total	$	318,623	$	258,128

Gas delivery volumes (MMcf)
Residential		11,685		13,013
Commercial and industrial		4,941		5,295
Transportation		13,359		13,741

Total		29,985		32,049

Other data
Depreciation and amortization	$	10,746	$	10,413
Capital expenditures	$	18,845	$	14,802
Operating income	$	63,727	$	66,404

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 under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and 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. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources and Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. 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. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.

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

The Company’s interest rate exposure as of March 31, 2006, was minimal since approximately 85 percent of long-term debt obligations were at fixed rates.

ITEM 4. CONTROLS AND PROCEDURES

(a)

Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

(b)	Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no changes in our internal controls 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 Progams***
January 1, 2006 through January 31, 2006	35,688	$	38.88	—	—
February 1, 2006 through February 28, 2006	19,644	$	36.00	—	—
March 1, 2006 through March 31, 2006	1,650	$	35.87	—	2,150,700
Total	56,982	$	37.80	—	2,150,700

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

***	By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 3,564,400 shares of the Company’s common stock. The resolutions do not have an expiration date.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

a.	At the annual meeting of shareholders held on April 26, 2006, Energen shareholders elected the following Directors to serve for three-year terms expiring in 2009:


Director	Votes cast for	Votes withheld
Judy M. Merritt	59,113,867	1,674,967
Stephen A. Snider	60,211,703	577,131
Gary C. Youngblood	59,714,285	1,074,549

ITEM 6. EXHIBITS

31(a)

- Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)

31(b)

- Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)

32	- Section 906 Certificate pursuant to 18 U.S.C. Section 1350

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 8, 2006	By	/s/ Wm. Michael Warren, Jr.
	Wm. Michael Warren, Jr.
	Chairman and Chief Executive Officer of Energen Corporation, Chairman and Chief Executive Officer of Alabama Gas Corporation

May 8, 2006	By	/s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation

May 8, 2006	By	/s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen Corporation

May 8, 2006	By	/s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas Corporation

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